e20vf

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

(Mark One)


o		Registration statement pursuant to Section 12(b) or 12(g) of the Securities Exchange Act of 1934.


þ		Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

For the fiscal year ended December 31, 2005.


o		Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

For the transition period from to .

Commission file number 001-32000

JED OIL INC.

(Exact Name of Registrant as Specified in Its Charter)

Alberta, Canada
(Jurisdiction of Incorporation or Organization)

Suite 2200, 500 – 4th Avenue S.W.
Calgary, Alberta, Canada
T2P 2V6
(Address of Principal Executive Offices)

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


Title of Each Class		Name of Each Exchange On Which Registered
Common Shares		The American Stock Exchange

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.

Common Shares, without par value at December 31, 2005: 14,630,256

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 þ

If this 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 þ

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 such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

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

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

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

Item 17 o Item 18 þ

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 þ

PART I

Item 1. Identity of Directors, Senior Management and Advisors

Not applicable.

Item 2. Offer Statistics and Expected Timetable

Not applicable.

Item 3. Key Information

Selected Financial Data

The following tables present the Company’s selected consolidated financial data. You should read these tables in conjunction with our audited consolidated financial statements and accompanying notes included in Item 18 of this Form 20-F and the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Item 5 of this Form 20-F.

The financial data as at December 31, 2005, 2004 and 2003 and for the years ended December 31, 2005 and 2004 and for the 120-day period starting from the Company’s inception on September 3, 2003 and ended December 31, 2003 have been derived from, and are qualified in their entirety by reference to, our audited consolidated financial statements, which have been prepared in accordance with United States Generally Accepted Accounting Principals (GAAP).

The following table presents a summary of our consolidated statement of operations derived from our audited financial statements for the years ended December 31, 2005 and 2004 and the 120 day period ended December 31, 2003.

Consolidated statements of operations data:
(In thousands, except per share data)


						120-Day Period
						Ended
	Year Ended December 31,					December 31,
	2005		2004			2003

Petroleum and natural gas, before royalties	$	9,659	$	1,519			—
Net earnings (loss)	$	1,143	$	(8,547	)	$	(360	)
Basic earnings (loss) per share	$	0.08	$	(0.81	)		—
Diluted earnings (loss) per share	$	0.07	$	(0.81	)		—

The following table presents a summary of our consolidated balance sheet as at December 31, 2005, 2004 and 2003.

Consolidated balance sheet data:


*(In Thousands)*	As at December 31,
	2005		2004		2003

Cash and cash equivalents	$	4,451	$	18,657	$	16,089
Accounts receivable and prepaid expenses	$	9,466	$	801	$	212
Due from related parties	$	13,468	$	4,172	$	4,628
Property and equipment	$	48,334	$	5,404		—
Total assets	$	75,719	$	29,034	$	20,929
Total debt	$	48,115	$	5,581	$	64
Total stockholders’ equity	$	27,605	$	23,452	$	20,865
Common shares outstanding		14,630,256		9,500		—
Preferred shares outstanding		—		—		7,600
Dividends paid on preferred shares		—		—		—
Dividends paid on common shares		—		—		—

We publish our consolidated financial statements in United States (“US”) dollars. In this report, except where otherwise indicated, all amounts are stated in US dollars.

Capitalization and Indebtedness

Not applicable.

Reasons for the Offer and Use of Proceeds

Not applicable.

Risk Factors

Set out below are certain risk factors that could materially adversely affect our cash flow, operating results or financial condition. Investors should carefully consider these risk factors before making investment decisions involving our Common Shares.

Our results of operations and financial condition are dependent on the prices received for our oil and natural gas production.

Oil and natural gas prices have fluctuated widely during recent years and are subject to fluctuations in response to relatively minor changes in supply, demand, market uncertainty and other factors that are beyond our control. These factors include, but are not limited to, worldwide political instability, foreign supply of oil and natural gas, the level of consumer product demand, government regulations and taxes, the price and availability of alternative fuels and the overall economic environment. Any decline in crude oil or natural gas prices may have a material adverse effect on our operations, financial condition, borrowing ability, reserves and the level of expenditures for the development of oil and natural gas reserves.

We may use financial derivative instruments and other hedging mechanisms to try to limit a portion of the adverse effects resulting from changes in natural gas and oil commodity prices. To the extent we hedge our commodity price exposure, we forego the benefits we would otherwise experience if commodity prices were to increase. In addition, our commodity hedging activities could expose us to losses. Such losses could occur under various circumstances, including where the other party to a hedge does not perform its obligations under the hedge agreement, the hedge is imperfect or our hedging policies and procedures are not followed. Furthermore, we cannot guarantee that such hedging transactions will fully offset the risks of changes in commodities prices.

In addition, we regularly assess the carrying value of our assets in accordance with U.S. generally accepted accounting principles under the full cost method. If oil and natural gas prices become depressed or decline, the carrying value of our assets could be subject to downward revision.

An increase in operating costs or a decline in our production level could have a material adverse effect on our results of operations and financial condition and, therefore, could affect the market price of the Common Shares.

Higher operating costs for our underlying properties will directly decrease the amount of cash flow received by JED. Electricity, chemicals, supplies, reclamation and abandonment and labour costs are a few of the operating costs that are susceptible to material fluctuation. The level of production from our existing properties may decline at rates greater than anticipated due to unforeseen circumstances, many of which are beyond our control. A significant decline in our production could result in materially lower revenues and cash flow.

A decline in our ability to market our oil and natural gas production could have a material adverse effect on production levels or on the price that we received for our production which, in turn, could affect the market price of our Common Shares.

Our business depends in part upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities. Canadian federal and provincial, as well as United States federal and state, regulation of oil and gas production, processing and transportation, tax and energy policies, general economic conditions, and changes in supply and demand could adversely affect our ability to produce and market oil and natural gas. If market factors change and inhibit the marketing of our production, overall production or realized prices may decline.

Fluctuations in foreign currency exchange rates could adversely affect our business, and could affect the market price of our Common Shares.

The price that we receive for a majority of our oil and natural gas is based on United States dollar denominated benchmarks, and therefore the price that we receive in Canadian dollars is affected by the exchange rate between the two currencies. A material increase in the value of the Canadian dollar relative to the United States dollar may negatively impact net production revenue by decreasing the Canadian dollars received for a given United States dollar price. We could be subject to unfavourable price changes to the extent that we have engaged, or in the future engage, in risk management activities related to foreign exchange rates, through entry into forward foreign exchange contracts or otherwise.

Actual reserves will vary from reserve estimates, and those variations could be material, and affect the market price of our Common Shares.

The reserve and recovery information contained in the independent engineering report prepared by McDaniel & Associates (“McDaniel”) relating to our reserves is only an estimate and the actual production and ultimate reserves from our properties may be greater or less than the estimates prepared by McDaniel.

The value of our Common Shares depends upon, among other things, the reserves attributable to our properties. Estimating reserves is inherently uncertain. Ultimately, actual reserves attributable to our properties will vary from estimates, and those variations may be material. The reserve figures contained herein are only estimates. A number of factors are considered and a number of assumptions are made when estimating reserves. These factors and assumptions include, among others:

	•		historical production in the area compared with production rates from similar producing areas;

	•		future commodity prices, production and development costs, royalties and capital expenditures;

	•		initial production rates;

	•		production decline rates;

	•		ultimate recovery of reserves;

	•		success of future development activities;

	•		marketability of production;

	•		effects of government regulation; and

	•		other government levies that may be imposed over the producing life of reserves.

Reserve estimates are based on the relevant factors, assumptions and prices on the date the relevant evaluations were prepared. Many of these factors are subject to change and are beyond our control. If these factors, assumptions and prices prove to be inaccurate, actual results may vary materially from reserve estimates.

If we expand our operations beyond oil and natural gas production in western Canada and the western United States we may face new challenges and risks.

If we were unsuccessful in managing these challenges and risks, our results of operations and financial condition could be adversely affected, which could affect the market price of our Common Shares.

Our operations and expertise are currently focused on conventional oil and gas production and development in the Western Canadian Sedimentary Basin and the Rocky Mountain states of the U.S. In the future, we may acquire oil and gas properties outside of this geographic area. In addition, JED could acquire other energy related assets, such as oil and natural gas processing plants or pipelines. Expansion of our activities into new areas may present challenges and risks that we have not faced in the past. If we do not manage these challenges and risks successfully, our results of operations and financial condition could be adversely affected.

In determining the purchase price of acquisitions, we rely on both internal and external assessments relating to estimates of reserves that may prove to be materially inaccurate. Such reliance could adversely affect the market price of our Common Shares.

The price we are willing to pay for reserve acquisitions is based largely on estimates of the reserves to be acquired. Actual reserves could vary materially from these estimates. Consequently, the reserves we acquire may be less than expected, which could adversely impact cash flows. An initial assessment of an acquisition may be based on a report by engineers or firms of engineers that have different evaluation methods and approaches than those of our engineers, and these initial assessments may differ significantly from our subsequent assessments.

Some of our properties are not operated by us and, therefore, results of operations may be adversely affected by the failure of third-party operators, which could affect the market price of our Common Shares.

The continuing production from a property, and to some extent the marketing of that production, is dependent upon the ability of the operators of those properties. At December 31, 2005, approximately 89% of our daily production was from properties operated by third parties. To the extent a third-party operator fails to perform its functions efficiently or becomes insolvent, our revenue may be reduced. Third party operators also make estimates of future capital expenditures more difficult.

Further, the operating agreements which govern the properties not operated by us typically require the operator to conduct operations in a good and “workmanlike” manner. These operating agreements generally provide, however, that the operator has no liability to the other non-operating working interest owners for losses sustained or liabilities incurred, except for liabilities that may result from gross negligence or wilful misconduct.

Delays in business operations could adversely affect the market price of our Common Shares.

In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of our properties, and the delays of those operators in remitting payment to us, payments between any of these parties may also be delayed by:

	•		restrictions imposed by lenders;

	•		accounting delays;

	•		delays in the sale or delivery of products;

	•		delays in the connection of wells to a gathering system;

	•		blowouts or other accidents;

	•		adjustments for prior periods;

	•		recovery by the operator of expenses incurred in the operation of the properties; or

	•		the establishment by the operator of reserves for these expenses.

Any of these delays could expose us to additional third party credit risks.

We may, from time to time, finance a significant portion of our operations through debt. Our indebtedness could affect the market price of our Common Shares.

Variations in interest rates and scheduled principal repayments could result in significant changes to the amount of the cash flow required to be applied to debt. The agreements governing our credit facility provide that if we are in default under the credit facility, exceed certain borrowing thresholds or fail to comply with certain covenants, we must repay the indebtedness at an accelerated rate.

Our lenders have been provided with a security interest in substantially all of our assets. If we are unable to pay the debt service charges or otherwise commit an event of default, such as bankruptcy, our lenders may foreclose on and sell the properties. The proceeds of any sale would be applied to satisfy amounts owed to the creditors. Only after the proceeds of that sale were applied towards the debt would the remainder, if any, be available for distribution to Shareholders.

Our current credit facility and any replacement credit facility may not provide sufficient liquidity.

The amounts available under our existing credit facility may not be sufficient for future operations, or we may not be able to obtain additional financing on economic terms attractive to us, if at all.

The oil and natural gas industry is highly competitive.

We compete for capital, acquisitions of reserves, undeveloped lands, skilled personnel, access to drilling rigs, service rigs and other equipment, access to processing facilities, pipeline and refining capacity and in many other respects with a substantial number of other organizations, many of which may have greater technical and financial resources than we do. Some of these organizations not only explore for, develop and produce oil and natural gas but also carry on refining operations and market oil and other products on a worldwide basis. As a result of these complementary activities, some of our competitors may have greater and more diverse competitive resources to draw on than we do. Given the highly competitive nature of the oil and natural gas industry, this could adversely affect the market price of our Common Shares.

The industry in which we operate exposes us to potential liabilities that may not be covered by insurance.

Our operations are subject to all of the risks associated with the operation and development of oil and natural gas properties, including the drilling of oil and natural gas wells, and the production and transportation of oil and natural gas. These risks include encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, equipment failures and other accidents, cratering, sour gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions, pollution, other environmental risks, fires and spills. A number of these risks could result in personal injury, loss of life, or environmental and other damage to our property or the property of others. We cannot fully protect against all of these risks, nor are all of these risks insurable. We may become liable for damages arising from these events against which we cannot insure or against which we may elect not to insure because of high premium costs or other reasons. Any costs incurred to repair these damages or pay these liabilities would reduce funds available for distribution to Shareholders.

The operation of oil and natural gas wells could subject us to environmental claims and liability.

The oil and natural gas industry is subject to extensive environmental regulation pursuant to local, provincial and federal legislation. A breach of that legislation may result in the imposition of fines or the issuance of “clean up” orders. Legislation regulating the oil and natural gas industry may be changed to impose higher standards and potentially more costly obligations. For example, the 1997 Kyoto Protocol to the United Nation’s Framework Convention on Climate Change, known as the Kyoto Protocol, was ratified by the Canadian government in December, 2002 and will require, among other things, significant reductions in greenhouse gases. The impact of the Kyoto Protocol on us is uncertain and may result in significant future additional costs for our operations. Although we record a provision in our financial statements relating to our estimated future environmental and reclamation obligations, we cannot guarantee that we will be able to satisfy our actual future environmental and reclamation obligations.

We are not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not available on economically reasonable terms.

Accordingly, our properties may be subject to liability due to hazards that cannot be insured against, or that have not been insured against due to prohibitive premium costs or for other reasons. Any site reclamation or abandonment costs actually incurred in the ordinary course of business in a specific period will be funded out of cash flow and, therefore, will reduce the amounts available for distribution to Shareholders. Should we be unable to fully fund the cost of remedying an environmental problem, we might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy.

Lower crude oil and natural gas prices increase the risk of ceiling limitation write-downs. Any write-downs could materially affect the value of your investment.

We use the “full cost” method of accounting for petroleum and natural gas properties. All costs related to the exploration for and the development of oil and gas reserves are capitalized into two geographic cost centres representing JED’s activity which are undertaken in Canada and the U.S. Costs capitalized include land acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling productive and non-productive wells. Proceeds from the disposal of properties are applied as a reduction of cost without recognition of a gain or loss except where such disposals would result in a major change in the depletion rate.

Capitalized costs are depleted and depreciated using the unit-of-production method based on the estimated gross proven oil and natural gas reserves before royalties as determined by independent engineers. Units of natural gas are converted into barrels of equivalents on a relative energy content basis. Capitalized costs, net of accumulated depletion and depreciation, are limited to estimated future net revenues from proven reserves, based on year-end prices, undiscounted, less estimated future abandonment and site restoration costs, general and administrative expenses, financing costs and income taxes. Estimated future abandonment and site restoration costs are provided for over the life of proven reserves on a unit-of-production basis. The annual charge is included in depletion and depreciation expense and actual abandonment and site restoration costs are charged to the provision as incurred. The amounts recorded for depletion and depreciation and the provision for future abandonment and site restoration costs are based on estimates of proven reserves and future costs. The recoverable value of capital assets is based on a number of factors including the estimated proven reserves and future costs. By their nature, these estimates are subject to measurement uncertainty and the impact on financial statements of future periods could be material.

We perform a cost recovery ceiling test which limits net capitalized costs to the estimated future net revenue from proven oil and gas reserves plus the cost of unproven properties less impairment, using year-end prices or average prices. Under U.S. GAAP, companies using the “full cost” method of accounting for oil and gas producing activities perform a ceiling test using discounted estimated future net revenue from proven oil and gas reserves with a discount factor of 10%. Prices used in the U.S. GAAP ceiling tests performed for this reconciliation were those in effect at the applicable year-end. Financing and administration costs are excluded from the calculation under U.S. GAAP. At December 31, 2004 JED realized a U.S. GAAP ceiling test write-down of US$4.2 million. There were no such write-downs required at December 31, 2005.

The risk that we will be required to write down the carrying value of crude oil and natural gas properties increases when crude oil and natural gas prices are low or volatile. We may experience additional ceiling test write-downs in the future.

Unforeseen title defects may result in a loss of entitlement to production and reserves.

Although we conduct 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 of 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.

Aboriginal Land Claims

The economic impact on us of claims of aboriginal title is unknown. Aboriginal people have claimed aboriginal title and rights to a substantial portion of western Canada. We are unable to assess the effect, if any, that any such claim would have on our business and operations.

Changes in tax and other laws may adversely affect Shareholders.

Income tax laws, other laws or government incentive programs relating to the oil and gas industry may in the future be changed or interpreted in a manner that adversely affects JED and our Shareholders. Tax authorities having jurisdiction over JED or the Shareholders may disagree with the manner in which we calculate our income for tax purposes or could change their administrative practices to our detriment or the detriment of Shareholders.

Income Tax Matters

On October 31, 2003, the Department of Finance (Canada) released, for public comment, proposed amendments to the Tax Act that relate to the deductibility of interest and other expenses for income tax purposes for taxation years commencing after 2004. In general, the proposed amendments were intended to deny the realization of losses in respect of a business if there is no reasonable expectation that the business will produce a cumulative profit over the period that the business can reasonably be expected to be carried on. Although the 2005 Canadian federal budget stated that the October 31, 2003 amendments will not be enacted, it stated that a “more modest legislative initiative” would be developed to address losses realized where there is no reasonable expectation of profit from the relevant activity. Accordingly, there is a possibility that legislation may be enacted which could restrict or deny losses in a manner which could adversely affect JED. However, JED believes that it is reasonable to expect JED and each subsidiary entity to produce a cumulative profit over the expected period that the business will be carried on.

Expenses incurred by JED are only deductible to the extent they are reasonable. Although JED is of the view that all expenses to be claimed by JED and its subsidiary entities should be reasonable and deductible, there can be no assurance that the Canadian Revenue Agency (“CRA”) will agree. If the CRA were to successfully challenge the deductibility of such expenses, the net revenue to JED may be adversely affected.

Changes in market-based factors may adversely affect the trading price of our Common Shares.

The market price of our Common Shares is primarily a function of the value of our properties. The market price of our Common Shares is therefore sensitive to a variety of market based factors, including, but not limited to, interest rates and the comparability of our Common Shares to other securities. Any changes in these market-based factors may adversely affect the trading price of the Common Shares.

Our operations are entirely independent from the Shareholders and loss of key management and other personnel could impact our business.

Shareholders are entirely dependent on the management of JED with respect to the acquisition of oil and gas properties and assets, the development and acquisition of additional reserves and the management and administration of all matters relating to our oil and natural gas properties. The loss of the services of key individuals

who currently comprise the management team could have a detrimental effect on JED. Investors should carefully consider whether they are willing to rely on the existing management before investing in the Common Shares.

There may be future dilution.

One of our objectives is to continually add to our reserves through acquisitions and through development. Our success is, in part, dependent on our ability to raise capital from time to time by selling additional Common Shares. Shareholders will suffer dilution as a result of these offerings if, for example, the cash flow, production or reserves from the acquired assets do not reflect the additional number of Common Shares issued to acquire those assets. Shareholders may also suffer dilution in connection with future issuances of Common Shares to effect acquisitions.

There may not always be an active trading market for the Common Shares.

While there is currently an active trading market for our Common Shares in the United States and Canada, we cannot guarantee that an active trading market will be sustained.

We may undertake acquisitions that could limit our ability to manage and maintain our business, result in adverse accounting treatment and are difficult to integrate into our business. Any of these events could result in a material change in our liquidity, impair our ability to pay dividends and could adversely affect the value of your investment.

A component of future growth will depend on the ability to identify, negotiate, and acquire additional companies and assets that complement or expand existing operations. However we may be unable to complete any acquisitions, or any acquisitions we may complete may not enhance our business. Any acquisitions could subject us to a number of risks, including:

	•		diversion of management’s attention;

	•		inability to retain the management, key personnel and other employees of the acquired business;

	•		inability to establish uniform standards, controls, procedures and policies;

	•		inability to retain the acquired company’s customers;

	•		exposure to legal claims for activities of the acquired business prior to acquisition; and

	•		inability to integrate the acquired company and its employees into our organization effectively.

Item 4. Information on the Company

History and development of the Company

JED Oil Inc. is an independent energy corporation that was incorporated under the laws of the Province of Alberta, Canada on September 3, 2003. Our head and principal office is located at 2200, 500 – 4th Avenue S.W., Calgary, Alberta, T2P 2V6. Our office telephone number is (403) 537-3250. JED owns 100% of JED Oil (USA) Inc., which was incorporated under the laws of the state of Wyoming on May 5, 2004.

Olympia Trust Company, Calgary, Alberta is our registered transfer agent. The principal and head office of Olympia Trust Company is located at 2300, 125 9^th Avenue S.E., Calgary, Alberta T2G 0P6.

In January 2004, we entered into a Farm-in/Joint Venture Agreement with Enterra Energy Trust (“Enterra”) for development of several properties in Central Alberta. Under the terms of the agreement, we pay 100% of the capital costs to earn a 70% working interest in these projects.

On March 31, 2004 we ended our development stage and commenced production. The first day of production occurred in the month of April 2004.

On August 12, 2004, we acquired 250,000 common shares of JMG Exploration, Inc. (“JMG”) (representing an approximate 11% equity interest in the total voting share capital of JMG at that time) for cash consideration of $1,000,000.

On October 21, 2004, we entered into a Farm-in Agreement with Enterra whereby we will develop certain projects related to the properties recently acquired by Enterra through the corporate acquisition of Rocky Mountain Energy Corp. Under the terms of the agreement, we pay 100% of the capital costs to earn a 65% working interest in these projects. The first phase of the development program commenced in November 2004.

Capital Expenditures

Since the inception of the Company in September 2003, we have invested $67.1 million in capital expenditures to drill wells and construct pipelines and facilities to transport and process our production volumes. A breakdown of the capital expended during this period is as follows:


	Amount Spent From Inception to
Expenditure Type	December 31, 2005

Petroleum and Natural Gas Properties	$	66,538,907
Other	$	529,424


Total Capital Expenditures	$	67,068,331

Capital Commitments

During the three months ending March 31, 2006 JED has capital expenditures of $30.0 million. For the year 2006 we expect to incur $80 million in capital expenditures. The capital program will be funded from cash flow, debt and possibly equity financing. We expect to spend the entire capital program in Canada and the Untied States.

Business Overview

JED is engaged in the development and operation of crude oil and natural gas in Western Canada and under its wholly owned subsidiary JED Oil (USA) Inc. in the Rocky Mountain states of the United States. We develop the oil and natural gas properties of others under arrangements in which we will finance the cost of development drilling in exchange for interests in the oil and natural gas revenue generated by the properties. It is anticipated that the majority of drilling opportunities will be the farm-outs from Enterra and its operating subsidiaries. Occasionally JED may purchase specific properties in the drilling upside. Our production averaged 1,250 boe/d during the first quarter of 2006 including 587 bbls/d of medium and heavy oil and 3,978 mcf/d of natural gas. Our proved reserves are approximately 3,390.2 mboe in the aggregate as of December 31, 2005. Our growth will come mainly from the development and exploitation of the undeveloped acreage owned by Enterra. These development programs will be financed in part by cash flow, and in part with debt or equity financing.

Business Strategy

JED’s business strategy is to grow its reserves and cash flow by funding the development of oil and gas properties in exchange for an interest in the property. JED is focused on per share growth. We will finance acquisitions with debt and cash flow, and minimize shareholders’ dilution while maintaining a strong balance sheet. JED’s ability to replace and grow its reserves over time is the key success factor in our business strategy.

A majority of our officers and employees were previously employed by Enterra and are familiar with its management and operating philosophies. We anticipate that a majority of our development activities for the near future will be through farm-in or other arrangements with Enterra. We have no contractual or other restrictions with Enterra that prevents us from developing oil and natural gas projects with others.

Relationship with Enterra Energy Trust

Effective January 1, 2004, JED and Enterra entered into a Technical Services Agreement, which provides for services required to manage Enterra’s field operations and governs the allocation of general and administrative expenses between the two entities. Under the Technical Services Agreement, JED and Enterra allocate the costs of management, development, exploitation, operations and general and administrative activities on the basis of production and capital expenditures, or as otherwise agreed to between JED and Enterra. The Technical Services Agreement was terminated in January 2006.

JED, Enterra and JMG are parties to a 2^nd Amended and Restated Agreement of Business Principles pursuant to which each oil and gas property which is owned by Enterra is as a general matter to be developed or explored under arrangements pursuant to which JED and JMG, respectively, bear the cost thereof in exchange for a percentage (usually 70 percent) of such property and Enterra retains the balance of such property. Enterra has a first right to purchase oil and gas properties owned by JED prior to the sale thereof to others, and Enterra has the right to purchase 80 percent of any oil and gas property that is owned by JMG when drilling has established the existence of commercially viable quantities of oil or gas at a value that is based upon an independent engineering report.

Revenues

JED’s revenue is principally from the sale of oil and natural gas liquids and natural gas. For the year ended December 31, 2005, approximately 31% of the revenue from our properties was derived from natural gas and approximately 69% was derived from crude oil and natural gas liquids. JED has also earned interest revenue from the investment of excess cash in interest-earning investments. The summary of revenues by revenue type for the years ended December 31, 2005 and 2004 and for the 120-day period starting from the Company’s incorporation on September 3, 2003 and ended December 31, 2003 is as follows:


					120-Day
					Period Ended
	Year Ended December 31,				December 31,
	2005		2004		2003

Revenue
Oil and natural gas liquids	$	6,705,384	$	1,413,044
Natural gas	$	2,953,406	$	106,045
Interest	$	604,592	$	484,137	$	49,485

Total Revenue	$	10,263,382	$	2,003,226	$	49,485

Employees

At December 31, 2005, we had approximately 30 employees and consultants working both in our head office and in field locations.

Office Facilities

JED shares office space with Enterra who currently leases 31,242 square feet of office space at Suite 2200, 500 — 4th Avenue S.W. in Calgary, Alberta in a lease that commenced January 1, 2005. The lease has a six-year term (expiring on January 31, 2011) and the annual rental is currently C$22.00 per square foot (excluding operating costs and property taxes). JED has no formal lease arrangements in place. JED’s share of the office lease costs are allocated based on the square footage of Suite 2200 which has 10,315 square feet of rentable area.

Competition

The petroleum industry is highly competitive. JED competes with numerous other participants in the acquisition of oil and gas leases and properties, and the recruitment of employees. Any company can make acquisitions and bid on provincial leases in Alberta. Competitors include oil companies and income trusts, many of who have greater financial resources, staff and facilities than those of JED. Our ability to increase reserves in the future will depend not only on our ability to develop existing properties, but also on our ability to select and acquire suitable additional

producing properties or prospects for drilling. We also compete with numerous other companies in the marketing of oil. Competitive factors in the distribution and marketing of oil include price and methods and reliability of delivery.

Government Regulation in Canada

The oil and natural gas industry is subject to extensive controls and regulations governing its operations, including land tenure, exploration, development, production, refining, transportation and marketing, imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta and British Columbia, all of which should be carefully considered by investors in the Canadian oil and gas industry. It is not expected that any of these controls or regulations will affect the operations of JED in a manner materially different from how they would affect other oil and gas companies of similar size operating in Western Canada. All current legislation is a matter of public record and JED is unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry.

Pricing and Marketing — Oil and Natural Gas

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Such price depends in part on oil quality, prices of competing oils, distance to market, the value of refined products and the supply/demand balance. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada, or NEB. Any oil export to be made pursuant to a contract of longer duration, to a maximum of 25 years, requires an exporter to obtain an export license from the NEB and the issuance of such license requires the approval of the Governor in Council. In addition, the prorationing of capacity on the interprovincial pipeline systems continues to limit oil exports.

The price of natural gas is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices with purchasers, provided that the export contracts meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas exports for a term of less than two years or for a term of two to twenty years, in quantities of not more than 30,000 m³/day, must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration, up to a maximum of 25 years, or a larger quantity, requires an exporter to obtain an export license from the NEB and the issuance of such license requires the approval of the Governor in Council.

The governments of British Columbia and Alberta also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere based on such factors as reserve ability, transportation arrangements and market considerations.

Provincial Royalties and Incentives

In addition to federal regulation, each province has legislation and regulations, which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur 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, although production from such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by governmental 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 governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry.

In the Province of Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to the Crown by virtue of the Alberta Royalty Tax Credit or, ARTC program. The ARTC rate is based on a price sensitive formula and the ARTC rate varies between 75% at prices at and below $100 per thousand cubic metres and 25% at prices at and above $210 per thousand cubic metres. The ARTC rate is applied to a maximum of Cdn$2,000,000 of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from a corporation claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The rate will be established quarterly based on the average “par price”, as determined by the Alberta Department of Energy for the previous quarterly period.

On December 22, 1997, the Alberta government announced that it was conducting a review of the ARTC program with the objective of setting out better-targeted objectives for a smaller program and to deal with administrative difficulties. On August 30, 1999, the Alberta government announced that it would not be reducing the size of the program but that it would introduce new rules to reduce the number of persons who qualify for the program. The new rules will preclude companies that pay less than Cdn$10,000 in royalties per year and non-corporate entities from qualifying for the program. Such rules will not presently preclude JED from being eligible for the ARTC program.

Crude oil and natural gas royalty holidays for specific wells and royalty reductions reduce the amount of Crown royalties paid by JED to the provincial governments. In general, the ARTC program provides a rebate on Alberta Crown royalties paid in respect of eligible producing properties.

The North American Free Trade Agreement

On January 1, 1994, the North American Free Trade Agreement (“NAFTA”) among the governments of Canada, the U.S. and Mexico became effective. The NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the U.S. 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; and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements.

The NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The 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.

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, licenses 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.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage and the imposition of material fines and penalties.

Environmental legislation in the Province of Alberta has been consolidated into the Environmental Protection and Enhancement Act, or EPEA, which came into force on September 1, 1993. The EPEA imposes stricter environmental standards, requires more stringent compliance, reporting and monitoring obligations and significantly increases penalties for violations. JED is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment and will be taking such steps as required to ensure compliance with the EPEA and similar legislation in other jurisdictions in which it operates. JED believes that it is in material compliance with applicable environmental laws and regulations. JED also believes that it is reasonably likely that the trend towards stricter standards in environmental legislation and regulation will continue.

The Kyoto Protocol came into force on February 16, 2005. Canada ratified the Kyoto Protocol in December 2002. In 1997, Canada committed to an emission reduction of 6% below 1990 levels during the First Commitment period (2008 to 2012). Until an implementation plan is developed it is impossible to assess the impact on specific industries and individual businesses within an industry. It is generally believed that the oil and gas industry, as a major producer of carbon dioxide, will bear a disproportionately large share of the anticipated cost of implementation. Any required reductions in the greenhouse gases emitted from our operations could result in increases in our capital expenditures and operating expenses, which could have an adverse effect on our results of operations and financial condition.

Organizational Structure

JED Oil Inc. is an independent energy corporation that was incorporated under the laws of the Province of Alberta, Canada on September 3, 2003. Our head and principal office is located at 2200, 500 – 4th Avenue S.W., Calgary, Alberta, T2P 2V6. JED owns 100% of JED Oil (USA) Inc., which was incorporated under the laws of the state of Wyoming on May 5, 2004.

Property, Plant and Equipment

JED Oil Inc.’s core areas include Ferrier and Ricinus, both in west central Alberta, Sousa, in northern Alberta, Desan in northeast British Columbia and through our U.S. subsidiary JED Oil (USA) Inc., the Midale play in North Dakota. JED has created a significant inventory of prospects in these areas mostly through existing farm-in opportunities, the development of these prospects could significantly increase the size of JED’s existing production and reserve base.

Desan

JED’s Desan property is located 210 miles north of the city of Fort St John in northeast British Columbia. The target is natural gas in the Upper Devonian Jean Marie Formation which is being developed using underbalanced horizontal drilling technology. Drilling access for the Desan area is only possible in the winter months between December and March.

JED has obtained a farm-in on 43,320 acres of land in this area whereby we will be paying 100% to earn a 70% working interest in ach spacing unit drilled. In Q4, 2005 and Q1, 2006 JED drilled 6 wells with a success rate of 83%. These wells are now on production producing net to JED 230 boe/d as of April 2006.

Peggo

The Peggo property is located east of Desan on the British Columbia/Alberta border. Here JED has the option to farm-in on 15 sections of undeveloped land, again with potential to drill horizontal wells into the Jean Marie Formation. This is winter access only and drilling is scheduled to commence in late Q4, 2006 or early Q1, 2007.

Ferrier

The Ferrier property is located 85 miles southwest of the City of Edmonton, Alberta. On this property JED has the option to earn a 70% working interest per spacing unit by paying 100% of the drilling costs. 35,877 acres of land are

available for farm-in in this area. In Q4, 2005 JED drilled 9 wells (6.3 net) with 100% success encountering gas in the liquids rich Ellerslie and Rock Creek Formations. In Q1, 2006 JED drilled an additional 6 wells (3.8 net), again with 100% success for a total of 15 (10.1 net). A 10 mmcf/d compression facility is being constructed, all of which should be on production by the end of March, 2006. JED has the potential to drill 5 additional wells on this acreage without further downspacing and another 22 wells with further downspacing. Four sections of land were purchased at a recent Alberta Crown land sale with up to 12 additional wells that can be drilled on these lands. Expected initial production rates from these wells should be between 500 mcf/d and 4 mmcf/d.

Ricinus

The Ricinus property is located just south of the town of Caroline, Alberta. The target is the liquid rich Cardium Formation. JED has earned an average working interest of 47% in 3,840 gross acres of land. In 2005 JED drilled and completed 6 wells and participated in 1 for a total of 7 (2.8net). Five wells will be tied-in and on production by the end of March, 2006. Currently there are no further development plans for this property. Production rates on these wells should average 400 mcf/d.

Cummings “Y” Unit

The Cummings “Y” Unit is located within the area known as Provost, Alberta, southwest of the town of Provost. The target is the Cummings Formation. JED has an average working interest of 32.7% over 340 gross acres (111.2 net acres) of land. JED drilled and completed 15 wells in the Cummings “Y” Unit over the past year. In order to optimize oil recovery 2 water injector wells were drilled and 1 older oil well was converted into a water injector to restore pressure to the field. This increased production from 90 BOE/d to 140 BOE/d net to JED. Total proved reserves assigned are 221.6 mbbl of oil. Currently there are no further development plans.

North Dakota, USA

JED’s North Dakota properties are located in the northwestern corner of the state near the United States/Canadian border in Divide County (162N-164N, 94W-97W). In 2005 JED focused on two targets in the area: the Lower Mississippian Bakken sandstone averaging 10’ in thickness and the Upper Mississippian Midale carbonates averaging 5’ in thickness. Both horizons have been targeted with horizontal drilling with the Bakken requiring large fracture stimulations. This area has year round drilling access.

JED’s activity in the area is in partnership with JMG Exploration, Inc. whereby JED’s subsidiary JED Oil (USA) Inc. farms-in on JMG to earn the right to 8 sections surrounding the initial exploratory discovery drilled by JMG. JED will pay 100% to earn a 70% working interest in each spacing unit to depth drilled. JED has the potential to earn an interest in 59,000 gross acres of land acquired by JMG in this area.

JED drilled 1 Bakken horizontal well in 2005 at Buck 3-8H offsetting an exploratory discovery well drilled by JMG. The Buck well was put on production in January, 2006. JED’s Bakken play is a northern extension of major, established Bakken production further south in North Dakota.

JED started drilling the Midale play in early 2006 as a follow up to an offsetting exploratory Midale horizontal well drilled by JMG in late 2005 (Schutz 5-26H) and subsequently put on production as an oil producer. To the middle of March, 2006 JED has drilled 2 more Midale horizontal wells (Erickson 1-27H and Kearney 4-25H). Completion and evaluation of these wells is in the early stages but combined with the encouraging results observed at the Schutz well further development is certainly warranted. JED plans to drill these horizontal wells on a 2 wells per section basis with the option of eventual downspacing to 4 wells per section. The Midale play is a southern extension of the emerging Midale field in Tableland, Saskatchewan to the north where one vertical offset Midale produced 166 mstb of 30⁰ API oil. JED has the potential to drill 16 wells in North Dakota in 2006. Expected initial production rates should be between 100 and 200 BOPD from the Midale.

Reserves and Present Value Summary

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known

reservoirs under existing economic and operating conditions. Reserve estimates are considered proved if economical productibility is supported by either actual production or conclusive formation tests. Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program in the reservoir provides support for the engineering analysis on which the project or program is based. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods.

JED emphasizes that its reported reserves are estimates which, by their nature, are subject to revision. The estimates are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed annually, and revised either upward or downward, as warranted by additional performance data.

In this Form 20-F, certain natural gas volumes have been converted to barrels of oil equivalent (“BOEs’’) on the basis of six thousand cubic feet (“Mcf’’) to one barrel (“bbl’’). BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of six Mcf to one bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent equivalency at the wellhead.

JED has its reserves evaluated by independent engineers every year. McDaniel independently evaluated the JED’s reserves at December 31, 2005. These recovery and reserve estimates of JED’s interest in the described properties are estimates only; the actual in the properties in which we have an interest may be more or less than those calculated. The extent and character of the material information supplied by JED including, but not limited to, ownership, well data, production, price, revenues, operating costs and contracts were relied upon by McDaniel in preparing the report. In the absence of such information, McDaniel relied upon their opinion of reasonable practice in the industry. The McDaniel report may be examined at the office of JED located at Suite 2200, 500 – 4^th Avenue S.W., Calgary, Alberta, T2P 2V6, during normal business hours.

Reserve Quantity Information

Estimated quantities of proved oil (including natural gas liquids) and natural gas reserves at December 31, 2005, 2004 and 2003 and changes in the reserves during those years, are shown in the following two tables:


	2005			2004			2003

Proved developed and undeveloped reserves – Oil (mboe)
At January 1		446.4			—			—
Extensions, discoveries and other additions		732.7			480.7			—
Production		(138.6	)		(34.3	)		—


At December 31		1,040.5			446.4			—


Proved developed reserves – Oil (mboe)
At January 1		400.4			—			—
At December 31		767.8			400.4			—


	2005			2004			2003

Proved developed and undeveloped reserves – Gas (mboe)
At January 1		55.2			—			—
Extensions, discoveries and other additions		2,347.0			58			—
Production		(52.5	)		(2.8	)		—


At December 31		2,349.7			55.2			—


Proved developed reserves – Gas (mboe)
At January 1		43.0			—			—
At December 31		1,018.3			43.0			—

Proved developed reserves are defined as reserves that can be expected to be recovered through existing wells with existing facilities and operating methods.

Proved undeveloped reserves are defined as reserves that can be expected to be recovered through the drilling of additional wells and building of additional facilities.

Total proved reserves increased to 3,390 mboe from 502 mboe at the end of 2004. Total proved reserves represent 65% (2004-76%) of total reserves.

Land Holdings

At December 31, 2005, 2004 and 2003, JED had the following land holdings, all of which are in Canada:


	2005				2004				2003
	gross		net		gross		net

Developed acres		23,352		16,622		2,177		1,504		—
Undeveloped acres		4,160		3,570		—		—		—

Total acres		27,512		20,192		2,177		1,504		—

Production

The following table summarizes JED’s working interest production, net before royalties, during the periods indicated:


	Years ended December 31,
	2005		2004		2003

Oil and NGL’s (mbbl)		167.2		42.6		—
Gas (mmcf)		379.6		20.7		—
Total (mboe)		230.3		46.0		—
Average production in boed		631.0		168.0		—

The average production for 2004 was for the period from the commencement of field operations on April 1, 2004 to December 31, 2004.

Definitions:


“boed”		means barrels of oil equivalent produced per day.

“mboe”		means thousands of barrels of oil equivalent, meaning one barrel of oil or one barrel of natural gas liquids or six mcf of natural gas.

“mbbl”		means thousands of barrels, with respect to production of crude oil or natural gas liquids.

“mmcf”		means millions of cubic feet, with respect to production of natural gas.

“NGL’s”		means natural gas liquids, being those hydrocarbon components recovered from raw natural gas as liquids by processing through extraction plants or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane, butanes and pentanes plus, or a combination thereof.

Average Sales Prices


	Year Ended December 31,
	2005		2004		2003

Oil, per barrel	$	40.11	$	33.28	$	—
Natural Gas, per mcf	$	7.78	$	5.09	$	—

Average Production Costs


	Year Ended December 31,
	2005		2004		2003

Per BOE	$	6.14	$	5.27	$	—

Drilling

JED’s drilling history is as follows:


	2005			2004			2003
Wells drilled	Gross (Net)			Gross (Net)			Gross (Net)

Oil		31 (12.6	)		22 (10.4	)		—(-	)
Natural Gas		43 (31.0	)		2 (1.0	)		—(-	)
Injection and water disposal		0 (0	)		0 (0.0	)		—(-	)
Abandoned		6 (3.2	)		3 (1.0	)		—(-	)

Total		80 (46.8	)		27 (12.4	)		—(-	)

JED commenced commercial operations in April 2004. There were no wells were drilled in 2003.

Notes:

(1)		“Gross” wells mean the number of whole wells.

(2)		“Net” wells means JED’s working interest in the gross wells.

Oil and Gas Wells

The following table summarizes JED’s interest in producing and non-producing oil and gas wells as at December 31, 2005:

Oil Wells

Gas Wells

Non Producing

Grand Total

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Canada

23.0

32.0

55.0

Item 5. Operating and Financial Review and Prospects

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following management discussion and analysis is as of March 19, 2006 and should be read in conjunction with the audited consolidated financial statements of JED Oil Inc. (“JED”) for the years ended December 31, 2005 and 2004, together with accompanying notes. Additional information relating to the Company, including the Company’s Annual Information Form (“AIF”), can be found on the SEDAR website at www.sedar.com.

Discussion with regard to the JED’s 2005 outlook is based on currently available information. All amounts are stated in United States dollars except where otherwise indicated. The financial data presented below has been prepared in accordance with United States generally accepted accounting principles (GAAP). The reporting currency is the United States dollar and the functional currency is the Canadian dollar.

This MD&A contains the terms funds from operations and funds from operations per share. Funds from operations, as used by the Company, is before changes in operating assets and liabilities. Funds from operations and funds from operations per share, as presented, are not defined by generally accepted accounting principals (GAAP) and therefore are referred to as non-GAAP measures. These non-GAAP measures may not be comparable to the calculation of similar measures for other entities.

The term barrels of oil equivalent (BOE) may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 thousand cubic feet (mcf) equals 1 barrel (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. All BOE conversion in this report are derived by converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This annual report includes forward looking statements. All statements other than statements of historical facts contained in this annual report, including statements regarding our future financial position, business strategy and plans and objectives of management for future operations, are forward-looking statements. The words “believe,” “may,” “will,” “estimate,” “continue,” “anticipate,” “intend,” “should,” “plan,” “expect” and similar expressions, as they relate to us, are intended to identify forward-looking statements. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends that we believe may affect our financial condition, results of operations, business strategy and financial needs. These forward-looking statements are subject to a number of risks, uncertainties and assumptions described elsewhere in this annual report.

Other sections of this annual report may include additional factors, which could adversely affect our business and financial performance. Moreover, we operate in a very competitive and rapidly changing environment. New risk factors emerge from time to time and it is not possible for our management to predict all risk factors, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause the Company’s actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements.

We undertake no obligation to update publicly or revise any forward-looking statements. Furthermore, the forward-looking statements contained in this annual report are made as of the date of this report, and we undertake no obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements in this annual report are expressly qualified by this cautionary statement.

SELECTED ANNUAL INFORMATION
(in thousands, except per share data)


	2005			2004			2003

Revenue, before royalties	$	9,659		$	1,519			—
Funds from operations ⁽³⁾	$	5,224		$	(1,276	)	$	(49	)
Funds from operations per share – basic ^(1)(2)(3)	$	0.36		$	(0.12	)		—
Funds from operations per share – diluted ^(1)(2)(3)	$	0.34		$	(0.11	)		—
Net income (loss)	$	1,143		$	(8,547	)	$	(360	)
Net income (loss) per share – basic ⁽¹⁾⁽²⁾	$	0.08		$	(0.81	)		—
Net income (loss) per share – diluted ⁽¹⁾⁽²⁾	$	0.07		$	(0.81	)		—
Capital expenditures	$	43,708		$	10,353			—
Working capital (deficiency)	$	(3,616	)	$	18,303		$	20,865
Total assets	$	75,719		$	29,034		$	20,929
Total long-term liabilities	$	21,401		$	255			—
Production (BOE/d)		631			126			—


(1)		Per share information and weighted average shares outstanding have been adjusted to reflect the 3-for-2 stock split that occurred on October 12, 2005. 2004 comparative numbers have been adjusted to reflect the stock split as if it occurred from the date of incorporation.

(2)		At December 31, 2003, the Company only had Series A Preferred Shares issued and outstanding and no common shares outstanding. Accordingly the preferred shares were excluded from the loss per share calculation resulting in a no loss per share for basic and diluted shares.

(3)		Funds from operation and funds from operations per share are non-GAAP measures and may not be comparable to the calculation of similar measures for other entities.

OPERATIONS SUMMARY
(in thousands, except percentages and per share data)


	2005									2004
	$			$/BOE			%			$			$/BOE			%

Petroleum and natural gas revenue	$	9,659		$	41.93			94.1		$	1,519		$	33.01			75.8
Interest	$	605		$	2.62			5.9		$	484		$	10.52			24.2

Total revenue	$	10,264		$	44.55			100.0		$	2,003		$	43.53			100.0
Royalties, net of ARTC	$	1,654		$	7.18			16.2		$	296		$	6.43			14.8
Production costs	$	1,415		$	6.14			13.8		$	243		$	5.27			12.1

Field netback ⁽¹⁾	$	7,195		$	31.23			70.0		$	1,464		$	31.83			73.1
General and administrative	$	1,125		$	4.88			11.0		$	2,740		$	59.54			136.8
Interest on convertible note	$	846		$	3.67			8.2			—			—			—

Funds from operations ⁽¹⁾	$	5,224		$	22.68			50.8		$	(1,276	)	$	(27.71	)		(63.7	)
Stock based compensation	$	1,078		$	4.68			10.5		$	224		$	4.86			11.2
Depletion, depreciation and accretion	$	3,503		$	15.21			34.1		$	4,958		$	107.73			247.5
Foreign exchange (gain) loss	$	(500	)	$	(2.17	)		(4.9	)	$	1,089		$	23.66			54.4
Loss on equity investment		—			—			—		$	1,000		$	21.73			49.9

Net income (loss)	$	1,143		$	4.96			11.1		$	(8,547	)	$	(185.69	)		(426.7	)


(1)		Both field netback and funds from operations are non-GAAP measures and may not be comparable to the calculation of similar measures for other entities. Field netback is defined as total revenues less field related costs including royalties, net of ARTC, and production costs.

PRODUCTION AND REVENUE
(in thousands except for percentages, volumes and per unit amounts)


	2005		2004		*Change*

Production
Crude oil and natural gas liquids (bbl/d)		458		117		291	%
Natural gas (mcf/d)		1,040		57		1,725	%

Oil equivalent (BOE/d)		631		126		401	%


Production Revenue
Crude oil and natural gas liquids	$	6,705	$	1,413		375	%
Natural gas (mcf/d)	$	2,954	$	106		2,686	%

Production revenue	$	9,659	$	1,519		536	%


Average Prices
Crude oil and natural gas liquids ($/bbl)	$	40.11	$	33.28		21	%
Natural gas ($/mcf)	$	7.78	$	5.09		53	%

Oil equivalent ($/BOE)	$	41.92	$	33.07		27	%

Petroleum and natural gas revenue increased 536% to $9.7 million in 2005 due to increased production and commodity pricing. Production volumes increased by 401% over the prior year to average 631 BOE in 2005 compared with the average of 126 BOE in 2004. Commodity price increases of 27% further contributed to the significant revenue growth.

The Company’s activities in 2005 concentrated on the development of the properties under the farm-in agreement with Enterra Energy Trust (“Enterra”) and the development of the Sousa area in Northern Alberta under a farm-in agreement with an industry partner.

During 2005, the Company drilled 80 gross wells (46.8 net) which contributed to the 401% increase in production. During the fourth quarter of 2005, the Company drilled 9 gross wells (6.3 net) in the Ferrier area of West Central Alberta and 7 gross wells (2.7 net) wells in the Ricinus area under a farm-in agreement with Enterra. The Ferrier area represents significant development potential for the Company in 2006 and will be the area of focus of further drilling throughout 2006. Also during the fourth quarter of 2005, the Company drilled its first well in the United States in the state of North Dakota targeting the Bakken formation. Due to the late drilling of this well, no reserves were assigned in 2005 and the well will be completed in 2006 and brought on production.

For the forth quarter, production averaged 595 BOE per day, a 129% increase from the forth quarter of 2004 where the Company produced 260 BOE per day. Petroleum and natural gas revenue for the forth quarter of 2005 increased 376% to $2.6 million compared with $0.6 million for the same period in 2004. The increase is attributable to the increased commodity prices and due to the wells drilled throughout 2005 and placed on production.

The Company currently has no derivative financial or physical delivery contracts in place. All production volumes are currently sold into the Alberta spot market.

ROYALTIES
(in thousands except BOE amounts)


	2005						2004
	$			$/BOE			$		$/BOE

Crown royalties	$	1,046		$	4.54		$	232	$	5.05
Other royalties	$	949		$	4.12		$	64	$	1.38

Gross royalties	$	1,995		$	8.66		$	296	$	6.43
Alberta Royalty Tax Credit (ARTC)	$	(341	)	$	(1.48	)		—		—

Net royalties	$	1,654		$	7.18		$	296	$	6.43

Royalties, before ARTC, on a barrel of oil equivalent basis, increased 35% from $6.43 in 2004 to $8.66 per BOE in 2005.

Crown royalties per BOE decreased by 10% due to a lower percentage of total production volumes being produced from crown lands in 2005 compared with 2004. This is partially offset by higher commodity prices in 2005 which would attract a higher royalty, on a BOE basis. Approximately 39% of 2005 oil production revenue came from the Princess area compared to no oil production from the area in 2004.

Other royalties, consisting of freehold royalties and gross overriding royalties, increased significantly on a BOE basis in 2005 due to the increased production volumes in the Princess area where all the production from the area attracts freehold royalties rather than crown royalties. On a total royalty basis, per BOE royalties increased 12% to $7.18 per BOE largely due to the increase in commodity prices in 2005 compared with 2004.

For the forth quarter of 2005, total royalties increased 1,422% to $0.5 million from less than $0.1 million in the forth quarter of 2004. The increase is attributable to the increased production and the increase in the commodity prices for the forth quarter of 2005 compared with the same period in 2004. In addition, forth quarter 2004 royalties were reduced by a credit recorded to crown royalties in the quarter relating to an over delivery of crown oil volumes relating to a prior period in 2004.

PRODUCTION EXPENSES
(in thousands except for percentages and BOE amounts)


	2005		2004		*Change*

Production expenses	$	1,415	$	243		482	%

Production expenses per boe	$	6.14	$	5.27		17	%

Production expenses, which include transportation costs, increased 17% to $6.14 per BOE from $5.27 per BOE in 2004. The increase per BOE is attributed to the overall increase in industry operating costs due to record oil and gas activity levels during 2005. Industry costs are expected to continue to rise into 2006, however, with the Company’s drilling focus on natural gas, which is generally cheaper to operate per BOE, production expenses are expected to increase only slightly in 2006.

Production expenses for the forth quarter of 2005 were $0.6 million or $10.29 per BOE compared with $0.2 million and $7.72 per BOE in the forth quarter of 2004. The increase of $2.57 per BOE, or a 33% increase in the forth quarter of 2005 is attributable the increase in industry costs associated with the record oil and gas activity.

GENERAL AND ADMINISTRATIVE EXPENSES
(in thousands except for percentages and BOE amounts)


	2005			$/BOE			2004			$/BOE

Gross general and administrative expense	$	2,853		$	12.39		$	3,735		$	81.16
2004 bonus recovery from Enterra	$	(831	)	$	(3.61	)		—			—

General and administrative expenses, net of bonus recovery	$	2,022		$	8.78		$	3,735		$	81.16
Overhead recoveries and capitalized general and administrative	$	(897	)	$	(3.90	)	$	(995	)	$	(21.62	)

Net general and administrative expenses	$	1,125		$	4.88		$	2,740		$	59.54


(1)		Net general and administrative expenses is a non-GAAP measure and may not be comparable to the calculation of similar measures for other entities.

Gross general and administrative expenses (“G&A”), before bonus recovery, overhead recoveries and capitalized G&A decreased approximately $0.9 million from $3.7 million in 2004 to $2.8 million in 2005 due in part to a lower bonus expense in 2005 of $0.5 million compared with a bonus expense in 2004 of $2.2 million. The bonus structure is based on the increase in the market capitalization of the Company from year to year. In 2004, the initial public offering of the Company was very successful and the market capitalization of the Company increased significantly in 2004. In 2005, the market capitalization increase from the beginning of the year to the end of the year was less significant.

Gross general and administrative expenses, excluding the effects of the bonus expense and bonus recovery from Enterra, increased approximately $0.8 million or 50% for 2005 compared with 2004. The increase in general and administrative expenses is due to increased staffing levels and associated personnel and office costs attributed to the increased drilling activities in 2005 and the increase in salary and benefits to retain quality staff in this very competitive market.

On a BOE basis, gross and net 2005 general and administrative expenses were $12.39 and $4.88 per BOE, respectively, compared with $81.16 and $59.54 per BOE, respectively, in 2004. In 2004, per BOE general and administrative expenses were high as the Company only commenced operations in mid 2004 and experienced higher staffing levels for future growth.

For 2005, the bonus recovery from Enterra relating to the bonus expensed in the 2004 fiscal year-end reduced general and administrative expenses by $3.61 per BOE.

For the forth quarter of 2005, gross general and administrative expenses, prior to capitalized general and administrative expense were $0.7 million compared to $2.6 million in the forth quarter of 2004. The decrease in gross general and administrative expenses of $1.9 million is primarily attributable to a recovery of bonus expense in the forth quarter of 2005 of $0.2 million compared to a bonus expense of $2.2 million for the same period of 2004. In the forth quarter of 2005, the Company’s stock price had declined from the third quarter so a bonus recovery was recorded. In the forth quarter of 2004, the entire year’s bonus expense of $2.2 million was recorded in the quarter. Excluding the affects of the bonus expense, gross general and administrative expenses for the forth quarter were $0.9 million in 2005 compared with $0.4 million a year prior. The increase of $0.5 is due to the increased staffing levels and associated personnel and office costs as a result of the increased drilling activities during the quarter.

Net general and administrative expense for the forth quarter of 2005 were $0.1million compared with $1.9 million for the same period in 2004. The decrease of $1.8 million is primarily due to the reduction in bonus expense of $2.4 million partially offset by a lower capitalized general and administrative of $0.1 million for 2005 compared with the forth quarter of 2004.

For 2006, net general and administrative expenses per BOE should decline as the first quarter of 2006 production has increased with the staffing levels being maintained at their current levels.

STOCK-BASED COMPENSATION

Stock-based compensation for 2005 increased 381% to $1.1 million from $0.2 million in 2004. The increase is due to the increase in the fair value per share of the stock options issued based on the increase in the volatility of the Company’s stock throughout 2005. During 2004, when the majority of the stock options were issued, the Company was private and the volatility was set at a nominal level of 1%. The Company’s volatility is currently at 50%. Also contributing to the increase in the stock-based compensation is the immediate expensing of stock options issued to two directors of the Company. Stock options issued to members of the Board of Directors vest immediately and therefore, the fair value of director options are expensed in the period they are issued.

For the forth quarter of 2005, stock-based compensation increased 570% to $0.4 million from $0.1 million in the same period of 2004. The increase is due to the increased fair value per share of the stock options issued due to the increased volatility of the Company’s stock as compared to the forth quarter of 2004.

FOREIGN EXCHANGE

Foreign exchange gain for 2005 was $0.5 million, an increase of 146% from a foreign exchange loss of $1.1 million in 2004. The gain in 2005 is primarily due to the affect of the strengthening Canadian dollar relative to the United States dollar (“U.S”) on the Company’s U.S dollar denominated debt. The Company issued $20.0 million in convertible notes in August 2005 when the exchange rate between the Canadian dollar and the U.S dollar was approximately 1.21. At December 31, 2005, the exchange rate had fallen to 1.17 which resulted in a gain on holding the US denominated debt. Due to the fact that the Company’s functional currency is the Canadian dollar, the debt is carried in the Company’s records in Canadian dollars and translated at each reporting period end date. This gain was partially offset by a loss incurred by holding US cash during part of the year thus creating a loss when the Canadian dollar strengthened relative to the US dollar. In 2004, the loss was created entirely due to the strengthening of the Canadian dollar relative to the US dollar while the Company held substantial US currency as a result of the private placement completed in late 2003 and the Company initial public offering in April 2004.

During the forth quarter 2005, the Company incurred a gain of $0.1 million versus a loss of $0.4 million in the forth quarter of 2004. The 125% foreign exchange gain is almost exclusively a result of the strengthening of the Canadian dollar on the US denominated convertible debt.

DEPLETION, DEPRECIATION AND ACCRETION

Depletion is determined on the unit-of-production method based on estimated gross proved reserves at constant prices and costs as determined by independent engineers. Costs of unproven properties, seismic and undeveloped land, net of impairments, are excluded from the depletion calculation and future capital costs associated with proved undeveloped reserves are included. The cost of unproved properties excluded from the depletion calculation at December 31, 2005 was $1.7 million ($0.1 million in 2004). The majority of the unproven properties excluded are located in North Dakota, an area the Company considers to be in the preproduction stage.

Depletion, depreciation and accretion decreased in 2005 to $15.21 per BOE compared to $16.95 per BOE in 2004, after removing the ceiling test write-down of $4.2 million at December 31, 2004. The decrease in depletion, depreciation and accretion is due to the increase in reserves in the Ferrier and Ricinus area’s as a result of the drilling program in the last quarter of 2005.

The Company recognizes an asset retirement obligation “ARO” associated with the retirement of a tangible long-lived asset as a liability in the period in which it is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO is depleted such that the cost of the ARO is recognized over the useful life of the asset. The ARO is recorded at fair value and accretion expense s recognized over time as the discounted liability is accreted to its expected settlement value.

The provision for asset retirement obligations are determined by management in consultation with the Company’s independent engineers and are based on prevailing regulations, costs, technology and industry standards. The estimated present value of the Company’s asset retirement obligation is $1.4 million based on an estimated fair value of $2.7 million, determined using a credit adjusted risk free interest rate of 8.0% and an inflation rate of 2%. These obligations will be settled at the end of the estimated useful lives underlying the assets, which currently extend up to 20 years into the future. Current expenditures for actual abandonment and site restoration in 2005 were $nil.

For the forth quarter of 2005, depletion, depreciation and accretion expense was $1.2 million compared with $4.6 million in the forth quarter of 2004. The decrease is primarily due to a ceiling test write-down in recorded in December 2004 of $4.2 million partially offset by increased depletion, depreciation and accretion expense in the forth quarter of 2005 of $0.8 million as a result of increased production for the period.

LOSS ON EQUITY INVESTMENT

In 2004, the Company incurred a $1.0 million loss on its investment in JMG Exploration, Inc. as compared to a $nil loss in 2005. In 2004, the Company owned 250,000 common shares of JMG which at December 31, 2004 represented 100% of the common shares of JMG. The Company was required to include 100% of the equity loss of JMG into income in 2004. As the loss incurred by JMG for the period ended December 31, 2004 exceeded the Company’s net investment in JMG, the Company reduced its net investment to zero.

INTEREST EXPENSE

Interest expense for 2005 is exclusively due to the issuance of a $20 million Convertible Subordinated Note Agreement in August 2005. The note bears interest at 10% per annum and can be converted at the holder’s option at $20 per share. For 2005, the Company incurred interest expense on the note of $0.8 million. The Company had no long-term debt in 2004; therefore, no interest expense was recorded in 2004.

For the forth quarter of 2005, interest expense was $0.5 million compared with $nil for the same period in 2004. The increase is due to the issuance of a $20 million on Convertible Subordinated Note in August 2005 and in 2004 the Company had no long term debt.

INCOME TAXES

The Company has recorded no current or future income taxes, capital taxes or other taxes for the years 2004 and 2005. The Company has non-capital losses for income tax purposes of approximately $2.7 million available for application against future years’ taxable income of which $2.6 million and $0.1 million expire in the years 2011 and 2012 respectively. The Company has approximately $49.8 million of tax pools remaining at December 31, 2005 to apply against future year’s taxable income.

NET INCOME (LOSS)
(in thousands except for per share amounts)


	2005		2004

Net income (loss)	$	1,143	$	(8,547	)
Net income (loss) – per basic share ⁽¹⁾	$	0.08	$	(0.81	)
Net income (loss) – per diluted share ⁽¹⁾	$	0.07	$	(0.81	)
Weighted average shares outstanding – basic ⁽¹⁾		14,470		10,599
Weighted average shares outstanding – diluted ⁽¹⁾		15,274		11,157


(1)		Per share information and weighted average shares outstanding have been adjusted to reflect the 3-for-2 stock split that occurred on October 12, 2005. 2004 comparative numbers have been adjusted to reflect the stock split as if it occurred from the date of incorporation.

Net income increased by $9.6 million from an $8.5 million loss in 2004 to net income of $1.1 million in 2005. This increase is due to the combination of a $6.8 million increase in revenues net of royalties, a $0.1 million increase in interest income and a $2.8 million decrease in expenses. The net decrease in expenses consists of decreased general and administrative costs of $1.6 million, decreased depletion charges of $1.5 million, no investment loss in 2005 versus a $1.0 million loss in 2004, a foreign exchange gain in 2005 of $0.5 million compared with a foreign exchange loss of $1.1 million in 2004, increased production expenses of $1.2 million, increased stock compensation expense of $0.9 million and increased interest expense of $0.8 million.

Net income per share increased to $0.08 per basic share versus a loss per share of $0.81 in 2004.

FUNDS FROM OPERATIONS
(in thousands except for percentages and per share amounts)

It is management’s view that funds from operations is a useful measure of performance and a good benchmark when comparing results from year to year or quarter to quarter. Funds from operations is a non-GAAP measure and is reconciled with GAAP net income (loss) in the table below:


	2005			2004

Net income (loss)	$	1,143		$	(8,547	)
Add back (subtract) non-cash items:
Depletion, depreciation and accretion	$	3,503		$	4,958
Foreign exchange (gain) loss	$	(500	)	$	1,089
Stock-based compensation	$	1,078		$	224
Loss on equity investment		—		$	1,000

Funds from operations ⁽²⁾	$	5,224		$	(1,276	)
Funds from operations per share – basic ⁽¹⁾⁽²⁾	$	0.36		$	(0.12	)


	2005		2004

Funds from operations per share – diluted ⁽¹⁾⁽²⁾	$	0.34	$	(0.11	)
Weighted average shares outstanding – basic ⁽¹⁾		14,470		10,599
Weighted average shares outstanding – diluted ⁽¹⁾		15,274		11,157


(1)		Per share information and weighted average shares outstanding have been adjusted to reflect the 3-for-2 stock split that occurred on October 12, 2005. 2004 comparative numbers have been adjusted to reflect the stock split as if it occurred from the date of incorporation.

(2)		Funds from operation and funds from operations per share are non-GAAP measures and may not be comparable to the calculation of similar measures for other entities.

LIQUIDITY AND CAPITAL RESOURCES

Capital expenditures of $43.7 million were financed through a combination of funds from operations, the proceeds of the $20 million convertible note, the proceeds from the exercise of stock options and the utilization of working capital. In August 2005, the Company completed a $20 million Convertible Subordinated Note Agreement for gross proceeds of $20 million. Total outstanding common shares at December 31, 2005 was 14,630,256.

At December 31, 2005 the Company had a working capital deficiency of $3.6 million and no bank debt.

On July 27, 2005, the Company entered into a Loan Agreement and Promissory Note with an arms length party whereby the Company advanced the party C$5,000,000 (US$4,288,165) for the construction of drilling equipment. In return for the note, the Company will be provided with five dedicated drilling rigs for a period of three years. The advance will be repaid to the Company through payment from a portion of the drilling rigs daily charges from the date of rig delivery until paid in full. The note is secured by a General Security Agreement over all assets of the third party, bears no interest and has no set repayment schedule. One of the drilling rigs was delivered to the Company in December 2005 with the final four rigs to be delivered by July 2006.

Subsequent to year end, in March 2006, the Company entered into a C$20 million (US$17.2 million) credit facility with a Canadian banking institution. The credit facility available to the Company is in part determined by the borrowing base of the Company. This borrowing base may be increased to C$30 million pending the confirmation of certain production levels. This borrowing base may be reduced by several factors including the material decline in commodity prices or revisions in reserves estimates, thereby reducing the credit facility available to the Company.

On February 27, 2006, the Company and JMG Exploration, Inc. announced they had signed a letter of intent to pursue a possible acquisition of JMG by JED. The proposal would offer two-thirds of a share of common stock of JED for each share of common stock of JMG. Completion of the proposed transaction is subject to the receipt of independent third party opinions that the transaction is fair to both the shareholders of JMG and JED. In addition, completion of the transaction is subject to receipt of all regulatory and stock exchange approvals in the United States and Canada and the approval of the shareholders of both JMG and JED. Should all conditions be met, the transaction is expected to close in August 2006.

The Company has entered into five separate Standard Daywork Contracts with a drilling contractor who will supply the Company with five drilling rigs for a period of three years. The terms of each contract call for a minimum requirement of 250 operating days per year for a total of 750 operating days over the three-year term of each separate contract. For the year 2006, the minimum capital requirement to satisfy the terms of the contracts is estimated to be $14.6 million. The total commitment over the life of these contracts is estimated to be $56.3 million.

The Company has substantial undiscounted future development costs of $45.5 million associated with the development of the Company’s proved non-producing and proved undeveloped properties, as estimated by the independent engineers. Should the Company not fulfill its future development obligations, the amount and value of the Company’s proved reserves could be reduced and the reduction could be significant.

RELATED PARTY TRANSACTIONS

Under the 2^nd Amended and Restated Agreement of Business Principles, properties acquired by Enterra will be contract operated and drilled by JMG, if they are exploration properties, and contract operated and drilled by JED if they are development projects. Exploration of the properties will be done by JMG, which will pay 100% of the exploration costs to earn a 70% working interest in the properties. If JMG discovers commercially viable reserves

on the exploration properties, Enterra will have the right to purchase 80% of JMG’s working interest in the properties at a fair value as determined by independent engineers. Should Enterra elect to have JED develop the properties, development will be done by JED, which will pay 100% of the development costs to earn 70% of the interests of both JMG and Enterra. Enterra will have a first right to purchase assets developed by JED.

Under Technical Services Agreements between JED and Enterra, and JED and JMG, both the Company and Enterra provide operational, technical and administrative services in connection with the management, development and exploitation and operation of the assets of JED, Enterra and JMG. Each entity provides these services on an expense re-imbursement basis based on the monthly capital activity and production levels relative to the combined capital activity and production levels of all three companies. For the year ended December 31, 2005, the Company charged general and administrative expenses and field operating expenses to Enterra of $5.1 million. The total outstanding from Enterra at December 31, 2005 was $6.2 million (December 31, 2004 — $1.8 million). Effective January 1, 2006, both Technical Services Agreements were terminated .

In August 2004, the Company acquired 250,000 common shares of JMG, a private company at the time of the Company’s investment, representing approximately 11% equity interest in the total voting share capital of JMG (and 100% of the Common Stock), for cash consideration of $1.0 million. In August 2005, JMG completed its initial public offering which reduced the Company’s ownership in JMG to approximately 6%. The Company is represented with two of the five seats on the JMG Board of Directors. The Company’s investment in JMG is being accounted for using the equity method. At December 31, 2004, the Company owned 100% of the common shares of JMG and was required to include 100% of the equity loss of JMG for the period then ended. As the loss incurred by JMG for the period ended December 31, 2004 exceeded JED’s net investment, the Company reduced its net investment to zero. However, as JED has not guaranteed any obligations or is not committed to any further financial support, no additional equity losses on the JMG investment has been recorded.

During the year ended December 31, 2005, the Company entered into the following transactions with JMG:

	(i)		JED charged JMG for certain general and administrative services and oil and gas equipment in the amount of $0.7 million (2004 — $0.3 million). These services were provided at standard industry rates for similar services;

	(ii)		in consideration for the assignment of JED’s interests in certain oil and gas properties, the Company charged JMG for drilling and other costs related to those properties in the amount $0.1 million for the year ended December 31, 2005, on a cost recovery basis.

In connection with these transactions the total amount receivable from JMG at December 31, 2005 was $0.4 million (December 31, 2004 — $0.4 million). Subsequent to year-end, this amount was paid in full.

BUSINESS RISK

Exploration, development and production of petroleum and natural gas involves many risks that even the combination of experience and diligent evaluation may not be sufficient to overcome. Utilizing highly skilled professionals, focusing in areas where the Company has existing knowledge and expertise or access to such expertise, using the most up to date technology, and controlling costs to maximize margins, mitigate these risks. The Company maintains a comprehensive insurance program that insures liability and property consistent with good industry practices. The program is designed to mitigate risks and protect against significant loss. However, the Company is not fully insured against all these risks, nor are all such risks insurable.

The reserve and recovery information contained in the Company’s independent reserve evaluation is only an estimate. The actual production and ultimate recovery of reserves from the properties may be greater or less than the estimates prepared by the independent reserve engineers. A significant portion of the Company’s assets is the Ferrier property whose relatively short production history may make estimates on this property more subject to revisions. The reserve report was prepared using commodity prices in place at the end of the year. If lower prices for crude oil, natural gas liquids and natural gas are realized by the Company, the present value of the estimated future cash flows for the reserves would be reduced and the reduction could be significant.

Financial risks include exposure to fluctuation in commodity prices, currency exchange rates and interest rates. To mitigate the risks, the Company may enter into physical contracts for the sale of crude oil, natural gas liquids and natural gas at fixed prices. The Company may also institute financial hedging techniques for interest rates, currency exchange rates and commodity prices. If utilized, such transactions would be subject to certain limits on term and amount as established by the Board of Directors.

OIL AND GAS RISKS

Inherent in development of oil and gas reserves are risks, among others, of drilling dry holes, encountering production or drilling difficulties or experiencing high decline rates in producing wells. In addition, a major market risk exposure is in the pricing applicable to our oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to our Canadian oil and natural gas production. Prices received for oil and gas production have been and remain volatile and unpredictable. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that non-cash write-downs of our oil and gas properties could occur under the full-cost accounting method allowed by the Securities Exchange Commission (SEC). Under these rules, we review the carrying value of our proved oil and gas properties each quarter on a country-by-country basis to ensure that capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization, and deferred income taxes, do not exceed the “ceiling.” This ceiling is the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties included in the costs being amortized, net of related tax effects. If capitalized costs exceed this limit, the excess is charged to additional depletion, depreciation and accretion expense. The calculation of estimated future net cash flows is based on the prices for crude oil and natural gas in effect on the last day of each fiscal quarter except for volumes sold under long-term contracts. Write-downs required by these rules do not impact cash flow from operating activities; however, as discussed above, sustained low prices would have a material adverse effect on future cash flows.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

We have entered into indemnification agreements with all of our directors and officers, which provides for the indemnification and advancement of expenses by us. There is no pending litigation or proceeding involving any director or officer of for which indemnification is being sought, nor are we aware of any threatened litigation that may result in claims for indemnification.

The Company has entered into five separate Standard Daywork Contracts with a drilling contractor who will supply the Company with five drilling rigs for a period of three years. The terms of each contract call for a minimum requirement of 250 operating days per year for a total of 750 operating days over the three-year term of each separate contract. The total commitment over the life of these contracts is estimated to be $56.3 million as outlined is the table below:

(in thousands)


	2006		2007		2008		2009		Total

Estimated minimum lease payments	$	14,579	$	18,750	$	18,750	$	4,171	$	56,250

The Company has no derivative financial or physical delivery contracts in place December 31, 2005.

SUMMARY OF QUARTERLY RESULTS
(in thousands except for percentages and per share amounts)

2005 Quarter Ended


	March 31		June 30		September 30		December 31

Revenue before royalties	$	1,740	$	1,994	$	3,294	$	2,631
Funds from operations ⁽¹⁾	$	822	$	1,707	$	1,475	$	1,220
Funds from operations per share – basic ⁽¹⁾	$	0.06	$	0.12	$	0.10	$	0.08


	March 31		June 30		September 30		December 31

Funds from operations per share – diluted ⁽¹⁾	$	0.05	$	0.11	$	0.10	$	0.08
Net income	$	134	$	865	$	446	$	(302	)
Net income per share – basic	$	0.01	$	0.06	$	0.03	$	(0.02	)
Net income per share – diluted	$	0.01	$	0.05	$	0.03	$	(0.02	)
Capital expenditures	$	7,313	$	7,322	$	1,382	$	27,691
Production (BOE/d)		585		583		759		596

2004 Quarter Ended


	March 31			June 30			September 30			December 31

Revenue before royalties		—		$	396		$	570		$	553
Funds from operations ⁽¹⁾	$	(80	)	$	69		$	191		$	(1,456	)
Funds from operations per share – basic ⁽¹⁾⁽²⁾		—		$	0.01		$	0.01		$	(0.10	)
Funds from operations per share – diluted ⁽¹⁾⁽²⁾		—		$	0.01		$	0.01		$	(0.10	)
Net loss	$	(71	)	$	(292	)	$	(616	)	$	(7,568	)
Net loss per share – basic ⁽²⁾		—		$	(0.02	)	$	(0.04	)	$	(0.53	)
Net loss per share – diluted ⁽²⁾		—		$	(0.02	)	$	(0.04	)	$	(0.53	)
Capital expenditures	$	546		$	3,584		$	672		$	5,312
Production (BOE/d)		—			134			184			260


(1)		Funds from operation and funds from operations per share are non-GAAP measures and may not be comparable to the calculation of similar measures for other entities.

(2)		During the quarter ended March 31, 2004, the Company only had Series A Preferred Shares outstanding and no common shares outstanding. Accordingly, the preferred shares were excluded from the funds from operations per share and loss per share and calculations resulting in no per share numbers for the quarter then ended. As a result of not having per share calculations for part of the year, the addition of all four quarters of 2004 will not reconcile to the yearly per share numbers.

OUTSTANDING SHARE DATA

As of December 31, 2005, there are 14,630,256 common shares outstanding, 1,291,251 stock options outstanding, 156,000 share purchase warrants outstanding and 1,000,000 common shares reserved for issuance upon conversion of the convertible note.

CRITICAL ACCOUNTING POLICIES

Policies and the Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect reported assets and liabilities, disclosures of contingencies and revenues and expenses. Management is also required to adopt accounting policies that require the use of significant estimates. Actual results could differ materially from those estimates. A summary of significant accounting policies adopted by the Company can be found in note 1 to the Consolidated Financial Statements. In assisting the Company’s Audit Committee to fulfill its financial statement oversight role, management regularly meets with the Committee to review the Company’s significant accounting policies, estimates and any significant changes thereto, including those discussed below.

Management believes the most critical accounting policies, including judgments in their application, which may have an impact on the Company’s financial results, relate to the accounting for property and equipment and asset retirement obligations. The rate at which the Company’s assets are depreciated or otherwise written off and the asset retirement liability provided for, with the associated accretion expense to the income statement, are subject to a number of judgments about future events, many of which are beyond managements control. Reserves recognition is central to much of the accounting for an oil and gas company as described below.

Reserves Recognition

Underpinning the Company’s oil and gas assets are its oil and gas reserves. Detailed rules and industry practice, to which the Company adheres, have been developed to provide uniform reserves recognition criteria. However, the process of estimating oil and gas reserves by independent engineers is inherently judgmental. There are two principal sources of uncertainty: technical and commercial. Technical reserves estimates are made using available

geological and reservoir data as well as production performance data. As new data becomes available, including actual reservoir performance, reserves estimates may change. Reserves can also be classified as proved or probable with decreasing levels of certainty as to the likelihood that the reserves will ultimately be produced.

Reserves recognition is also impacted by economic considerations. In order for reserves to be recognized, they must be reasonably certain of being produced under existing economic and operating conditions, which is viewed as being at year end commodity prices with a cost profile based on current operations. As economic conditions change, primarily as a result of changes in commodity prices and, to a lesser extent, operating and capital costs, marginally profitable production, typically experienced in the later years of a field’s life cycle, may be added to reserves or conversely, may no longer qualify for reserves recognition.

The Company’s reserves and revisions to the those reserves, although not separately reported on the Company’s balance sheet or income statement, impact the Company’s reported net income (loss) through the depletion and depreciation of the Company’s property and equipment and the provision for future asset retirement obligations.

The Reserves Committee of the Company’s Board of Directors reviews the Company’s reserves booking process and related public disclosures. The primary responsibilities of the Reserve Committee of the Board of Directors include amongst other things, reviewing the Company’s reserves and recommending to the Board of Directors, the Company’s annual reserve report as prepared by the Company’s independent reserves engineers and other oil and gas information.

Depletion, Depreciation and Amortization Expense (DD&A)

The Company follows the full-cost method of accounting for petroleum and natural gas properties. Under this method, the Company capitalizes all costs relating to the exploration for and the development of oil and natural gas reserves including land acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling of productive and non-productive wells and general and administrative costs directly related to exploration and development activities. Proceeds from the disposal of properties are applied as a reduction of costs without the recognition of a gain or loss except where such disposals would result in a greater than 25% change in the depletion rate.

Capitalized costs are depleted and depreciated using the unit-of-production method based on the estimated proven oil and natural gas reserves before royalties as determined by independent engineers. Properties are evaluated on a quarterly basis by the Company’s internal engineers. Units of natural gas are converted into barrels of equivalents on a relative energy content basis. Costs related to unproven properties are excluded from the costs subject to depletion until it is determined whether or not proved reserves exist or if impairment has occurred.

In performing its quarterly ceiling test, the Company limits, on a country-by-country basis, the capitalized costs of proved oil and gas properties, net of accumulated depletion, depreciation and amortization (“DD&A”) and deferred income taxes, to the estimated future net cash flows from proved oil and gas reserves based on period-end prices, discounted at 10 percent, net of related tax effects, plus the value of unproved properties. If capitalized costs exceed this limit, the excess is charged to additional DD&A expense.

Given the volatility of oil and gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of petroleum and natural gas properties could occur.

Asset Retirement Obligations

The Company follows SFAS No 143. “Accounting for Asset Retirement Obligations”, which requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset. The ARO is recorded at fair value, and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the Company’s credit-

adjusted risk-free interest rate. The Company’s asset retirement obligations primarily relate to the plugging and abandonment of petroleum and natural gas properties.

Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the petroleum and natural gas properties balance.

Foreign Currency Translation

As the majority of the Company’s operating activities are in Canada, the Company uses the Canadian dollar as its functional currency. The Company’s operations are translated for financial statement reporting purposes into United States dollars in accordance with Statement of Financial Accounting Standards No. 52, Foreign Currency Translation, using the current rate method. Under this method, all assets and liabilities are translated at the period end rate of exchange and all revenue and expense items are translated at the average rate of exchange for the period. Exchange differences arising on translation are classified as other comprehensive income in a separate component of stockholders’ equity.

Monetary assets and liabilities denominated in a currency other than the Company’s functional currency are translated at the exchange rates in effect at the balance sheet date. Non-monetary assets and liabilities denominated in a currency other than the Company’s functional currency are translated at historical exchange rates. Revenues and expenses are translated at average rates for the period. Exchange gains or losses are reflected in the Consolidated Statement of Operations for the period.

Stock Based Compensation

The Company has a stock-based compensation plan which reserve shares of common stock for issuance to key employees and directors. The Company accounts for grants issued under this plan using the fair value recognition provisions of Statement of Financial Accounting Standards No. 123-R, Accounting for Stock-Based Compensation (“SFAS 123-R”). Under these provisions, the cost of options granted to employees is charged as an expense with a corresponding increase in additional paid-in capital, based on an estimate of the fair value determined using the Black-Scholes option pricing model.

IMPACT OF NEW ACCOUNTING POLICIES

Accounting Changes and Error Corrections

In June 2005, the FASB issued Statement 154, Accounting Changes and Error Corrections which replaces APB Opinion 20 and FASB Statement 3. Statement 154 changes the requirements for the accounting and reporting of a change in accounting principle. Opinion 20 previously required that most voluntary changes in accounting principles be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. In the absence of explicit transition provisions provided for in new or existing accounting pronouncements, Statement 154 now requires retrospective application of changes in accounting principle to prior period financial statements, unless impracticable to do so. The Statement is effective for fiscal years beginning after December 15, 2005. The Company does not expect the adoption of this statement will have a material impact on its results or operations or financial position.

Exchange of Nonmonetary Assets

In December 2004, the FASB issued Statement 153, Exchange of Nonmonetary Assets, an amendment of APB Opinion 29, Accounting for Nonmonetary Transactions. This amendment eliminates the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have a commercial substance. Under Statement 153, if a nonmonetary exchange of similar productive assets meets a commercial-substance criterion and fair value is determinable, the transaction must be accounting for at fair value resulting in recognition of any gain or loss. The statement is effective for nonmonetary transactions in fiscal periods that begin after June 15, 2005. The adoption of this statement will not have any material impact on

our results of operations or financial position.

RESEARCH AND DEVELOPMENT, PATENTS AND LICENSES, ETC

JED does not engage in R&D activities as part of its oil and gas business.

OFF — BALANCE SHEET ARRANGEMENTS

On July 27, 2005, the Company entered into a Loan Agreement and Promissory Note with an arms length party whereby the Company advanced the party C$5,000,000 (US$4,228,165) for the construction of drilling equipment. In return for the note, the Company will be provided with five dedicated drilling rigs for a period of three years. The advance will be repaid to the Company through payment from a portion of the drilling rigs daily charges from the date of rig delivery until paid in full. The note is secured by a General Security Agreement over all assets of the third party, bears no interest and has no set repayment schedule. One of the drilling rigs was delivered to the Company in December 2005 with the final four rigs to be delivered by July 2006.

Item 6. Directors, Senior Management and Employees

Directors and Senior Management

JED’s officers, directors and executive officers as of May 31, 2006 are as follows:


Name	Age		Position

Reginald J. Greenslade (3)		42	Chairman and Director
Thomas J. Jacobsen (4)		71	Chief Executive Officer and Director
Alan F. Williams		53	President
David C. Ho		37	Chief Financial Officer
Ludwig (Louie) Gierstorfer (1) (2) (3)		59	Director
Horst Engel (1) (2) (4)			Director
Justin W. Yorke (1) (2) (3)		39	Director


(1)		Member of Audit Committee.

(2)		Member of Compensation Committee.

(3)		Member of Reserves Committee.

(4)		Member of Governance and Nominating Committee.

Reginald J. Greenslade has been serving as Chairman and Director since November 2003. He was President, CEO and Director of Enterra from January 16, 2005 to March 31, 2006 and from the fall of 2001 until November 2003. He served as Chairman of the Enterra Board between his appointment as President and CEO. He was a director of PASW Inc., a software development company, from February 2001 to July 2001. From 1995 until the formation of Enterra, Mr. Greenslade was the President, CEO and Director of Big Horn Resources Ltd, a predecessor of Enterra’s. Prior to his position with Big Horn, Mr. Greenslade was with CS Resources Limited in the areas of exploitation engineering and project management from 1993 to 1995. Prior to 1993, Mr. Greenslade was employed by Saskatchewan Oil and Gas Corporation in the capacities of project management, production, and reservoir engineering. He has extensive experience with secondary recovery schemes and is recognized for his work in the specialized field of horizontal well technology. All the above companies were publicly traded in either the U.S., Canada, or both, during the periods indicated.

Thomas J. Jacobsen became our President, Chief Operating Officer and Director in September 2003 and currently continues to serve as Chief Executive Officer and a Director. Mr. Jacobsen joined Westlinks Resources Ltd., a predecessor of Enterra, as a director in February 1999, and was appointed Executive Vice President, Operations in October 1999. In October 2000, he resigned from this position and was appointed Vice Chairman of The Board of Directors. Mr. Jacobsen became Enterra Chief Operating Officer in February 2002 and resigned in November 2003. Mr. Jacobsen has more than 40 years experience in the oil and gas industry in Alberta and Saskatchewan including

serving as President, Chief Operating Officer and a director of Empire Petroleum Corporation from June 2001 to April 2002, President and Chief Executive Officer of Niaski Environmental Inc. from November, 1996 to February, 1999, President and Chief Executive Officer of International Pedco Energy Corporation from September 1993 to February 1996, and President of International Colin Energy Corporation from October 1987 to June 1993. Mr. Jacobsen served as a director of Cariboo Resources Corp., formerly Niaski Environmental Services Inc. Niaski’s proposal to its creditors under the Bankruptcy and Insolvency Act (Canada) was accepted in April 2000 and Niaski was discharged in May 2001. All of the above companies were publicly traded in either the U.S., Canada, or both, during the periods indicated.

Alan F. Williams became our President in November 2004. Prior to that he helped form and was Chief Operating Officer and Vice President, Exploration of Endev Energy Inc. since April 2002. From September 1999 to December 2001 he was Vice President, Exploration of Allied Oil & Gas Corp., a Toronto Stock Exchange listed oil and gas issuer. From October 1997 to July 1999 he held the position of Vice President Exploration of Edge Energy Inc., and was Vice President, Exploration of Chancellor Energy Ltd. From November 1994 to April 1996.

David C. Ho became our Chief Financial Officer in April 2006. Mr. Ho was previously the Controller of Aquest Energy Ltd, a Toronto Stock Exchange listed junior oil and gas company since December 2004. In March 2002 , Mr. Ho took on the role of Controller of Coastal Energy, a private junior Canadian oil and gas organization. Mr. Ho graduated with a Bachelors of Commerce degree majoring in Accounting from the University of Calgary in 1991, then articled with Coopers & Lybrand where he obtained his Chartered Accountant designation in 1994. While in public practice, Mr. Ho provided financial reporting and audit advisory services to public and private exploration and development enterprises in the oil & gas industry.

Ludwig (Louie) Gierstorfer was appointed to our Board of Directors in September 2003. Most recently, he served as Chief Executive Officer, President and Director of Pirate Drilling Inc., a privately held drilling services company, from 1980 to 2000 when its assets were sold to the Ensign Group. During his tenure at Pirate Drilling, he also was Chief Executive Officer, President and Director of Pirate Ventures Inc., an associated company of Pirate Drilling Inc., which drilled and operated oil and natural gas properties from 1982 until the assets were sold in early 2003. Prior to founding Pirate Drilling, he held various field positions with Westburne Drilling. All the above companies were publicly traded in Canada, except as noted, during the periods indicated.

Justin W. Yorke was appointed to our Board of Directors in November 2005. Mr. Yorke has over 10 years experience as an institutional equity fund manager and senior financial analyst for investment funds and investment banks. He currently is a Director at Dunes Advisors, which assists international and domestic middle market companies in private equity fund raising and joint venture partnerships with Asian strategic investors. Until December 2001, Mr. Yorke was a partner at Asiatic Investment Management, which specialized in public and private investments in South Korea. From May 1998 to June 2000, Mr. Yorke was a Fund Manager and Senior Financial Analyst, based in Hong Kong, for Darier Henstch, S.A., a private Swiss bank, where he managed their $400 million Asian investment portfolio. From July 1996 to March 1998, Mr. Yorke was an Assistant Director and Senior Financial Analyst with Peregrine Asset Management, which was a unit of Peregrine Securities, a regional Asian investment bank. From August 1992 to March 1995, Mr. Yorke was a Vice President and Senior Financial Analyst with Unifund Global Ltd., a private Swiss Bank, as a manager of its $150 million Asian investment portfolio.

Horst H. Engel was born in Germany, where he lived and was educated until 1961 when he emigrated to the U.S. Since 1963 he has been involved in the travel business. He was part owner and president of V.I.P. Travel, an exclusive travel management company in Sierra Madre, California for more than 30 years. Mr. Engel is a certified Travel Counselor; he is a Life member of the Travel Institute and a Life member of the Royal Geographical Society, and holds a community college teaching credential in business and industrial management. He is also an elder in the Presbyterian Church. He has served as a board member and officer of several companies and organizations, has consulted businesses in marketing and management areas.

Compensation

Summary of Executive Compensation

The following table provides a summary of compensation earned during each of the last three fiscal years by our Chief Executive Officer and for the next four most highly compensated executive officers (the “named executive officers”). The figures are in Canadian dollars.


			Annual Compensation						Long-Term Compensation
									Awards				Payout
									Securities		Shares
									under		subject to
Name &							Other Annual		Options		Resale				All Other
Principal			Salary				Compensation		Granted		Restrictions		LTIP		Compensation
Position	Year		($)		Bonus($)		($)		(#)		($)		Payouts($)		($)
Reginald J. Greenslade		2005		—		—		—		—		—		—		—
Former President		2004		200,000		194,625		—		50,000		—		—		10,450
and Chief Executive Officer		2003		—		—		—		—		—		—		—
Thomas J. Jacobsen		2005		190,000		45,836		—		—		—		—		13,300
Chief Executive		2004		190,000		184,894		—		50,000		—		—		9,975
Officer		2003		—		—		—		—		—		—		—
Alan F. Williams		2005		173,333		41,816		—		—		—		—		11,912
President		2004		25,173		100,000		—		50,000		—		—		—
		2003		—		—		—		—		—		—		—
Bruce A. Stewart		2005		143,333		34,578										9,100
Vice-President, Finance and		2004		125,833		122,452		—		45,000		—		—		6,708
CFO		2003		28,750		—		—		—		—		—		—
Tom Dirks		2004		130,000		126,506		—		45,000		—		—		6,825
Vice-President, Exploration		2003		—		—		—		—		—		—		—
Donald Ashton		2004		124,167		120,830		—		45,000		—		—		6,592
Vice-President, Operations		2003		—		—		—		—		—		—		—

Management Contracts

We have no employment contracts with any employees.

Stock Option Plan

Our Stock Option Plan (the “Plan”) was adopted by the Board and approved by our stockholders in 2004. Under the Plan, officers, directors, employees and consultants of the Company or any of its subsidiaries (the “Participants”) may be awarded stock options to purchase shares of our Common Stock. Options may be incentive stock options meeting the statutory requirements of Section 422 of the U.S. Internal Revenue Code, or non-statutory stock options which do not meet those requirements.

The Plan is administered by the Board and its Compensation Committee. The Compensation Committee has complete discretion to determine who should be granted a stock option, determine the type, number, vesting schedule and other terms and conditions of a grant, interpret the Plan, and make all other decisions relating to the operation of the Plan. The exercise price for non-statutory and incentive stock options granted under the Plan may not be less than 100% of the fair market value of the Common Stock on the date of grant.

If there is a change in control of the Company, the outstanding stock options will immediately vest and become exercisable. A change in control includes: a merger or consolidation after which our then current stockholders own less than 50% of the surviving corporation; a sale of all or substantially all of our assets; or an acquisition of 50% or more of our outstanding stock by a person other than or a corporation owned by our stockholders in substantially the same proportions as their stock ownership in us.

In the event of a merger or other reorganization of the Company, the outstanding stock options will be subject to the agreement of merger or reorganization, which may provide for: assumption of outstanding stock options by the surviving corporation or its parent; continuation of outstanding stock options by us if we are the surviving corporation; accelerated vesting; or settlement in cash followed by cancellation of outstanding stock options.

If an optionee ceases to be eligible for stock options due to the loss of employment for any reason other than death, the stock options terminate in 30 days, provided that in the event of termination of employment for cause, the Board may terminate the stock options on the same date. If an optionee dies, his or her legal representatives may exercise his or her unexercised stock options within the earlier of six months after the death or the normal expiry time of the unexercised stock options.

No Participant may be granted an option if it would cause the Participant to hold more than 5% of our outstanding Common Shares on the date of such grant. Stock options granted under the Plan are non-assignable and non-transferable for a period of time fixed by the Board, such period not to exceed the maximum term permitted by the stock exchange on which the Common Shares are listed (the “Option Period”). However, the Option Period must be reduced with respect to any option, as provided in the Plan, covering cessation of the Participant as a director, officer, employee or consultant of the Corporation or any of its subsidiaries, death of the Participant or change of control of the Corporation.

Option agreements may provide that, in the event a stockholder of the Company receives a “take-over” bid as defined in the Securities Act (Alberta), as amended from time to time, or any successor legislation thereto, pursuant to which the “offeror” as a result of such take-over bid, if successful, would beneficially own in excess of 50% of the outstanding Common Shares of the Corporation (a “Control Bid”), the Board may, at its option, require the acceleration of the vesting time for the exercise of such option to allow the Participant to exercise such option (including in respect of Common Shares not otherwise vested at such time) for the purpose of tendering the Common Shares received thereon to the Control Bid.

Option Grants During Fiscal Year 2005

There were 1,291,251 stock options outstanding at a weighted average price of $8.49 at the fiscal year ended December 31, 2005. At December 31, 2005, 171,770 shares were remaining available for future issuance under the stock option plan.

The following table discloses the grants of options to purchase or acquire shares of common stock to our executive officers during the period indicated.

Stock Options Granted During 2005

Market Value of

Securities

% of Total

Securities

Under Share

Options

Exercise Price

Underlying Share

Options

Granted to

at Date of

Options at Date

Expiration

Granted

Employees in

Grant

of Grant

Date

Name

(#)

Financial Year

(US$/Security)

(mm/dd/yyyy)

Reginald J. Greenslade

Nil

N/A

Thomas J. Jacobsen

Nil

N/A

Alan F. Williams

Nil

N/A

Bruce A. Stewart

Nil

N/A

Thomas N. Dirks

Nil

N/A

Donald Ashton

Nil

N/A

Option Exercises in Fiscal Year 2005 and Option Values at the End of Fiscal Year 2005

The following table sets forth the aggregate of options exercised by our executive officers during the year ended December 31, 2005 and the December 31, 2005 year-end values for options granted to the executive officers.

Three of the named executive officers exercised options during the fiscal year ending December 31, 2005. The following table sets forth the number and value of securities underlying options held as of December 31, 2005.

Aggregate Stock Options Exercised and Year-End Values


	Common
	Shares								Value of Unexercised
	Acquired				Unexercised Stock Options				in the money Stock Options at
	on		Aggregate		at December 31, 2005				December 31, 2005⁽²⁾
	Exercise		Value Realized		Exercisable/Unexercisable				Exercisable/Unexercisable
Name⁽¹⁾	(#)		($)		(#)				(US$)
Reginald J. Greenslade		0		0		25,000	/	50,000		325,750	/	651,500
Thomas J. Jacobsen		0		0		25,000	/	50,000		325,750	/	651,500
Alan F. Williams		0		0		25,000	/	50,000		325,750	/	651,500
Bruce A. Stewart		15,000		193,800		0	/	30,000		0	/	390,900
Thomas N. Dirks		15,000		150,623		0	/	0		0	/	0
Donald Ashton		15,000		86,770		30,000	/	0		390,900	/	0

Notes:


(1)		The value of unexercised Stock Options at December 31, 2005 was based on a closing price per Common Share on the American Stock Exchange on December 31, 2005 of $13.03.

Other Compensation Plans

Stock Savings Plan

Our Stock Savings Plan was adopted by the Board, approved by our stockholders, and registered under Form S-8 with the SEC, in 2004. The Stock Savings Plan allows all employees to purchase our shares at the current market price in an amount not to exceed 7% of the employee’s monthly salary, excluding overtime. We will match all employee contributions to the Stock Savings Plan up to their maximum contribution. All contributions made by us will be a taxable benefit to each employee.

Annual Bonus Program

Our Annual Bonus Program was adopted by the Board and approved by our stockholders in 2004. The Annual Bonus Program is designed to reward our head office employees and consultants based on the annual increase in our market capitalization. The increase in our market capitalization will be calculated as the year-end share price minus the beginning of the year share price, multiplied by the weighted average number of shares outstanding for the year. An amount equal to 0.7% of this increase in market capitalization will then be used to create a bonus pool available to head office employees, consultants and directors. Each eligible person’s share of the bonus pool will be their pro-rata share of the total salaries and consulting fees for the particular year.

Board Practices

JED is authorized to have a board of at least three directors and no more than fifteen. JED currently has five directors. Directors are elected for a term of about one year, from annual meeting to annual meeting, or until an earlier resignation, death or removal. Each officer serves at the discretion of the Board or until an earlier resignation, death or removal. There are no family relationships among any of our directors or officers.

United States resident directors receive US$10,000 annual compensation for service on the Board. Canadian resident directors receive CDN$10,000 annual compensation for service on the Board. Directors are also compensated for out-of-pocket costs, including travel and accommodations, relating to their attendance at Board meetings. Directors are entitled to participate in our Stock Option Plan. Independent directors were granted 135,000 options to acquire shares of common stock at a range between $3.67 and $17.35 per share which expire between January 2009 and November 2010. Additionally, Reginald J. Greenslade, Chairman of the Board, and Thomas J. Jacobsen, Chief Executive Officer and Director, have each been granted options to acquire 75,000 shares of our Common Stock at $3.67 per share which expire in January 2009.

We have no service contracts with any of our directors.

Committees of the Board of Directors

Our Board currently has an Audit Committee, a Compensation Committee, a Governance and Nominating Committee, a Reserves Committee and a Special Committee for the proposed merger with JMG.

Audit Committee. Our Audit Committee consists of Mr. Yorke, Mr. Gierstorfer, and Mr. Engel. Mr. Yorke serves as Chairman of the Audit Committee, and is a financial expert under applicable SEC rules and regulations. All of the three member are independent directors under applicable SEC and Canadian rules and regulations. The Audit Committee reviews in detail and recommends approval by the full Board of our annual and quarterly financial statements, recommends approval of the remuneration of our auditors to the full Board, reviews the scope of the audit procedures and the final audit report with the auditors, and reviews our overall accounting practices and procedures and internal controls with the auditors.

Compensation Committee. Our Compensation Committee consists of Mr. Gierstorfer, the committee chairman, Mr. Yorke and Mr. Engel. All of the three members are independent directors. The Compensation Committee recommends approval to the full Board of the compensation of the Chief Executive Officer, the annual compensation budget for all other employees, bonuses, grants of stock options and any changes to our benefit plans.

Governance and Nominating Committee. Our Governance and Nominating Committee consists of Mr. Jacobsen, the committee chairman and Mr. Engel. Mr. Engel is an independent director. The Governance and Nominating Committee determines the scope and frequency of periodic reports to the Board concerning issues relating to overall financial reporting, disclosure and other communications with our stockholders, and recommends approval to the full Board of director nominations.

Reserves Committee. Our Reserves Committee consists of Mr. Gierstorfer, the committee chairman, Mr. Greenslade and Mr. Yorke. Mr. Gierstorfer and Mr. Yorke are independent directors. The Reserves Committee retains our independent reservoir engineers, reviews our information systems and internal controls for the information provided to the independent reservoir engineers, and reviews and recommends approval to the full Board of our annual reserve report as prepared by the independent reservoir engineers.

Special Committee. Our Special Committee consists of Mr. Yorke, the committee chairman, Mr. Gierstorfer and Mr. Engel, and was formed to oversee the process of the proposed merger with JMG, as Mr. Greenslade and Mr. Jacobsen are also directors of JMG.

Employees

At December 31, 2005, JED had approximately 30 employees and consultants working both in our head office and in field operations. At December 31, 2004 JED had approximately 73 employees and consultants and provided all staff to Enterra, and nil employees and consultants at December 31, 2003 except for the President and CFO, as all staff was provided by Enterra. None of JED’s employees are members of a labor union.

Share Ownership

The following table sets forth information regarding beneficial ownership of our Common Stock as of June 26, 2006, by our executive officers and directors individually and as a group. The address of each executive officer and director is Suite 2200, 500 — 4th Avenue S.W., Calgary, Alberta, Canada, T2P 2V6.


			Percentage of
	Number of Shares		Shares
	Beneficially Owned		Outstanding
Reginald J. Greenslade (1)		302,268		2.02	%
Thomas J. Jacobsen (2)		407,716		2.73	%
Alan F. Williams (3)		2,549		0.02	%
David C. Ho	Nil			0.00	%
Ludwig Gierstorfer		27,000		0.18	%
Justin W. Yorke (4)		8,100		0.05	%
Horst H. Engel		1,000		0.00	%

All directors and executive officers as a group (eight persons)		748,633		5.00	%


(1)		Mr. Greenslade’s beneficial ownership includes 150,000 shares held in the name of his wife and 2,268 shares held by Olympia Trust Company (“OTC”) as trustee of our Stock Savings Plan.

(2)		Mr. Jacobsen’s beneficial ownership is attributable to 407,716 shares held in Wells Gray Resorts and Resources Ltd., a private company controlled by him and 4,216 shares held by OTC as trustee of our Stock Savings Plan.

(3)		Mr. Williams’ beneficial ownership is attributable to 2,549 shares held by OTC as trustee of our Stock Savings Plan.

(4)		Mr. Yorke’s beneficial ownership is attributable to 8,100 shares held by the San Gabriel Fund, which he controls.

Item 7. Major Shareholders and Related Party Transactions

To the best of our knowledge, JED is not directly or indirectly controlled by another corporation or the government of Canada or any other government. Our management believes that no single person or entity holds a controlling interest in our share capital. Major shareholders do not have different voting rights. As of June 26, 2006, 27 record holders in the United States held approximately 75% of our share capital.

Related Party Transactions

Under a 2^nd Amended and Restated Agreement of Business Principles, properties acquired by Enterra will be contract operated and drilled by JMG, if they are exploration properties, and contract operated and drilled by JED if they are development projects. Exploration of the properties will be done by JMG, which will pay 100% of the exploration costs to earn a 70% working interest in the properties. If JMG discovers commercially viable reserves on the exploration properties, Enterra will have the right to purchase 80% of JMG’s working interest in the properties at a fair value as determined by independent engineers. Should Enterra elect to have JED develop the properties, development will be done by JED, which will pay 100% of the development costs to earn 70% of the interests of both JMG and Enterra. Enterra will have a first right to purchase assets developed by JED.

Under Technical Services Agreements between JED and Enterra, and JED and JMG, both the Company and Enterra provide operational, technical and administrative services in connection with the management, development and exploitation and operation of the assets of JED, Enterra and JMG. Each entity provides these services on an expense re-imbursement basis based on the monthly capital activity and production levels relative to the combined capital activity and production levels of all three companies. For the year ended December 31, 2005, the Company charged general and administrative expenses and field operating expenses to Enterra of $5,112,744. The total outstanding from Enterra at December 31, 2005 was $6,205,676 (December 31, 2004 — $1,796,632). Effective January 1, 2006, both Technical Services Agreements were terminated.

On December 23, 2004, the Company loaned $1,992,032 (Cdn $2,400,000) to Enterra, a joint venture partner that the Company’s Chairman was also Chairman of the Board. The loan was originally repayable on or before June 29, 2005, however, the term of the loan has been extended indefinitely. The revised terms of the loan call for interest to be calculated at rate of 10% per annum. During the year ended December 31, 2005, the Company loaned additional funds of $8,576,797 under the same terms of which Enterra repaid $3,707,775.

The total outstanding from Enterra, including accrued interest, under the promissory note at December 31, 2005 was $6,861,054 (December 31, 2004 — $1,992,032). Subsequent to year end, the entire loan together with accrued interest was repaid in full.

In August 2004, the Company acquired 250,000 common shares of JMG, a private company at the time of the Company’s investment, representing approximately 11% equity interest in the total voting share capital of JMG at that time (and 100% of the Common Stock), for cash consideration of $1,000,000. In August 2005, JMG completed its initial public offering in August of 2005 which reduced the Company’s ownership in JMG to approximately 6%. The Company is represented with two of the five seats on the JMG Board of Directors. The Company’s investment in JMG is being accounted for using the equity method. At December 31, 2004, the Company owned 100% of the common shares of JMG and was required to include 100% of the equity loss of JMG for the period then ended. As the loss incurred by JMG for the period ended December 31, 2004 exceeded JED’s net investment, the Company reduced its net investment to zero. However, as JED has not guaranteed any obligations or is not committed to any

further financial support, no additional equity losses on the JMG investment has been recorded. During the year ended December 31, 2005, the Company entered into the following transactions with JMG:

JED charged JMG for certain general and administrative services and oil and gas equipment in the amount of $711,134 (2004 — $325,811). These services were provided at standard industry rates for similar services.

In consideration for the assignment of JED’s interests in certain oil and gas properties, the Company charged JMG for drilling and other costs related to those properties in the amount $85,085 for the year ended December 31, 2005, on a cost recovery basis.

In connection with these transactions the total amount receivable from JMG at December 31, 2005 was $401,142 (December 31, 2004 — $376,855). Subsequent to year-end, this amount was repaid in full.

On January 28, 2004, pursuant to a farm-in/joint venture agreement signed in January 2004 with Enterra Energy Corp., the Company advanced Enterra $12,832,125 (Cdn $17,000,000). The advance was subsequently repaid on June 29, 2004 together with accrued interest of $231,043 at an effective interest rate of 4.39%. Due to the strengthening of the Canadian dollar relative to the United States dollars, when the receipt of funds was translated from the operating currency of Canadian dollars to the reporting currency of United States dollars, a cash inflow of $12,636,587 was recorded on the consolidated statement of cash flows, which resulted in cash used in financing activities of $195,538.

At December 31, 2004, due from related party is comprised of $5,931 due from a company that is controlled by an officer and director of the Company. These services were provided at standard industry rates for similar services. The entire amount was paid in full in 2005.

Interests of Experts and Counsel

Not applicable.

Item 8. Financial Information

Consolidated Financial Statements and Other Financial Information

See Item 18.

Significant Changes

None.

Item 9. The Offer and Listing

Offer and Listing details

Not applicable, except for Item 9A (4).

Price Range of Common Stock and Trading Markets

JED’s shares commenced trading on the American Stock Exchange (“Amex”) under the symbol “JDO” on April 6, 2004. The following table sets forth the bid prices, in US dollars, as reported by the Amex and adjusted for the 3:2 stock split on October 10, 2005, for the periods shown.


	American Stock
	Exchange/Amex
	(US$)
	High		Low
Five most recent full fiscal years:
Year ended December 31, 2005		21.50		9.44
Year ended December 31, 2004		14.77		9.46

Quarter ended March 31, 2006		16.76		11.00

Year ended December 31, 2005:
Quarter ended December 31, 2005		19.33		11.65
Quarter ended September 30, 2005		21.50		15.93
Quarter ended June 30, 2005		17.13		10.11
Quarter ended March 31, 2005		12.73		9.44

Year ended December 31, 2004:
Quarter ended December 31, 2004		14.77		11.62
Quarter ended September 30, 2004		12.74		10.80
Quarter ended June 30, 2004		13.20		9.46
Quarter ended March 31, 2004	NA		NA

Six most recent months ended:
May 2006		17.60		12.50
April 2006		16.74		14.90
March 2006		16.76		11.00
February 2006		15.60		12.82
January 2006		16.02		13.05
December 2005		16.50		11.00

Plan of Distribution

Not applicable.

Markets

See Item 9.A.

Selling Shareholders

Not applicable.

Dilution

Not applicable.

Expense of the Issue

Not applicable.

Item 10. Additional Information

Share Capital

Description of Securities

The authorized share capital of JED consists of an unlimited number of Common Shares, and an unlimited number of Preferred Shares issuable in series, of which 8,000,000 Series A Preferred Shares and 2,200,000 Series B Preferred Shares are authorized. At March 31, 2006 there were 14,715,260 Common Shares issued and outstanding, 1,158,751 Common Shares reserved for issuance pursuant to stock options, 81,000 Common Shares reserved for issuance pursuant to share purchase warrants, 1,000,000 Common Shares are reserved for the conversion of the outstanding Secured Subordinated Convertible Note and no Preferred Shares issued and outstanding.

On September 28, 2005, the shareholders of the Company approved a 3-for-2 stock split of the Company’s common shares. The record date of the stock split was October 10, 2005 and the shares began trading on the American Stock Exchange on a post split basis on October 12, 2005.

Articles of Incorporation and By-laws

We were incorporated in Alberta, Canada. Our Articles of Incorporation and By-laws provide no restrictions as to the nature of our business operations. Under Alberta law, a director must inform us, at a meeting of the Board of Directors, of any interest in a material contract or proposed material contract with us. Directors may not vote in respect of any such contracts made with us or in any such contract in which a director is interested, and such directors shall not be counted for purposes of determining a quorum. However, these provisions do not apply to (i) an arrangement by way of security for money lent to or obligations undertaken by them, (ii) a contract relating primarily to their remuneration as a director, officer, employee or agent, (iii) a contract for indemnity or insurance on behalf of a director as allowed under the Alberta law, or (iv) a contract with an affiliate.

We are authorized to issue an unlimited number of common and preferred shares. Our stockholders have no rights to share in our profits, are subject to no redemption or sinking fund provisions, have no liability for further capital calls and are not subject to any discrimination due to number of shares owned. By not more than 50 days or less than seven days in advance of a dividend, the Board of Directors may establish a record date for the determination of the persons entitled to such dividend.

The rights of holders of our common stock can be changed at any time in a stockholder meeting where the modifications are approved by 66²/3% of the shares represented by proxy or in person at a meeting at which a quorum exists.

All holders of our common stock are entitled to vote at annual or special meetings of stockholders, provided that they were stockholders as of the record date. The record date for stockholder meetings may precede the meeting date by no more than 50 days and not less than 21 days, provided that notice by way of advertisement is given to stockholders at least seven days before such record date. Notice of the time and place of meetings of stockholders may not be less than 21 or greater than 50 days prior to the date of the meeting. There are no:

	•		limitations on share ownership;

	•		provisions of the Articles or by-laws that would have the effect of delaying, deferring or preventing a change of control of our company;

	•		by-law provisions that govern the ownership threshold above which stockholder ownership must be disclosed; and

	•		conditions imposed by the Articles or by-laws governing changes in capital, but Alberta law requires any changes to the terms of share capital be approved by 66²/3% of the shares represented by proxy or in person at a stockholders’ meeting convened for that purpose at which a quorum exists.

Common Stock

Each holder of record of common stock is entitled to one vote for each share held on all matters properly submitted to the stockholders for their vote, except matters which are required to be voted on as a particular class or series of stock. Cumulative voting for directors is not permitted.

Holders of outstanding shares of common stock are entitled to those dividends declared by the Board of Directors out of legally available funds. In the event of liquidation, dissolution or winding up our affairs, holders of common stock are entitled to receive, pro rata, our net assets available after provision has been made for the preferential rights of the holders of preferred stock. Holders of outstanding common stock have no preemptive, conversion or redemption rights. All of the issued and outstanding shares of common stock are, and all unissued shares of common stock, when offered and sold will be, duly authorized, validly issued, fully paid and non-assessable. To the extent

that additional shares of common stock may be issued in the future, the relative interests of the then existing stockholders may be diluted. There were 14,630,256 common shares issued and outstanding at December 31, 2005.

Preferred Stock

Our Board is authorized to issue from time to time, without stockholder approval, in one or more designated series, unissued shares of preferred stock with such dividends, redemption, conversion and exchange provisions as may be provided by the Board of Directors with regard to such particular series. Any series of preferred stock may possess voting, dividend, liquidation and redemption rights superior to those of the common stock.

The rights of the holders of common stock will be subject to and may be adversely affected by the rights of the holders of any preferred stock that we may issue in the future. Our issuance of a new series of preferred stock could make it more difficult for a third party to acquire, or discourage a third party from acquiring, our outstanding shares of common stock and make removal of the Board more difficult.

A total of 7,600,000 shares of Series A Convertible Preferred Stock were issued pursuant to a private placement completed in December 2003. The Series A Convertible Preferred Stock is voting, carries no dividend and was all converted into an equal number of shares of common stock in April 2004. At December 31, 2005 no preferred shares were issued or outstanding.

Series B Preferred Shares consisting of an authorized 2,200,000 shares were created May 26, 2006. The Series B Preferred Stock is non-voting, carries dividends of 10% per annum and is convertible to common stock on a one-for-one basis at any time at the holder’s option. A total of 979,663 shares of Series B Preferred Stock were issued pursuant to a private placement completed in June 2006. The Series B Convertible Preferred Shares will be redeemed by the Company on February 1, 2008 if not converted earlier. Each quarter, holders may elect to receive their dividends in common shares of JED, valued at the trailing fifteen day volume weighted average trading price for the common shares prior to the record date for the dividend. The outstanding principal may be converted at any time at the holder’s option into common shares of the Company at a conversion price of US$16.00 per share. In the event of certain new equity issues by the Company, holders of the Series B Convertible Preferred Shares shall have a right of first refusal to participate, on a pro rata basis, in such new issues.

Convertible Notes

JED recently closed a private placement of US$34,325,000 of 10% Senior Subordinated Convertible Notes. All documents for the closing are dated May 31, 2006 and funds were released from escrow on June 1, 2006. The Convertible Notes bear interest at the rate of 10% per annum, payable quarterly, and mature on February 1, 2008. The outstanding principle and interest may be converted at any time at the holder’s option into common shares of the Company at a conversion price of US$16.00 per share. Notes outstanding on the maturity date will be redeemed by the Company. There are penalty provisions if the Company does not comply with the terms of the Convertible Notes. In the event of certain new equity issues by the Company, holders of the Convertible Notes have a right of first refusal to participate, on a pro rata basis, in such new issues. The Convertible Notes are unsecured and are subordinated to the credit facility granted by JED’s senior commercial financial institution.

In August 2005 the Company issued a similar 10% Senior Subordinated Convertible Note in the amount of $20 million, of which $1 million has been converted to common shares. In connection with the current private placement, the 2005 note was amended to have the identical terms of the Convertible Notes in the 2006 private placement, including the reduction of the conversion price into JED common shares to $16.00 per share from $20.00 per share. In addition the holder of the 2005 note was granted the right to convert the outstanding principle amount to Series B Convertible Preferred shares. It is expected that a substantial portion of the 2005 note will be converted to the Series B Convertible Preferred shares.

Shares Eligible for Future Sale

Future sales of substantial amounts of our common stock in the public market or even the perception that such sales may occur, could adversely affect the market price for our common stock and could impair our future ability to raise capital through an offering of our equity securities.

At December 31, 2005 there were 1,291,251 options outstanding under the plan to purchase an equal number of shares of common stock. The outstanding options are exercisable at a weighted average price per share of $8.49.

Indemnification of Executive Officers and Directors

We have agreed to indemnify our executive officers and directors for all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment, reasonably incurred by them in respect of any civil, criminal or administrative action or proceeding to which they are made a party by reason of being or having been a director or officer, if (a) they acted honestly and in good faith with a view to our best interests, and (b) in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, they had reasonable grounds for believing that their conduct was lawful.

Material Contracts

The Company has entered into material contracts that are other than in the ordinary course of business during the previous two years, other than as described elsewhere in this Form 20-F, as follows:

In August 2005, JED issued a Senior Subordinated Convertible Note in the amount of $20 million to an arms-length California limited partnership. This Note bears interest at the rate of 10% per annum, is due February 1, 2008 and is convertible at the holder’s option into one million common shares for the principal amount and the conversion of accrued interest into common shares on the basis of $20.00 per share.

In July 2005, JED entered into a Loan Agreement and Promissory Note with an arms length party whereby JED advanced the party $4,288,165 for the construction of drilling equipment. In return for the note, the Company will be provided with five dedicated drilling rigs for a period of three years. The terms of each contract call for a minimum requirement of 250 operating days per year for a total of 750 operating days over the three-year term for

each drilling rig. The advance will be repaid to JED through payment from a portion of the drilling rigs daily charges from the date of rig delivery until paid in full. The note is issued by a General Security Agreement over all assets of the third party, bears no interest and has no set repayment schedule.

In connection with the private placement of the convertible notes in May 2006, we entered into a Registration Rights Agreement dated May 31, 2006 with the purchasers of the Notes (the “Registration Rights Agreement”). Pursuant to the terms of the Registration Rights Agreement, we have agreed to prepare and file with the Securities and Exchange Commission (the “SEC”) a registration statement for the purpose of registering for resale all of the common shares of the Company issuable upon conversion of the Notes. We are obligated to file such registration statement no later than July 30, 2006, to have the SEC declare such registration statement effective no later than September 28, 2006 and, subject to certain exceptions, to keep such registration statement effective at all times until the all shares registered thereby have been sold thereunder or may be resold pursuant to rule 144(k) under the Securities Act of 1933, as amended. We are obligated to pay certain liquidated damages in the event in fails to satisfy these registration obligations.

In connection with the private placement of the Series B Convertible Preferred Stock, we entered into a Registration Rights Agreement with the purchasers of the preferred shares (the “Registration Rights Agreement”). Pursuant to the terms of the Registration Rights Agreement, we have agreed to prepare and file with the Securities and Exchange Commission (the “SEC”) a registration statement for the purpose of registering for resale all of the common shares of the Company issuable upon conversion of the preferred shares. The Company is obligated to file such registration statement no later than August 9, 2006, to have the SEC declare such registration statement effective no later than October 6, 2006 and, subject to certain exceptions, to keep such registration statement effective at all times until the all shares registered thereby have been sold thereunder or may be resold pursuant to rule 144(k) under the Securities Act of 1933, as amended. We are obligated to pay certain liquidated damages in the event in fails to satisfy these registration obligations.

Exchange Controls

There is no law or governmental decree or regulation in Canada that restricts the export or import of capital, or affects the remittance of dividends, interest or other payments to non-resident holders of our voting shares, other than withholding tax requirements.

There is no limitation imposed by Canadian law or by our Articles or our other charter documents on the right of a non-resident to hold or vote voting shares, other than as provided by the Investment Canada Act, the North American Free Trade Agreement Implementation Act (Canada) and the World Trade Organization Agreement Implementation Act.

The Investment Canada Act requires notification and, in certain cases, advance review and approval by the government of Canada of the acquisition by a non-Canadian of control of a Canadian business, all as defined in the Investment Canada Act. Generally, the threshold for review will be higher in monetary terms for a member of the World Trade Organization or North American Free Trade Agreement.

Taxation

U.S. Federal Income Tax Consequences

The following is a summary of the anticipated material U.S. federal income tax consequences to a U.S. Holder (as defined below) arising from and relating to the acquisition, ownership, and disposition of common shares of the Company (“Common Shares”).

This summary is for general information purposes only and does not purport to be a complete analysis or listing of all potential U.S. federal income tax consequences that may apply to a U.S. Holder as a result of the acquisition, ownership, and disposition of Common Shares. In addition, this summary does not take into account the individual facts and circumstances of any particular U.S. Holder that may affect the U.S. federal income tax consequences of the acquisition, ownership, and disposition of Common Shares. Accordingly, this summary is not intended to be, and should not be construed as, legal or U.S. federal income tax advice with respect to any U.S. Holder. Each U.S. Holder should consult its own financial advisor, legal counsel, or accountant regarding the U.S. federal, U.S. state and local, and foreign tax consequences of the acquisition, ownership, and disposition of Common Shares.

Scope of this Disclosure

Authorities

This summary is based on the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations (whether final, temporary, or proposed), published rulings of the Internal Revenue Service (“IRS”), published administrative positions of the IRS, the Convention Between Canada and the United States of America with Respect to Taxes on Income and on Capital, signed September 26, 1980, as amended (the “Canada-U.S. Tax Convention”), and U.S. court decisions that are applicable and, in each case, as in effect and available, as of the date of this Annual Report. Any of the authorities on which this summary is based could be changed in a material and adverse manner at any time, and any such change could be applied on a retroactive basis. This summary does not discuss the potential effects, whether adverse or beneficial, of any proposed legislation that, if enacted, could be applied on a retroactive basis.

U.S. Holders

For purposes of this summary, a “U.S. Holder” is a beneficial owner of Common Shares that, for U.S. federal income tax purposes, is (a) an individual who is a citizen or resident of the U.S., (b) a corporation, or any other entity classified as a corporation for U.S. federal income tax purposes, that is created or organized in or under the

laws of the U.S. or any state in the U.S., including the District of Columbia, (c) an estate if the income of such estate is subject to U.S. federal income tax regardless of the source of such income, or (d) a trust if (i) such trust has validly elected to be treated as a U.S. person for U.S. federal income tax purposes or (ii) a U.S. court is able to exercise primary supervision over the administration of such trust and one or more U.S. persons have the authority to control all substantial decisions of such trust.

Non-U.S. Holders

For purposes of this summary, a “non-U.S. Holder” is a beneficial owner of Common Shares other than a U.S. Holder. This summary does not address the U.S. federal income tax consequences of the acquisition, ownership, and disposition of Common Shares to non-U.S. Holders. Accordingly, a non-U.S. Holder should consult its own financial advisor, legal counsel, or accountant regarding the U.S. federal, U.S. state and local, and foreign tax consequences (including the potential application of and operation of any tax treaties) of the acquisition, ownership, and disposition of Common Shares.

U.S. Holders Subject to Special U.S. Federal Income Tax Rules Not Addressed

This summary does not address the U.S. federal income tax consequences of the acquisition, ownership, and disposition of Common Shares to U.S. Holders that are subject to special provisions under the Code, including the following U.S. Holders: (a) U.S. Holders that are tax-exempt organizations, qualified retirement plans, individual retirement accounts, or other tax-deferred accounts; (b) U.S. Holders that are financial institutions, insurance companies, real estate investment trusts, or regulated investment companies; (c) U.S. Holders that are broker-dealers, dealers, or traders in securities or currencies that elect to apply a mark-to-market accounting method; (d) U.S. Holders that have a “functional currency” other than the U.S. dollar; (e) U.S. Holders that are liable for the alternative minimum tax under the Code; (f) U.S. Holders that own Common Shares as part of a straddle, hedging transaction, conversion transaction, constructive sale, or other arrangement involving more than one position; (g) U.S. Holders that acquired Common Shares in connection with the exercise of employee stock options or otherwise as compensation for services; (h) U.S. Holders that hold Common Shares other than as a capital asset within the meaning of Section 1221 of the Code; or (i) U.S. Holders that own, directly or indirectly, 10% or more, by voting power or value, of the outstanding shares of the Company. U.S. Holders that are subject to special provisions under the Code, including U.S. Holders described immediately above, should consult their own financial advisor, legal counsel or accountant regarding the U.S. federal, U.S. state and local, and foreign tax consequences of the acquisition, ownership, and disposition of Common Shares.

If an entity that is classified as partnership (or “pass-through” entity) for U.S. federal income tax purposes holds Common Shares, the U.S. federal income tax consequences to such partnership (or “pass-through” entity) and the partners of such partnership (or owners of such “pass-through” entity) generally will depend on the activities of the partnership (or “pass-through” entity) and the status of such partners (or owners). Partners of entities that are classified as partnerships (or owners of “pass-through” entities) for U.S. federal income tax purposes should consult their own financial advisor, legal counsel or accountant regarding the U.S. federal income tax consequences of the acquisition, ownership, and disposition of Common Shares.

Tax Consequences Other than U.S. Federal Income Tax Consequences Not Addressed

This summary does not address the U.S. state and local, U.S. federal estate and gift, or foreign tax consequences to U.S. Holders of the acquisition, ownership, and disposition of Common Shares. Each U.S. Holder should consult its own financial advisor, legal counsel, or accountant regarding the U.S. state and local, U.S. federal estate and gift, and foreign tax consequences of the acquisition, ownership, and disposition of Common Shares. (See “Taxation—Canadian Federal Income Tax Consequences “ below).

U.S. Federal Income Tax Consequences of the Acquisition, Ownership, and Disposition of Common Shares

Distributions on Common Shares

General Taxation of Distributions

A U.S. Holder that receives a distribution, including a constructive distribution, with respect to the Common Shares will be required to include the amount of such distribution in gross income as a dividend (without reduction for any Canadian income tax withheld from such distribution) to the extent of the current or accumulated “earnings and profits” of the Company. To the extent that a distribution exceeds the current and accumulated “earnings and profits” of the Company, such distribution will be treated (a) first, as a tax-free return of capital to the extent of a U.S. Holder’s tax basis in the Common Shares and, (b) thereafter, as gain from the sale or exchange of such Common Shares. (See more detailed discussion at “Disposition of Common Shares” below).

Reduced Tax Rates for Certain Dividends

For taxable years beginning after December 31, 2002 and before January 1, 2009, a dividend paid by the Company generally will be taxed at the preferential tax rates applicable to long-term capital gains if (a) the Company is a “qualified foreign corporation” (as defined below), (b) the U.S. Holder receiving such dividend is an individual, estate, or trust, and (c) such dividend is paid on Common Shares that have been held by such U.S. Holder for at least 61 days during the 121-day period beginning 60 days before the “ex-dividend date” (i.e., the first date that a purchaser of such Common Shares will not be entitled to receive such dividend).

The Company generally will be a “qualified foreign corporation” under Section 1(h)(11) of the Code (a “QFC”) if (a) the Company is incorporated in a possession of the U.S., (b) the Company is eligible for the benefits of the Canada-U.S. Tax Convention, or (c) the Common Shares are readily tradable on an established securities market in the U.S. However, even if the Company satisfies one or more of such requirements, the Company will not be treated as a QFC if the Company is a “passive foreign investment company” (as defined below) for the taxable year during which the Company pays a dividend or for the preceding taxable year. In 2003, the U.S. Department of the Treasury (the “Treasury”) and the IRS announced that they intended to issue Treasury Regulations providing procedures for a foreign corporation to certify that it is a QFC. Although these Treasury Regulations were not issued in 2004, the Treasury and the IRS have confirmed their intention to issue these Treasury Regulations. It is expected that these Treasury Regulations will obligate persons required to file information returns to report a distribution with respect to a foreign security issued by a foreign corporation as a dividend from a QFC if the foreign corporation has, among other things, certified under penalties of perjury that the foreign corporation was not a “passive foreign investment company” for the taxable year during which the foreign corporation paid the dividend or for the preceding taxable year.

As discussed below, the Company does not believe that it was a “passive foreign investment company” for the taxable year ended December 31, 2005, and does not expect that it will be a “passive foreign investment company” for the taxable year ending December 31, 2006. (See more detailed discussion at “Additional Rules that May Apply to U.S. Holders” below). However, there can be no assurance that the IRS will not challenge the determination made by the Company concerning its “passive foreign investment company” status or that the Company will not be a “passive foreign investment company” for the current or any future taxable year. Accordingly, although the Company expects that it may be a QFC, there can be no assurances that the IRS will not challenge the determination made by the Company concerning its QFC status, that the Company will be a QFC for the current or any future taxable year, or that the Company will be able to certify that it is a QFC in accordance with the certification procedures issued by the Treasury and the IRS.

If the Company is not a QFC, a dividend paid by the Company to a U.S. Holder, including a U.S. Holder that is an individual, estate, or trust, generally will be taxed at ordinary income tax rates (and not at the preferential tax rates applicable to long-term capital gains). The dividend rules are complex, and each U.S. Holder should consult its own financial advisor, legal counsel, or accountant regarding the dividend rules.

Distributions Paid in Foreign Currency

The amount of a distribution paid to a U.S. Holder in foreign currency generally will be equal to the U.S. dollar value of such distribution based on the exchange rate applicable on the date of receipt. A U.S. Holder that does not convert foreign currency received as a distribution into U.S. dollars on the date of receipt generally will have a tax basis in such foreign currency equal to the U.S. dollar value of such foreign currency on the date of receipt. Such a U.S. Holder generally will recognize ordinary income or loss on the subsequent sale or other taxable disposition of such foreign currency (including an exchange for U.S. dollars).

Dividends Received Deduction

Dividends paid on the Common Shares generally will not be eligible for the “dividends received deduction.” The availability of the dividends received deduction is subject to complex limitations that are beyond the scope of this discussion, and a U.S. Holder that is a corporation should consult its own financial advisor, legal counsel, or accountant regarding the dividends received deduction.

Disposition of Common Shares

A U.S. Holder will recognize gain or loss on the sale or other taxable disposition of Common Shares in an amount equal to the difference, if any, between (a) the amount of cash plus the fair market value of any property received and (b) such U.S. Holder’s tax basis in the Common Shares sold or otherwise disposed of. Any such gain or loss generally will be capital gain or loss, which will be long-term capital gain or loss if the Common Shares are held for more than one year. Gain or loss recognized by a U.S. Holder on the sale or other taxable disposition of Common Shares generally will be treated as “U.S. source” for purposes of applying the U.S. foreign tax credit rules. (See more detailed discussion at “Foreign Tax Credit” below).

Preferential tax rates apply to long-term capital gains of a U.S. Holder that is an individual, estate, or trust. There are currently no preferential tax rates for long-term capital gains of a U.S. Holder that is a corporation. Deductions for capital losses and net capital losses are subject to complex limitations under the Code. For a U.S. Holder that is an individual, estate, or trust, capital losses may be used to offset capital gains and up to U.S.$3,000 of ordinary income. An unused capital loss of a U.S. Holder that is an individual, estate, or trust generally may be carried forward to subsequent taxable years, until such net capital loss is exhausted. For a U.S. Holder that is a corporation, capital losses may be used to offset capital gains, and an unused capital loss generally may be carried back three years and carried forward five years from the year in which such net capital loss is recognized.

Foreign Tax Credit

A U.S. Holder who pays (whether directly or through withholding) Canadian income tax with respect to dividends paid on the Common Shares generally will be entitled, at the election of such U.S. Holder, to receive either a deduction or a credit for such Canadian income tax paid. Generally, a credit will reduce a U.S. Holder’s U.S. federal income tax liability on a dollar-for-dollar basis, whereas a deduction will reduce a U.S. Holder’s income subject to U.S. federal income tax. This election is made on a year-by-year basis and applies to all foreign taxes paid (whether directly or through withholding) by a U.S. Holder during a year.

Complex limitations apply to the foreign tax credit, including the general limitation that the credit cannot exceed the proportionate share of a U.S. Holder’s U.S. federal income tax liability that such U.S. Holder’s “foreign source” taxable income bears to such U.S. Holder’s worldwide taxable income. In applying this limitation, a U.S. Holder’s various items of income and deduction must be classified, under complex rules, as either “foreign source” or “U.S. source.” In addition, this limitation is calculated separately with respect to specific categories of income (including “passive income,” “high withholding tax interest,” “financial services income,” “general income,” and certain other categories of income). Dividends paid by the Company generally will constitute “foreign source” income and generally will be categorized as “passive income” or, in the case of certain U.S. Holders, “financial services income.” However, for taxable years beginning after December 31, 2006, the foreign tax credit limitation categories are reduced to “passive category income” and “general category income” (and the other categories of income, including “financial services income,” are eliminated). The foreign tax credit rules are complex, and each U.S. Holder should consult its own financial advisor, legal counsel, or accountant regarding the foreign tax credit rules.

Information Reporting; Backup Withholding Tax

Payments made within the U.S., or by a U.S. payor or U.S. middleman, of dividends on, and proceeds arising from certain sales or other taxable dispositions of, Common Shares generally will be subject to information reporting and backup withholding tax, at the rate of 28%, if a U.S. Holder (a) fails to furnish such U.S. Holder’s correct U.S. taxpayer identification number (generally on Form W-9), (b) furnishes an incorrect U.S. taxpayer identification number, (c) is notified by the IRS that such U.S. Holder has previously failed to properly report items subject to backup withholding tax, or (d) fails to certify, under penalty of perjury, that such U.S. Holder has furnished its

correct U.S. taxpayer identification number and that the IRS has not notified such U.S. Holder that it is subject to backup withholding tax. However, U.S. Holders that are corporations generally are excluded from these information reporting and backup withholding tax rules. Any amounts withheld under the U.S. backup withholding tax rules will be allowed as a credit against a U.S. Holder’s U.S. federal income tax liability, if any, or will be refunded, if such U.S. Holder furnishes required information to the IRS. Each U.S. Holder should consult its own financial advisor, legal counsel, or accountant regarding the information reporting and backup withholding tax rules.

Additional Rules that May Apply to U.S. Holders

If the Company is a “controlled foreign corporation” or a “passive foreign investment company” (each as defined below), the preceding sections of this summary may not describe the U.S. federal income tax consequences to U.S. Holders of the acquisition, ownership, and disposition of Common Shares.

Controlled Foreign Corporation

The Company generally will be a “controlled foreign corporation” under Section 957 of the Code (a “CFC”) if more than 50% of the total voting power or the total value of the outstanding shares of the Company is owned, directly or indirectly, by citizens or residents of the U.S., domestic partnerships, domestic corporations, domestic estates, or domestic trusts (each as defined in Section 7701(a)(30) of the Code), each of which own, directly or indirectly, 10% or more of the total voting power of the outstanding shares of the Company (a “10% Shareholder”).

If the Company is a CFC, a 10% Shareholder generally will be subject to current U.S. federal income tax with respect to (a) such 10% Shareholder’s pro rata share of the “subpart F income” (as defined in Section 952 of the Code) of the Company and (b) such 10% Shareholder’s pro rata share of the earnings of the Company invested in “United States property” (as defined in Section 956 of the Code). In addition, under Section 1248 of the Code, any gain recognized on the sale or other taxable disposition of Common Shares by a U.S. Holder that was a 10% Shareholder at any time during the five-year period ending with such sale or other taxable disposition generally will be treated as a dividend to the extent of the “earnings and profits” of the Company that are attributable to such Common Shares. If the Company is both a CFC and a “passive foreign investment company” (as defined below), the Company generally will be treated as a CFC (and not as a “passive foreign investment company”) with respect to any 10% Shareholder.

The Company does not believe that it has previously been, or currently is, a CFC. However, there can be no assurance that the Company will not be a CFC for the current or any future taxable year.

Passive Foreign Investment Company

The Company generally will be a “passive foreign investment company” under Section 1297 of the Code (a “PFIC”) if, for a taxable year, (a) 75% or more of the gross income of the Company for such taxable year is passive income or (b) on average 50% or more of the assets held by the Company either produce passive income or are held for the production of passive income, based on the fair market value of such assets (or on the adjusted tax basis of such assets, if the Company is not publicly traded and either is a “controlled foreign corporation” or makes an election). “Passive income” includes, for example, dividends, interest, certain rents and royalties, certain gains from the sale of stock and securities, and certain gains from commodities transactions. However, for transactions entered into on or before December 31, 2004, gains arising from the sale of commodities generally are excluded from passive income if (a) a foreign corporation holds the commodities directly (and not through an agent or independent contractor) as inventory or similar property or as dealer property, (b) such foreign corporation incurs substantial expenses related to the production, processing, transportation, handling, or storage of the commodities, and (c) gross receipts from sales of commodities that satisfy the requirements of clauses (a) and (b) constitute at least 85% of the total gross receipts of such foreign corporation. For transactions entered into after December 31, 2004, gains arising from the sale of commodities generally are excluded from passive income if substantially all of a foreign corporation’s commodities are (a) stock in trade of such foreign corporation or other property of a kind which would properly be included in inventory of such foreign corporation, or property held by such foreign corporation primarily for sale to customers in the ordinary course of business, (b) property used in the trade or business of such foreign corporation that would be subject to the allowance for depreciation under Section 167 of the Code, or (c) supplies of a type regularly used or consumed by such foreign corporation in the ordinary course of its trade or business.

For purposes of the PFIC income test and assets test described above, if the Company owns, directly or indirectly, 25% or more of the total value of the outstanding shares of another foreign corporation, the Company will be treated as if it (a) held a proportionate share of the assets of such other foreign corporation and (b) received directly a proportionate share of the income of such other foreign corporation. In addition, for purposes of the PFIC income test and asset test described above, “passive income” does not include any interest, dividends, rents, or royalties that are received or accrued by the Company from a “related person” (as defined in Section 954(d)(3) of the Code), to the extent such items are properly allocable to the income of such related person that is not passive income.

If the Company is a PFIC, the U.S. federal income tax consequences to a U.S. Holder of the acquisition, ownership, and disposition of Common Shares will depend on whether such U.S. Holder makes an election to treat the Company as a “qualified electing fund” or “QEF” under Section 1295 of the Code (a “QEF Election”) or a mark-to-market election under Section 1296 of the Code (a “Mark-to-Market Election”). A U.S. Holder that does not make either a QEF Election or a Mark-to-Market Election will be referred to in this summary as a “Non-Electing U.S. Holder.”

Under Section 1291 of the Code, any gain recognized on the sale or other taxable disposition of Common Shares, and any “excess distribution” (as defined in Section 1291(b) of the Code) paid on the Common Shares, must be ratably allocated to each day in a Non-Electing U.S. Holder’s holding period for the Common Shares. The amount of any such gain or excess distribution allocated to prior years of such Non-Electing U.S. Holder’s holding period for the Common Shares generally will be subject to U.S. federal income tax at the highest tax applicable to ordinary income in each such prior year. A Non-Electing U.S. Holder will be required to pay interest on the resulting tax liability for each such prior year, calculated as if such tax liability had been due in each such prior year.

A U.S. Holder that makes a QEF Election generally will not be subject to the rules of Section 1291 of the Code discussed above. However, a U.S. Holder that makes a QEF Election generally will be subject to U.S. federal income tax on such U.S. Holder’s pro rata share of (a) the “net capital gain” of the Company, which will be taxed as long-term capital gain to such U.S. Holder, and (b) and the “ordinary earnings” of the Company, which will be taxed as ordinary income to such U.S. Holder. A U.S. Holder that makes a QEF Election will be subject to U.S. federal income tax on such amounts for each taxable year in which the Company is a PFIC, regardless of whether such amounts are actually distributed to such U.S. Holder by the Company.

A U.S. Holder that makes a Mark-to-Market Election generally will not be subject to the rules of Section 1291 of the Code discussed above. A U.S. Holder may make a Mark-to-Market Election only if the Common Shares are “marketable stock” (as defined in Section 1296(e) of the Code). A U.S. Holder that makes a Mark-to-Market Election will include in gross income, for each taxable year in which the Company is a PFIC, an amount equal to the excess, if any, of (a) the fair market value of the Common Shares as of the close of such taxable year over (b) such U.S. Holder’s tax basis in such Common Shares. A U.S. Holder that makes a Mark-to-Market Election will, subject to certain limitations, be allowed a deduction in an amount equal to the excess, if any, of (a) such U.S. Holder’s adjusted tax basis in the Common Shares over (b) the fair market value of such Common Shares as of the close of such taxable year.

The Company does not believe that it was a PFIC for the taxable year ended December 31, 2005, and does not expect that it will be a PFIC for the taxable year ending December 31, 2006. However, the determination of whether the Company was, or will be, a PFIC for a taxable year depends, in part, on the application of complex U.S. federal income tax rules, which are subject to various interpretations. In addition, whether the Company will be a PFIC for the taxable year ending December 31, 2006 and each subsequent taxable year depends on the assets and income of the Company over the course of each such taxable year and, as a result, cannot be predicted with certainty as of the date of this Annual Report. Accordingly, there can be no assurance that the IRS will not challenge the determination made by the Company concerning its PFIC status or that the Company will not be a PFIC for the current or any future taxable year.

The PFIC rules are complex, and each U.S. Holder should consult its own financial advisor, legal counsel, or accountant regarding the PFIC rules and how the PFIC rules may affect the U.S. federal income tax consequences of the acquisition, ownership, and disposition of Common Shares.

Canadian Taxation

The following summary fairly describes, as of the date hereof, the principal Canadian federal income tax considerations under the Income Tax Act (Canada) (the “ITA”) generally applicable to a beneficial owner of Common Shares who is not and has not been or deemed to be resident in Canada for purposes of the ITA at any time while such Holder holds the Common Shares, is a resident of the U.S. for purposes of the Canada-U.S. Tax Convention , and who, for purposes of the ITA, at all relevant times:

	•		holds the Common Shares as capital property;

	•		does not have a “permanent establishment” or “fixed base” in Canada, as defined in the Canada-U.S. Tax Convention;

	•		does not use or hold (and is not deemed to use or hold) the Common Shares in carrying on a business in Canada for purposes of the ITA; and

	•		deals at arm’s length and is not affiliated with the Company within the meaning of the ITA

(a “Holder”).

Special rules, which are not discussed below, apply to “financial institutions” and “tax shelter investments” as defined in the ITA and to non-resident insurers carrying on an insurance business in Canada and elsewhere.

This summary is based upon the current provisions of the ITA, the regulations thereunder (the “Regulations”), the Canada-U.S. Tax Convention, all specific proposed amendments to the ITA or the Regulations publicly announced by or on behalf of the Canadian Minister of Finance prior to the date hereof, and the Company’s understanding of the current published administrative and assessing practices of the CRA. This summary does not otherwise take into account or anticipate any changes in law, whether by way of judicial, governmental or legislative decision or action, administrative practice nor does it take into account any income tax laws or considerations of any province or territory of Canada or any jurisdiction other than Canada, which may differ from the Canadian federal income tax consequences described in this document.

The Common Shares will generally constitute capital property to a Holder unless such Holder holds such Common Shares in the course of carrying on a business of trading or dealing in securities or has acquired such Common Shares in a transaction or transactions considered to be an adventure in the nature of trade.

Under the Canada-U.S. Tax Convention, dividends paid or credited, or deemed to be paid or credited, on the Common Shares to a Holder generally will be subject to Canadian withholding tax at the rate of 15% of the gross amount of those dividends. If a Holder is a corporation within the meaning of the Canada-U.S. Tax Convention and owns 10% or more of the Company’s voting stock, the rate is reduced from 15% to 5%.

Under the Canada-U.S. Tax Convention, dividends paid to religious, scientific, literary, educational or charitable organizations or certain pension, retirement or employee benefit organizations that have complied with administrative procedures specified by the CRA are exempt from the aforementioned Canadian withholding tax so long as such organization is resident in and exempt from tax in the U.S.

A Holder will only be subject to taxation in Canada under the ITA on capital gains realized by the Holder on a disposition or deemed disposition of the Common Shares if the such shares constitute “taxable Canadian property” within the meaning of the ITA at the time of the disposition or deemed disposition and the Holder is not afforded relief under the Canada-U.S. Tax Convention. In general, the Common Shares will not be “taxable Canadian property” to a Holder if, at the time of their disposition, they are listed on a stock exchange that is prescribed in the Regulations (which includes American Stock Exchange), unless:

•

at any time within the 60-month period immediately preceding the disposition or deemed disposition, the Holder, persons not dealing at arm’s length with the Holder, or the Holder together with such non-

			arm’s length persons, owned 25% or more of the issued shares of any class or series of the Company’s capital stock;
	•		the Holder was formerly resident in Canada and, upon ceasing to be a Canadian resident, elected under the ITA to have the Common Shares deemed to be “taxable Canadian property; or

	•		the Holder’s Common Shares were acquired in a tax deferred exchange in consideration for property that was itself “taxable Canadian property.”

If a Holder’s Common Shares are “taxable Canadian property,” such Holder will recognize a capital gain (or a capital loss) for the taxation year during which the Holder disposes, or is deemed to have disposed of, the Common Shares. Such capital gain (or capital loss) will be equal to the amount by which the proceeds of disposition exceed (or are less than) the Holder’s adjusted cost base of such Common Shares and any reasonable costs of making the disposition. One-half of any such capital gain (a “taxable capital gain”) must be included in income in computing the Holder’s income and one half of any such capital loss (an “allowable capital loss”) is generally deductible by the Holder from taxable capital gains arising in the year of disposition. To the extent a Holder has insufficient taxable capital gains in the current taxation year against which to apply an allowable capital loss, the deficiency will constitute a net capital loss for the current taxation year and may generally be carried back to any of the three preceding taxation years or carried forward to any future taxation year, to the extent and under the circumstances described in the ITA.

This summary is of a general nature only, is not exhaustive of all possible tax considerations applicable to an investor, and is not intended to be relied on as legal or tax advice or representations to any particular investor. Consequently, investors are urged to seek independent tax advice in respect of the consequences to them of the acquisition, ownership or disposition of Common Shares having regard to their particular circumstances.

Dividends and Paying Agents

Not applicable.

Statement by Experts

Not applicable.

Documents on Display

We are subject to the information and reporting requirements of the Securities and Exchange Act of 1934, as amended, and file periodic reports and other information with the SEC. However, as a foreign private issuer, we will be exempt from the rules and regulations under the Exchange Act prescribing the furnishing and content of proxy statements, and our officers, directors and principal stockholders will be exempt from the reporting and short-swing profit recovery provisions contained in Section 16 of the Exchange Act. Under the Exchange Act, we are not required to publish financial statements as frequently or as promptly as U.S. companies. Such reports and other information filed with the SEC may be inspected at the public reference facilities maintained by the Commission at 100 F Street, N.E., Washington, D.C. 20549. Copies of these materials may be obtained at prescribed rates from the SEC at that address. The reports, proxy statements and other information can also be inspected at no charge on the Commission’s Web site at www.sec.gov.

We are also subject to the information and reporting requirements of the Securities Act (Alberta) and the Business Corporations Act (Alberta). Such reports and information can be inspected at no charge on the website www.sedar.com.

If you are a stockholder, you may request a copy of these filings at no cost by contacting us at:

JED Oil Inc.
Suite 2200, 500 — 4^th Avenue S.W.
Calgary, Alberta, Canada

T2P 2V6
(403) 537-3250
(403) 536-3221 (fax)

Subsidiary Information

JED Oil (USA) Inc., a Wyoming corporation, is JED’s only subsidiary and is wholly owned by JED.

Item 11. Qualitative and Quantitative Disclosures about Market Risk

We are exposed to all of the normal risks inherent within the oil and gas sector, including commodity price risk, foreign-currency rate risk, interest rate risk and credit risk. We manage our operations in a manner intended to minimize our exposure.

Risk Factors

Credit Risk

Credit risk is the risk of loss resulting from non-performance of contractual obligations by a customer or joint venture partner. A substantial portion of our accounts receivable are with customers in the energy industry and are subject to normal industry credit risk. We intend to assess the financial strength of our customers and joint venture partners through regular credit reviews in order to minimize the risk of non-payment.

Market Risk

We are exposed to market risk from changes in currency exchange rates and interest rates. As a Canadian oil and natural gas company, we may be adversely affected by changes in the exchange rate between U.S. and Canadian dollars. The price we will receive for oil and natural gas production is based on a benchmark expressed in U.S. dollars, which is the standard for the oil and natural gas industry worldwide. However, we will pay our operating expenses, drilling expenses and general overhead expenses in Canadian dollars. Changes to the exchange rate between U.S. and Canadian dollars can adversely affect us.

Interest Rate Risk

At December 31, 2005, JED has no interest rate risk exposure.

Foreign Currency Exchange Risk

We conduct a significant portion of our business in Canada and the Canadian dollar has been designated as our functional currency. This subjects us to foreign exchange risk on assets, liabilities and cash flows dominated in a currency other than our functional currency. We generally hold United States dollar denominated assets that are converted to our Canadian dollar functional currency at each balance sheet date. When the Canadian dollar strengthens in relation to the United States dollar, we can incur a foreign exchange loss on the conversion. Conversely, when the Canadian dollar weakens in relation to the United States dollar, we can incur a foreign exchange gain. We have not entered into foreign currency forward contracts or other similar financial instruments to manage this risk.

Oil and Gas Risk

(SEC). Under these rules, we review the carrying value of our proved oil and gas properties each quarter on a country-by-country basis to ensure that capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization, and deferred income taxes, do not exceed the “ceiling.” This ceiling is the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties included in the costs being amortized, net of related tax effects. If capitalized costs exceed this limit, the excess is charged to additional depletion, depreciation and accretion expense. The calculation of estimated future net cash flows is based on the prices for crude oil and natural gas in effect on the last day of each fiscal quarter except for volumes sold under long-term contracts. Write-downs required by these rules do not impact cash flow from operating activities; however, as discussed above, sustained low prices would have a material adverse effect on future cash flows. We have not entered into any derivative securities or hedging instruments to manage oil and gas risks.

Item 12. Description of Securities Other Than Equity Securities

Not applicable.

PART II

Item 13. Defaults, Dividends, Arrearages and Delinquencies

None.

Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds

Not applicable.

Item 15. Controls and Procedures

(a) Evaluation of disclosure controls and procedures

Our Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of JED’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report (the “Evaluation Date”), have concluded that, as of the Evaluation Date, our disclosure controls and procedures were adequate and effective.

(b) Management’s annual report on internal control over financial reporting

Not applicable.

(c) Attestation report of the independent registered public accounting firm

Not applicable.

(d) Changes in internal controls

There has been no change in JED’s internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, JED’s internal control over financial reporting.

Item 16. [Reserved]

Item 16A. Audit Committee Financial Expert

Our Board of Directors has determined that Justin W. Yorke, a director of the Company and the Chairman of the Audit Committee, possesses the attributes required of an “audit committee financial expert,” and is “independent,” under applicable AMEX rules.

Item 16B. Code of Ethics

We have adopted a Code of Ethics, which applies to all of our officers, directors, employees and consultants. The Code of Ethics is publicly available on our website at www.jedoil.com. A copy of the Code of Ethics is also available upon written request. There were no amendments to, or waivers granted under, the Code of Ethics during the fiscal year ended December 31, 2005.

Item 16C. Principal Accountant Fees and Services

Ernst & Young LLP has served as our principal accountants for the fiscal years ended December 31, 2005 and 2004. The fees billed or expected to be billed by Ernst & Young LLP and its affiliates for their professional services for each of the last two fiscal years were as follows:


Services Rendered	2005		2004
	(in Canadian Dollars)
Audit Fees (1)	$	136,623	$	81,395
Audit-Related Fees (2)	$	—	$	35,123
Tax Fees (3)	$	1,665	$	7,881
All Other Fees (4)	$	34,552	$	2,788

Total	$	172,840	$	127,187


(1)		Audit Fees were fees billed for the audit of our annual consolidated financial statements and statutory and regulatory filings.

(2)		Audit-Related Fees were fees billed for the review of our interim financial statements.

(3)		Tax Fees were fees billed for the preparation and review of our tax returns and for investment tax advice.

(4)		All Other Fees were fees billed for review of our registration statement and for electronic database usage.

Pre-Approval Policies and Procedures

The audit committee approves all audit, audit-related services, tax services and other services provided by Ernst & Young LLP. Any services provided by Ernst & Young LLP that are not specifically included within the scope of the audit must be pre-approved by the audit committee in advance of any engagement. Under the Sarbanes-Oxley Act of 2002, audit committees are permitted to approve certain fees for audit-related services, tax services and other services pursuant to a de minimus exception prior to the completion of an audit engagement.

Item 16D. Exemptions from the Listing Standards for Audit Committees

Not applicable.

Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Not applicable.

PART III

Item 17. Financial Statements

We have responded to Item 18 in lieu of responding to this Item.

Item 18. Financial Statements

The Consolidated Financial Statements of JED Oil Inc. are attached as follows:


	Page
Reports of Ernst & Young LLP, Independent Registered Public Accounting Firm		F-1
Consolidated Balance Sheets as of December 31, 2005, 2004 and 2003		F-2
Consolidated Statements of Operations for the years ended December 31, 2005 and 2004 and for the 120-day period from inception on September 3, 2003 to December 31, 2003		F-3
Consolidated Statements of Cash Flows for the years ended December 31, 2005 and 2004 and for the 120-day period from inception on September 3, 2003 to December 31, 2003		F-4
Statement of Consolidated Stockholders’ Equity		F-5
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2005 and 2004 and for the 120-day period from inception on September 3, 2003 to December 31, 2003		F-6
Notes to Consolidated Financial Statements		F-7

Item 19. Exhibits


Number		Exhibit
1.1		Articles of Incorporation of the Registrant (1)

1.2		By-laws of the Registrant (1)

1.3		Articles of Amendment of the Registrant

4.1		Stock Option Plan (1)

4.2		Annual Bonus Plan (2)

4.3		Form of Officer and Director Indemnity Agreement (1)

4.4		Note Purchase Agreement, dated May 31, 2006, by and among JED Oil Inc. and each of the persons listed on the Schedule of Purchasers attached thereto (5)

4.5		Form of 10% Senior Subordinated Convertible Note, to be issued by JED Oil Inc. to each of the persons listed on the Schedule of Purchasers attached to the Note Purchase Agreement in the principal amount set out by such person’s name on such schedule (5)

4.6		Form of Registration Rights Agreement, dated May 31, 2006, by and among JED Oil Inc. and each of the persons listed on the Schedule of Purchasers attached to the Note Purchase Agreement (5)

4.7		Form of Securities Purchase Agreement, dated June 9, 2006, by and among JED Oil Inc. and each of the persons listed on the Schedule of Purchasers attached thereto (6)

4.8		Form of Registration Rights Agreement, dated June 9, 2006, by and among JED Oil Inc. and each of the persons listed on the Schedule of Purchasers attached to the Securities Purchase Agreement (6)

8.1		List of Subsidiaries

12.1		Certifications of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act

12.2		Certifications of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act

13.1		Certifications of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act

13.2		Certifications of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act

15.1		Consent from Ernst & Young LLP

15.2		Consent from McDaniel & Associates Consultants Ltd.

15.3		2nd Amended and Restated Agreement of Business Principles with Enterra Energy Trust, JED Oil Inc. and JMG Exploration, Inc. (3)

15.4		Senior Subordinated Convertible Note issued by the Company in August 2005. (4)


(1)		Incorporated by reference from JED’s Registration Statement on Form S-1 (File No. 333-111435) filed December 22, 2003.

(2)		Incorporated by reference from JED’s Amended Registration Statement on Form S-1/A (File No. 333-111435) filed February 13, 2004.

(3)		Incorporated by reference from JED’s Annual Report on Form 20-F (File No. 333-111435) filed July 15, 2005.

(4)		Incorporated by reference from JED’s Registration Statement on Form F-3 (File No. 333-128711) filed September 30, 2005.

(5)		Incorporated by reference from JED’s Current Report on Form 6-K furnished June 6, 2006.

(6)		Incorporated by reference from JED’s Current Report on Form 6-K furnished June 21, 2006.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of JED Oil Inc.

We have audited the accompanying consolidated balance sheets of JED Oil Inc. and subsidiary as of December 31, 2005, 2004 and 2003, and the related consolidated statements of operations, comprehensive income, stockholders’ equity and cash flows for the years ended December 31, 2005 and 2004 and the 120 day period from inception on September 3, 2003 to December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of JED Oil Inc. and subsidiary at December 31, 2005, 2004 and 2003, and the consolidated results of their operations and their cash flows for the years ended December 31, 2005 and 2004 and the 120 day period from inception on September 3, 2003 to December 31, 2003, in conformity with U.S. generally accepted accounting principles.


Calgary, Canada
March 13, 2006		Chartered Accountants

F-1

JED Oil Inc. and Subsidiary

CONSOLIDATED BALANCE SHEETS
(In United States Dollars)


At December 31	2005			2004			2003
	$			$			$

ASSETS
Current
Cash and cash equivalents [note 2]		4,451,419			18,657,007			16,088,631
Accounts receivable [note 12]		4,837,054			773,433			40,805
Prepaid expenses		341,133			27,463			171,744
Due from Enterra Energy Trust [note 11]		6,205,676			1,796,632			—
Due from JMG Exploration, Inc. [note 11]		401,142			376,855			—
Due from related party [note 11]		—			5,931			—
Loan receivable from Enterra Energy Trust [note 11]		6,861,054			1,992,032			4,627,844

		23,097,478			23,629,353			20,929,024


Drilling advance *[note 3]*		4,288,165			—			—


Property and equipment *[note 4]*
Oil and gas, on the basis of full cost accounting:
Proved properties		54,737,562			10,172,328			—
Unproved properties under development, not being depleted		1,629,017			—			—
Other		348,613			180,811			—


		56,715,192			10,353,139			—
Less: accumulated depletion and depreciation		(8,381,422	)		(4,948,745	)		—

		48,333,770			5,404,394			—

		75,719,413			29,033,747			20,929,024


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current
Accounts payable		16,799,364			1,792,835			64,176
Interest payable on convertible note		338,889			—			—
Accrued capital liabilities		8,125,334			1,231,385			—
Accrued other liabilities		1,450,081			2,301,908			—

		26,713,668			5,326,128			64,176

Convertible note payable *[note 5]*		20,000,000			—			—
Asset retirement obligations *[note 6]*		1,401,235			255,164			—

		48,114,903			5,581,292			64,176


Commitments and contingencies *[note 7]*
Stockholders’ equity
Share capital [note 8]

Common stock – no par value; unlimited authorized; 14,630,256 shares issued and outstanding at December 31, 2005 and 14,250,000 shares outstanding at December 31, 2004		32,087,197			29,710,573			—
Preferred Shares – Series A convertible preferred stock — $2.75 stated value; unlimited authorized in series; 12,000,000 shares authorized; nil shares issued and outstanding at December 31, 2004 and 11,400,000 outstanding at December 31, 2003		—			—			20,876,469
Additional paid-in capital		1,080,586			223,842			—
Share purchase warrants		37,506			60,410			—
Accumulated deficit		(7,763,390	)		(8,906,534	)		(359,604	)
Accumulated other comprehensive income		2,162,611			2,364,164			347,983

		27,604,510			23,452,455			20,864,848

		75,719,413			29,033,747			20,929,024

The accompanying notes to the consolidated financial statements are an integral part of this statement.

On behalf of the Board


Reg J. Greenslade Chairman		James F. Dinning Director

F-2

JED Oil Inc. and Subsidiary

CONSOLIDATED STATEMENTS OF OPERATIONS
(In United States Dollars)


							For the 120 day
							period from
							inception on
	For the year			For the year			September 3,
	ended			ended			2003 to
	December 31,			December 31,			December 31,
	2005			2004			2003
	$			$			$

Revenue *[note 11]*
Petroleum and natural gas		9,658,790			1,519,089			—
Royalties, net of Alberta Royalty Tax Credit		(1,653,880	)		(295,816	)		—

		8,004,910			1,223,273			—
Interest		604,592			484,137			49,485

		8,609,502			1,707,410			49,485


Expenses *[note 11]*
Production		1,414,849			243,016			—
General and administrative		1,124,990			2,740,230			99,336
Stock-based compensation [note 9]		1,077,642			223,842			—
Foreign exchange (gain) loss		(499,769	)		1,088,921			309,753
Depletion, depreciation and accretion [note 4]		3,502,762			4,958,331			—
Loss on equity investment [note 11]		—			1,000,000			—
Interest on convertible note payable		845,884			—			—

		7,466,358			10,254,340			409,089


*Net income (loss) [note 10]***		1,143,144			(8,546,930	)		(359,604	)

Net income (loss) for the period per common share [note 8]
- basic		0.08			(0.81	)		—
- diluted		0.07			(0.81	)		—

The accompanying notes to the consolidated financial statements are an integral part of this statement.

F-3

JED Oil Inc. and Subsidiary

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In United States Dollars)


							For the 120 day
							period from
	For the year			For the year			inception on
	Ended			ended			September 3, 2003 to
	December 31,			December 31,			December 31,
	2005			2004			2003
	$			$			$

OPERATIONS
Net loss for the period		1,143,144			(8,546,930	)		(359,604	)
Adjustments to reconcile net income (loss) to cash flows from operating activities:
Foreign exchange (gain) loss		(499,769	)		1,088,921			309,753
Stock-based compensation		1,077,642			223,842			—
Depletion, depreciation and accretion		3,502,762			4,958,331			—
Loss on equity investment		—			1,000,000			—
Changes in operating assets and liabilities:
Increase in accounts receivable		(4,063,621	)		(2,529,260	)		(40,805	)
(Increase) decrease in prepaid expenses		(313,670	)		144,281			(171,744	)
Increase in due from Enterra Energy Trust		(4,409,044	)		—			—
Increase in due from JMG Exploration, Inc.		(24,287	)		(376,855	)		—
Decrease (increase) in due from related party		5,931			(5,931	)		—
Increase in accounts payable and accrued liabilities		13,262,206			4,030,567			64,176

Cash provided by (used in) operations		9,681,294			(13,034	)		(198,224	)


FINANCING
Proceeds from issuance of convertible note		20,000,000			—			—
Issue of preferred shares, net of related costs		—			—			20,876,469
Issue of common shares, net of related costs		1,941,155			8,834,104			—
Issue of share purchase warrants		—			60,410			—

Cash provided by financing activities		21,941,155			8,894,514			20,876,469


INVESTING
Repayment (advance) of loan by (to) third party		—			4,527,277			(4,582,951	)
(Increase) in loan to Enterra Energy Trust		(8,576,797	)		(1,992,032	)		—
Decrease in loan to Enterra Energy Trust		3,707,775			—			—
Increase in long-term investment		—			(1,000,000	)		—
Purchase of property and equipment		(35,582,239	)		(8,882,531	)		—
Funds received from joint venture partner [note 11]		—			12,636,587			—
Funds advanced to joint venture partner [note 11]		—			(12,832,125	)		—
Funds advanced to third party		(4,288,165	)		—			—

Cash used in investing activities		(44,739,426	)		(7,542,824	)		(4,582,951	)

Effect of foreign exchange on cash and cash equivalents		(1,088,611	)		1,229,720			(6,663	)

Net (decrease) increase in cash and cash equivalents		(14,205,588	)		2,568,376			16,088,631

Cash and cash equivalents, beginning of period		18,657,007			16,088,631			—

Cash and cash equivalents, end of period		4,451,419			18,657,007			16,088,631

During 2005, the Company paid cash interest of $505,479 (2004 – $Nil; 2003 – $Nil) on the convertible note and paid no cash taxes.

The accompanying notes to the consolidated financial statements are an integral part of this statement.

F-4

JED Oil Inc. and Subsidiary

STATEMENT OF CONSOLIDATED STOCKHOLDERS’ EQUITY
(In United States Dollars)


	Shares			Amount
				$

Common stock
Balance, September 3, 2003 (inception) and December 31, 2003		—			—
Preferred shares converted to common shares		11,400,000			20,900,198
Shares issued for cash pursuant to initial public offering		2,850,000			10,389,590
Share issue costs		—			(1,579,215	)

Balance, December 31, 2004		14,250,000			29,710,573
Shares issued upon exercise of stock options		285,006			1,934,618
Shares issued upon exercise of warrants		95,250			442,006

Balance, December 31, 2005		14,630,256			32,087,197


Series A convertible preferred stock, $2.75 stated value
Balance, September 3, 2003 (inception) and December 31, 2003		11,400,000			20,876,469
Share issue costs		—			(3,720	)
Preferred shares converted to common shares		(11,400,000	)		(20,872,749	)

Balance, December 31, 2004 and 2005		—			—


Additional paid in capital
Balance, September 3, 2003 (inception) and December 31, 2003					—
Stock-based compensation on issued stock options					223,842

Balance, December 31, 2004					223,842
Stock-based compensation on issued stock options					1,269,307
Stock-based compensation on stock options and warrants exercised					(412,563	)

Balance, December 31, 2005					1,080,586


Share purchase warrants
Balance, September 3, 2003 (inception) and December 31, 2003					—
Share purchase warrants issued pursuant to initial public offering					60,410

Balance, December 31, 2004					60,410
Warrants exercised					(22,904	)

Balance, December 31, 2005					37,506


Deficit
Balance, September 3, 2003					—
Net loss					(359,604	)

Balance, December 31, 2003					(359,604	)
Net loss					(8,546,930	)

Balance, December 31, 2004					(8,906,534	)
Net income					1,143,144

Balance, December 31, 2005					(7,763,390	)


Accumulated other comprehensive income
Balance, September 3, 2003					—
Foreign exchange translation adjustment					347,983

Balance, December 31, 2003					347,983
Foreign exchange translation adjustment					2,016,181

Balance, December 31, 2004					2,364,164
Foreign exchange translation adjustment					(201,553	)

Balance, December 31, 2005					2,162,611


Total stockholders’ equity					27,604,510

The accompanying notes to the consolidated financial statements are an integral part of this statement.

F-5

JED Oil Inc. and Subsidiary

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In United States Dollars)

1. SIGNIFICANT ACCOUNTING POLICIES

These financial statements have been prepared by management in accordance with accounting principles generally accepted in the United States.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates.

a) Nature of operations

JED Oil Inc. (“JED” or the “Company”) is an independent energy company that explores for, develops and produces natural gas, crude oil and natural gas liquids in Canada and the United States. Currently, all the Company’s proved reserves are located in Canada.

The Company’s future financial condition and results of operations will depend upon prices received for its oil and natural gas production and the costs of finding, acquiring, developing and producing reserves. Prices for oil and natural gas are subject to fluctuations in response to change in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability, the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand, and the price and availability of alternative fuels.

b) Principles of consolidation

These consolidated financial statements include the accounts of the Company’s wholly owned legal subsidiary, JED Oil (USA) Inc., incorporated under the laws of the state of Wyoming on May 5, 2004. All inter-company accounts and transaction have been eliminated. Investments in companies which give JED significant, but not control, over the investee are accounted for using the equity method.

c) Foreign currency translation

As the majority of the Company’s operating activities are in Canada, the Company uses the Canadian dollar as its functional currency. The Company’s operations are translated for financial statement reporting purposes into United States dollars in accordance with Statement of Financial Accounting Standards No. 52, Foreign Currency Translation, using the current rate method. Under this method, all assets and liabilities are translated at the period-end rate of exchange and all revenue and expense items are translated at the average rate of exchange for the period. Exchange differences arising on translation are classified as other comprehensive income in a separate component of stockholders’ equity.

F-7

JED Oil Inc. and Subsidiary

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In United States Dollars)

exchange rates. Revenues and expenses are translated at average rates for the period. Exchange gains or losses are reflected in the Consolidated Statement of Operations for the period.

d) Comprehensive income (loss)

Comprehensive income includes net income (loss) and other comprehensive income (loss), which includes, but is not limited to, foreign currency translation adjustments.

e) Revenue recognition

Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if the collectibility of the revenue is probable.

f) Joint operations

Substantially all of the Company’s petroleum and natural gas development activities are conducted jointly with others. Accordingly, these financial statements reflect only the Company’s proportionate interest in such activities.

g) Property and equipment

The Company uses the full-cost method of accounting for petroleum and natural gas properties. Under this method, the Company capitalizes all costs relating to the exploration for and the development of oil and natural gas reserves including land acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling of productive and non-productive wells and general and administrative costs directly related to exploration and development activities. Proceeds from the disposal of properties are applied as a reduction of costs without the recognition of a gain or loss except where such disposals would result in a greater than 25% change in the depletion rate.

Capitalized costs are depleted and depreciated using the unit-of-production method based on the estimated proven oil and natural gas reserves before royalties as determined by independent engineers. Properties are evaluated on a quarterly basis by the Company’s internal engineers. Units of natural gas are converted into barrels of oil equivalents on a relative energy content basis. Costs related to unproven properties are excluded from the costs subject to depletion until it is determined whether or not proved reserves exist or if impairment has occurred.

In performing its quarterly ceiling test, the Company limits, on a country-by-country basis, the capitalized costs of proved oil and gas properties, net of accumulated depletion, depreciation and amortization (“DD&A”) and deferred income taxes, to the estimated future net cash flows from proved oil and gas reserves based on period-end prices, discounted at 10 percent, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the costs being amortized. If capitalized costs exceed this limit, the excess is charged to additional DD&A expense.

F-8

JED Oil Inc. and Subsidiary

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In United States Dollars)

decline significantly, even if only for a short period of time, it is possible that write-downs of petroleum and natural gas properties could occur.

Unproved properties are assessed quarterly for possible impairments or reductions in value. If a reduction in value has occurred, the impairment is transferred to proved properties. Unproved properties that are individually insignificant are generally amortized over an average holding period.

Other property and office furniture, fixtures and equipment are recorded at cost. Depreciation is provided using the straight-line method based over the estimated useful lives at a rate of 20 percent per annum.

h) Allowance for doubtful accounts

The Company considers accounts receivable to be fully collectible as recorded as of December 31, 2005. Accordingly, no allowance for doubtful accounts is required.

i) Income taxes

The Company accounts for income taxes under the Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”. Temporary differences between the tax basis of assets and liabilities and their reported amount in the financial statements that will result in taxable amounts in the future. The Company routinely assesses the realizability of its deferred tax assets. If it concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized, under accounting standards, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions.

j) Stock-based compensation

The Company has a stock-based compensation plan which reserve shares of common stock for issuance to key employees and directors. The Company accounts for grants issued under this plan using the fair value recognition provisions of Statement of Financial Accounting Standards No. 123-R, Accounting for Stock-Based Compensation (“SFAS 123-R”). Under these provisions, the cost of options granted to employees is charged to expense with a corresponding increase in additional paid-in capital, based on an estimate of the fair value determined using the Black-Scholes option pricing model.

k) Asset retirement obligations

F-9

JED Oil Inc. and Subsidiary

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In United States Dollars)

retirement obligations primarily relate to the plugging and abandonment of petroleum and natural gas properties.

l) Measurement uncertainty

The amount recorded for depletion and amortization of oil and gas properties, the provision for asset retirement obligations and the ceiling test calculation are based on estimates of gross proven reserves, production rates, commodity prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future years could be significant.

m) Net income (loss) per share

The Company accounts for per common share amounts in accordance with SFAS No. 128, “Earnings per Share.” Under SFAS No. 128, basic per common share amounts is computed by dividing net income (loss) attributable to common shareholders by the weighted average common shares outstanding without including any potentially dilutive securities. Diluted per common share amounts are computed by dividing net income (loss) by the weighted average common shares outstanding plus, when their effect is dilutive, common stock equivalents.

n) Reclassifications

Certain prior period amounts have been reclassified to confirm with the presentation adopted in the current year.

2. CASH AND CASH EQUIVALENTS

Cash and cash equivalents consist of cash on hand and balances invested in short-term, highly liquid securities with maturities less than 90 days from the date of purchase.

For year ended December 31, 2005, the average effective interest rate earned on cash equivalent balances was 2.79% (2004 – 2.76%; 2003 – 0.25%). As at December 31, 2005, the Company had $4,451,419 (2004 — $589,344; 2003 — $Nil) in cash and $Nil (2004 — $18,067,663; 2003 — $16,088,631) in short-term, highly liquid securities.

F-10

JED Oil Inc. and Subsidiary

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In United States Dollars)

3. DRILLING ADVANCE

4. PROPERTY AND EQUIPMENT


	2005			2004
	$			$

Petroleum and natural gas properties		56,366,579			10,172,328
Other		348,613			180,811

		56,715,192			10,353,139
Accumulated depletion and depreciation		(8,381,422	)		(4,948,745	)

		48,333,770			5,404,394

During 2005, approximately $563,500 (2004 — $969,500; 2003 — $Nil) of general and administrative and stock based compensation costs were capitalized to petroleum and natural gas properties. At December 31, 2004, the Company incurred a ceiling test write-down of oil and natural gas properties in the amount of $4,178,000 that is included in depletion, depreciation and accretion in the 2004 Consolidated Statement of Operations.

At December 31, 2005, approximately $1,701,000 (2004 — $83,600; 2003 — $Nil) of unproved properties and seismic was excluded from the depletion calculation.

5. CONVERTIBLE NOTE PAYABLE

On August 3, 2005, the Company entered into a $20,000,000 Convertible Subordinated Note Agreement with a qualified investor limited partnership. The convertible note bears interest at a rate of 10% per annum payable in quarterly payments commencing on November 1, 2005, has no set repayment terms and expires on February 1, 2008. The note is convertible at the holder’s option into 1,000,000 common shares of the Company at a value of $20 per share.

F-11

JED Oil Inc. and Subsidiary

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In United States Dollars)

6. ASSET RETIREMENT OBLIGATIONS

As at December 31, 2005, the estimated present value of the Company’s asset retirement obligation was $1,401,235 (2004 — $255,164; 2003 — $Nil) based on an estimated fair value of $2,736,080, determined using a credit adjusted risk free interest rate of 8.0%, and inflation rate of 2%. These obligations will be settled at the end of the estimated useful lives of the underlying assets, which currently extend up to 20 years into the future.

The following table describes the changes to the Company’s asset retirement obligations liability:


	2005		2004
	$		$

Asset retirement obligation, beginning of year		255,164		—
Liabilities incurred		1,075,989		246,682
Liabilities settled		—		—
Accretion expense		70,082		8,482

Asset retirement obligation, end of year		1,401,235		255,164

7. COMMITMENTS AND CONTINGENCIES

In conjunction with the Drilling Advance outlined in note 3, the Company has entered into five separate Standard Daywork Contracts with a drilling contractor who will supply the Company with five drilling rigs for a period of three years. The terms of each contract call for a minimum requirement of 250 operating days per year for a total of 750 operating days over the three-year term of each separate contract. The following outlines the Company’s estimated commitments over the life of the contracts:


	2006		2007		2008		2009		Total

Estimated minimum lease payments	$	14,578,767	$	18,750,000	$	18,750,000	$	4,171,233	$	56,250,000

The Company has entered into indemnification agreements with all of its directors and officers, which provides for the indemnification and advancement of expenses by the Company. There is no pending litigation or proceeding involving any director or officer of the Company for which indemnification is being sought, nor is the Company aware of any threatened litigation that may result in claims for indemnification. Accordingly, no provision has been made in these financial statements under the terms of the indemnification agreements.

The Company had no derivative financial or physical delivery contracts in place at December 31, 2005, 2004 and 2003.

F-12

JED Oil Inc. and Subsidiary

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In United States Dollars)

8. SHARE CAPITAL

On September 28, 2005, the shareholders of the Company approved a 3-for-2 stock split of the Company’s common shares. The record date of the stock split was set at October 10, 2005 and the shares began trading on the American Stock Exchange on a post split basis on October 12, 2005. All share and per share amounts have been restated to account for the 3-for-2 stock split as if it had occurred at the inception of the Company.

a) Authorized

The Company has authorized an unlimited number of common voting shares and an unlimited number of preferred shares, issuable in series. The first Series A Preferred Shares were issued, which was comprised of 11,400,000 voting, convertible preferred shares. Subsequent to the Company’s initial public offering in April 2004, all the Series A Preferred Shares were converted into common shares of the Company and the Preferred Shares were cancelled.

b) Common stock issued and outstanding


	2005				2004
			Amount				Amount
	Shares		$		Shares		$

Balance, beginning of year		14,250,000		29,710,573		—		—
Issued upon exercise of stock options		285,006		1,934,618		—		—
Issued upon exercise of warrants		95,250		442,006		—		—
Preferred shares converted to common		—		—		11,400,000		20,900,198
Shares issued for cash pursuant to initial public offering		—		—		2,850,000		10,389,590
Share issue costs		—		—		—		(1,579,215	)

Balance, end of year		14,630,256		32,087,197		14,250,000		29,710,573

On April 5, 2004, the Company’s initial public offering registration statement for 2,512,500 shares of common stock and an underwriter’s over-allotment option of 337,500 shares of common stock, at a price of $3.67 per share, was declared effective. Upon the closing of the initial public offering on April 12, 2004, the Company issued 2,850,000 shares of common stock at a price of $3.67 per share and 251,250 warrants for gross proceeds of $10,450,000.

As part of the registration statement holders of 11,400,000 Series A Convertible Preferred Shares elected to convert their shares into 11,400,000 shares of common stock.

F-13

JED Oil Inc. and Subsidiary

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In United States Dollars)

e) Share purchase warrants

Upon the closing of the Company’s initial public offering in April 2004, the Company issued 251,250 share purchase warrants to the Underwriter of the offering. The warrants are exercisable into an equal number of common shares for a four-year period expiring on April 12, 2009 at an exercise price of $4.40 per common share. The Company assigned a fair value of the warrants of $60,410 based on a Black-Scholes option model. To December 31, 2005, $95,250 (2004 – $Nil; 2003 - $Nil) of the warrants have been exercised into common shares of the Company.


	2005						2004
				Amount					Amount
	Shares			$			Shares		$

Balance, beginning of year		251,250			60,410			—		—
Share purchase warrants issued pursuant to initial public offering		—			—			251,250		60,410
Warrants exercised		(95,250	)		(22,904	)		—		—


Balance, end of year		156,000			37,506			251,250		60,410

f) Stock options

The following summarizes information concerning outstanding and exercisable stock options as of December 31:


	2005					2004
				Weighted					Weighted
	Number of			average exercise		Number of			average
	options			price		options			exercise price

Balance, beginning of year		1,138,751		$	4.62		—			—
Granted		625,000		$	12.91		1,211,251		$	4.56

Cancelled		(187,494	)	$	4.91		(72,500	)	$	3.67
Exercised		(285,006	)	$	5.34		—			—

Balance, end of year		1,291,251		$	8.49		1,138,751		$	4.62


Exercisable as at end of year		261,261		$	6.79		—			—

F-15

JED Oil Inc. and Subsidiary

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In United States Dollars)

The following table summarizes the stock options outstanding at December 31, 2005


	Stock options outstanding						Stock options exercisable
					Weighted
					average				Weighted
			Weighted		remaining				average
Range of	Outstanding		average		contractual life		Options		exercise
exercise prices	options		exercise price		(years)		exercisable		price

$3.67 - $3.67		543,751	$	3.67		3.1		171,260	$	3.67
$7.60 - $11.15		505,000	$	9.72		4.1		45,001	$	8.39
$12.30 - $17.96		212,500	$	16.23		4.7		45,000	$	17.06
$20.33 - $20.46		30,000	$	20.33		4.6		—		—

		1,291,251	$	8.49		4.1		261,261	$	6.79

The 1,291,251 stock options outstanding at December 31, 2005 vest over a three-year period and expire at various dates in 2009 and 2010. The Company has a total of 1,291,251 stock options reserved for issuance under the Stock Option Plan.

9. STOCK-BASED COMPENSATION

The fair value of common share options granted during the year ended December 31, 2005 is estimated to be $2,751,379 or $4.40 per option (2004 — $1,048,973; 2003 — $Nil) using the Black-Scholes option pricing model and the following weighted average assumptions as at the date of grant:

Risk-free interest rate — 4.37%
Expected life (years) — 5.0
Expected volatility — 32.8%
Estimated forfeitures — 11%
Expected dividend yield (%) — Nil

The estimated fair value of the options is amortized to expense over the options’ vesting period on a straight-line basis. For the year ended December 31, 2005, stock based compensation expense of $1,077,642 (2004 – $223,842; 2003 — $Nil) was included in the Consolidated Statement of Operations.

F-16

JED Oil Inc. and Subsidiary

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In United States Dollars)

10. INCOME TAXES

The provision for income taxes recorded in the financial statements differs from the amount, which would be obtained by applying the statutory income tax rate to the income (loss) before tax as follows:


	2005			2004			2003
	$			$			$

Income (loss) for the year		1,143,144			(8,546,930	)		(359,604	)
Statutory Canadian corporate tax rate		37.62	%		38.87	%		40.62	%
Anticipated tax expense (recovery)		430,051			(3,322,192	)		(146,071	)
Resource allowance		(275,797	)		(112,804	)		—
Non-deductible crown royalties		158,309			74,480			—
Stock-based compensation		411,299			92,515			—
Lower effective future tax rate		—			—			21,576

Anticipated tax expense (recovery)		723,862			(3,268,001	)		(124,495	)
Deferred tax valuation allowance		(723,862	)		3,268,001			124,495

Income tax benefit (liability)		—			—			—

The components of the Company’s deferred income tax assets are as follows:


	2005						2004			2003
	United States			Canada			Canada			Canada
	$			$			$			$

Deferred tax assets
Non-capital loss carry-forwards		—			898,519			958,860			20,250
Income tax pools		8,897			912,774			681,309			—
Unrealized foreign exchange loss		—			—			—			125,821
Share issue costs		—			620,417			—			9,630
Other		—			645			2,172			—

Total future tax assets		8,897			2,432,355			1,642,341			155,701
Valuation allowance		(8,897	)		(2,432,355	)		(1,642,341	)		(155,701	)

Net future tax assets		—			—			—			—

The Company provides a valuation allowance for the amount of deferred tax assets except where it is more likely than not that the asset will be realized.

The Company has non-capital losses for income tax purposes of approximately $2,672,600 available for application against future years’ taxable income of which $2,619,300 and $53,300 expire in the years 2011 and 2012, respectively.

F-17

JED Oil Inc. and Subsidiary

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In United States Dollars)

11. RELATED PARTY TRANSACTIONS

Under an Agreement of Business Principles, properties acquired by Enterra Energy Trust (“Enterra”) will be contract operated and drilled by JMG Exploration, Inc. (“JMG”), if they are exploration properties, and contract operated and drilled by JED if they are development projects. Exploration of the properties will be done by JMG, which will pay 100% of the exploration costs to earn a 70% working interest in the properties. If JMG discovers commercially viable reserves on the exploration properties, Enterra will have the right to purchase 80% of JMG’s working interest in the properties at a fair value as determined by independent engineers. Should Enterra elect to have JED develop the properties, development will be done by JED, which will pay 100% of the development costs to earn 70% of the interests of both JMG and Enterra. Enterra will have a first right to purchase assets developed by JED.

Under a Technical Services Agreement, both the Company and Enterra provide operational, technical and administrative services in connection with the management, development and exploitation and operation of the assets of JED, Enterra and JMG. Each Company provides these services on an expense re-imbursement basis based on the monthly capital activity and production levels relative to the combined capital activity and production levels of all three companies. For the year ended December 31, 2005, the Company charged general and administrative expenses and field operating expenses to Enterra of $5,112,744. The total outstanding from Enterra at December 31, 2005 was $6,205,676 (2004 — $1,796,632; 2003 — $Nil). Effective January 1, 2006, the Technical Services Agreement with Enterra and JMG was terminated by all parties.

On December 23, 2004, the Company loaned $1,992,032 (Cdn $2,400,000) to Enterra, a joint venture partner that the Company’s Chairman is also Chairman of the Board. The loan was originally repayable on or before June 29, 2005, however, the term of the loan has been extended indefinitely. The revised terms of the loan call for interest to be calculated at a rate of 10% per annum. During the year ended December 31, 2005, the Company loaned additional funds of $8,576,797 under the same terms of which Enterra repaid $3,707,775.

The total outstanding from Enterra, including accrued interest, under the promissory note at December 31, 2005 was $6,861,054 (2004 — $1,992,032; 2003 — $Nil). Subsequent to year end, the entire loan together with accrued interest was repaid in full.

In August 2004, the Company acquired 250,000 common shares of JMG, a private company at the time of the Company’s investment, representing approximately 11% equity interest in the total voting share capital of JMG, for cash consideration of $1,000,000. In August 2005, JMG completed its initial public offering which reduced the Company’s ownership in JMG to approximately 6%. The Company is represented with two of the five seats on the JMG Board of Directors. The Company’s investment in JMG is being accounted for using the equity method. At December 31, 2004, the Company owned 100% of the common shares of JMG and was required to include 100% of the equity loss of JMG for the period then ended. As the loss incurred by JMG for the period ended December 31, 2004 exceeded JED’s net investment, the Company reduced its net investment to zero. However, as JED has not guaranteed any obligations or is not committed to any further financial support, no additional equity losses on the JMG investment has been recorded.

F-18

JED Oil Inc. and Subsidiary

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In United States Dollars)

During the year ended December 31, 2005, the Company entered into the following transactions with JMG:

(i)		JED charged JMG for certain general and administrative services and oil and gas equipment in the amount of $711,134 (2004 — $325,811; 2003 — $Nil). These services were provided at standard industry rates for similar services.

(ii)		in consideration for the assignment of JED’s interests in certain oil and gas properties, the Company charged JMG for drilling and other costs related to those properties in the amount $85,085 for the year ended December 31, 2005, on a cost recovery basis.

In connection with these transactions the total amount receivable from JMG at December 31, 2005 was $401,142 (2004 — $376,855; 2003 — $Nil). Subsequent to year-end, this amount was repaid in full.

12. FINANCIAL INSTRUMENTS

a) Fair value of financial assets and liabilities

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, due from Enterra Energy Trust, due from JMG Exploration, Inc., due from related parties, loan receivable from Enterra Energy Trust, accounts payable, interest payable on convertible note and convertible note accounts payable. Unless otherwise noted, as at December 31, 2005, 2004 and 2003 there were no significant differences between the carrying amounts of these financial instruments and their estimated fair value.

b) Concentration of credit risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist principally of cash and cash equivalents, accounts receivable and loan receivable. At December 31, 2005, the Company had all of its cash and cash equivalents with one banking institution. The Company mitigates the concentration risk associated with cash deposits by only depositing material amounts of funds with major banking institutions. Concentrations of credit risk with respect to accounts receivable are the result of joint venture operations with industry partners and are subject to normal industry credit risks. The Company routinely assesses the credit of joint venture partners to minimize the risk of non-payment.

F-19

JED Oil Inc. and Subsidiary

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In United States Dollars)

The Company has balances due from Enterra Energy Trust totaling $13,066,730 and conducted a significant amount of operations jointly with Enterra. The Company believes that Enterra is a strong business entity and the risk of non-payment is minimal.

c) Interest rate risk

At December 31, 2005, the Company had no interest rate risk exposure.

d) Foreign currency risk

Foreign currency risk is the risk that a variation in exchange rates between the Canadian dollar and foreign currencies will affect the Company’s operating and financial results. The Company is exposed to foreign currency risk as the Company holds cash and cash equivalents on hand that are denominated in United States currency.

No forward foreign currency exchange contracts were in place at December 31, 2005, 2004 and 2003.

13. SUBSEQUENT EVENTS

On February 27, 2006, the Company and JMG Exploration, Inc. announced they had signed a letter of intent for JED to acquire JMG. The proposal would offer two-thirds of a share of common stock of JED for each share of common stock of JMG. Completion of the proposed transaction is subject to the receipt of independent third party opinions that the transaction is fair to both the shareholders of JMG and JED. In addition, completion of the transaction is subject to receipt of all regulatory and stock exchange approvals in the United States and Canada and the approval of the shareholders of both JMG and JED. Should all conditions be met, the transaction is expected to close in May 2006.

On March 9, 2006, the Company entered into a C$20,000,000 (US$17,200,000) Revolving Loan Facility with a Canadian commercial lending institution. The facility bears interest at Canadian prime lending rate plus 0.25% and is repayable on demand. Security of the facility is provided by a floating first charge over all of the Company’s assets in Canada.

F-20


ITEM 1.	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS	2
ITEM 2.	OFFER STATISTICS AND EXPECTED TIMETABLE	2
ITEM 3.	KEY INFORMATION	2
ITEM 4.	INFORMATION ON THE COMPANY	9
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	18
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	32
ITEM 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	38
ITEM 8.	FINANCIAL INFORMATION	41
ITEM 9.	THE OFFER AND LISTING	41
ITEM 10.	ADDITIONAL INFORMATION	42
ITEM 11.	QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK	53
ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	54
ITEM 13.	DEFAULTS, DIVIDENDS, ARREARAGES AND DELINQUENCIES	54
ITEM 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	54
ITEM 15.	CONTROLS AND PROCEDURES	54
ITEM 16.	[RESERVED]	54
ITEM 16A.	AUDIT COMMITTEE FINANCIAL EXPERT	54
ITEM 16B.	CODE OF ETHICS	55
ITEM 16C.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	55
ITEM 16D.	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	55
ITEM 16E.	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	55
ITEM 17.	FINANCIAL STATEMENTS	55
ITEM 18.	FINANCIAL STATEMENTS	56
ITEM 19.	EXHIBITS	56


	Shares		Percentage
	Beneficially		of Shares
Name of Beneficial Owner	at June 19, 2006		Outstanding
5% Stockholders:
Heller 2002 Trust
Fred P. Heller—Trustee
1700 Coronet Drive
Reno, Nevada 89509		845,328		5.66	%


JED OIL INC.
By:	/s/ Thomas J. Jacobsen
	Name:	Thomas J. Jacobsen
	Title:	Chief Executive Officer

	Date:	June 30, 2006


By:	/s/ David C. Ho
	Name:	David C. Ho
	Title:	Chief Financial Officer

	Date:	June 30, 2006


							For the 120
							period from
	For the year			For the year			inception on
	ended December			ended			September 3, 2003
	31,			December 31,			to December 31,
	2005			2004			2003
	$			$			$

Net income (loss) for the period		1,143,144			(8,546,930	)		(359,604	)

Other comprehensive income
Foreign exchange translation adjustment		(201,553	)		2,016,181			347,983

Comprehensive income (loss) for the period		941,591			(6,530,749	)		(11,621	)

Comprehensive income (loss) for the period per share [note 8]
- basic		0.07			(0.62	)		—
- diluted		0.06			(0.62	)		—


			2005
	Income		Shares		Per Share

Basic
Income attributable to common stock	$	1,143,144		14,470,086	$	0.08
Effect of dilutive securities
Stock options and warrants		—		803,696		—

Diluted
Income attributable to common stock, including assumed conversion	$	1,143,144		15,273,782	$	0.07


			2004
	Loss		Shares		Per Share

Basic
Loss attributable to common stock	$	8,546,930		10,599,437	$	(0.81	)