Exhibit 99.1

ANNUAL INFORMATION FORM

for the year ended December 31, 2007

March 31, 2008

TABLE OF CONTENTS

	Page
NOTE REGARDING FORWARD LOOKING STATEMENTS		1
GLOSSARY OF TERMS		2
ABBREVIATIONS		3
CONVERSION		3
CURRENCY OF INFORMATION		4
ORGANIZATIONAL STRUCTURE		4
JED Oil Inc		4
JED Production Inc.		4
JED Oil (USA) Inc		4
GENERAL DEVELOPMENT OF THE BUSINESS OF JED		4
3 Year History		4
Significant Acquisitions		5
Significant Dispositions		5
DESCRIPTION OF THE BUSINESS		5
Strategy		5
Revenue Sources		5
Employees		5
OPERATIONS REVIEW		5
Alberta, Canada		6
Wyoming, USA		6
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION		6
Disclosure of Reserves Data		6
Oil and Natural Gas Reserves and Net Present Value of Future Net Revenue		7
Reserves Data — Constant Prices and Costs		7
Reserves Data — Forecast Prices and Costs		9
Future Net Revenue by Production Group		10
Pricing Assumptions — Constant Prices and Costs		10
Pricing Assumptions — Forecast Prices and Costs		11
Reconciliations of Changes in Reserves and Future Net Revenue		12
Undeveloped Reserves		13
Properties with No Attributed Reserves		13
Significant Factors or Uncertainties Affecting Reserves Data		14
Future Development Costs		14
Future Abandonment Costs		15
Oil and Gas Wells		15
Undeveloped Acreage Summary		15
Additional Information Concerning Abandonment and Reclamation Costs		15
Tax Horizon		15
Costs Incurred		15
Production Estimates		16
Production History		17
INDUSTRY CONDITIONS		17
Pricing and Marketing — Natural Gas		17
Pricing and Marketing — Oil		18
The North American Free Trade Agreement		18
Royalties and Incentives		18
Environmental Regulation		19
Kyoto Protocol		19

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TABLE OF CONTENTS
(continued)

	Page
RISK FACTORS		20
DESCRIPTION OF SHARE CAPITAL		27
Common Shares		27
Series A Preferred Shares		27
Series B Preferred Shares		27
DIVIDENDS		28
Dividend Record		28
Restrictions on Dividend Payments		28
Dividend Policy		28
MARKET FOR SECURITIES		28
Trading Price and Volume		28
Prior Sales		29
DIRECTORS AND OFFICERS		29
Name, Occupation and Securityholding		29
Cease Trade Orders, Bankruptcies, Penalties or Sanctions		32
Conflicts of Interest		32
LEGAL PROCEEDINGS		32
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS		33
TRANSFER AGENT AND REGISTRAR		33
MATERIAL CONTRACTS		33
INTERESTS OF EXPERTS		33
ADDITIONAL INFORMATION		33
SEDAR		33
Management Information Circular		33
Financial Statements and MD&A		34
AUDIT COMMITTEE		34
General		34
Mandate of the Audit Committee		34
Relevant Education and Experience of Audit Committee Members		35
External Auditor Services Fees		36
Audit Committee Oversight		36
APPENDIX “A” AUDIT COMMITTEE CHARTER		A-1
APPENDIX “B” REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR		B-1
APPENDIX “C” REPORT ON RESERVES DATA BY MANAGEMENT AND DIRECTORS		C-1

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NOTE REGARDING FORWARD LOOKING STATEMENTS

Certain statements contained in this annual information form and in documents incorporated by reference constitute forward looking statements. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward looking statements. Management believes the expectations reflected in those forward looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward looking statements included herein should not be unduly relied upon. These statements speak only as of the date hereof.

In particular, this annual information form contains forward looking statements pertaining to the following:

• oil and natural gas production levels;

• capital expenditure programs;

• the quantity of the oil and natural gas reserves;

• projections of commodity prices and costs;

• supply and demand for oil and natural gas;

• expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; and

• treatment under governmental regulatory regimes.

The actual results could differ materially from those anticipated in these forward looking statements as a result of the risk factors set forth below and elsewhere in this annual information from:

• volatility in market prices for oil and natural gas;

• liabilities inherent in oil and natural gas operations;

• uncertainties associated with estimating oil and natural gas reserves;

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

• incorrect assessments of the value of acquisitions;

• geological, technical, drilling and processing problems;

• fluctuations in foreign exchange or interest rates and stock market volatility;

• failure to realize the anticipated benefits of acquisitions; and

• the other factors discussed under “Risk Factors”.

These factors should not be construed as exhaustive. We do not undertake any obligation to publicly update or revise any forward looking statements.

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GLOSSARY OF TERMS

The following are defined terms used in this Annual Information Form:

“$” means currency of the United States of America unless otherwise stated;

“Agreement of Business Principles” means the Agreement of Business Principles as twice amended and restated among the Trust, JED and JMG, dated effective September 1, 2003 as between the Trust and JED and August 1, 2006 as among the Trust, JED and JMG, and terminated September 28, 2007;

“AMEX” means the American Stock Exchange;

“board of directors” means the board of directors of JED;

“Caribou” means Caribou Resources Corp., a corporation incorporated under the laws of Alberta, which was acquired by JED effective July 31, 2007 and its name was changed to JPI;

“CGE” means CG Engineering Ltd., independent petroleum engineering consultants of Calgary, Alberta;

“CGE Report” means the independent engineering evaluation of certain oil, NGL and natural gas interests of JED prepared by CGE dated March 12, 2007 and effective December 31, 2007;

“Common Shares” means the common shares in the capital stock of JED;

“Company” means JED, together with its wholly-owned subsidiaries where relevant;

“Enterra” means Enterra Energy Corp., a corporation incorporated under the laws of Alberta;

“JED” means JED Oil Inc., a corporation incorporated under the laws of Alberta;

“JED USA” means JED Oil (USA) Inc., a corporation incorporated under the laws of Wyoming, and a wholly-owned subsidiary of JED;

“JMG” means JMG Exploration, Inc., a corporation incorporated under the laws of Nevada;

“JPI” means JED Production Inc., a corporation incorporated under the laws of Alberta and resulting from a name change to Caribou, and a wholly-owned subsidiary of JED;

“Notes” means the 10% Senior Subordinated Convertible Notes issued by JED;

“Preferred Shares” means the preferred shares in the capital stock of JED, including the Series A Preferred Shares, the Series B Preferred Shares and any other series of preferred shares which the board of directors may create;

“Series A Preferred Shares” means the Series A convertible preferred shares in the capital stock of JED;

“Series B Preferred Shares” means the Series B convertible preferred shares in the capital stock of JED;

“Shareholders” means holders from time to time of the Common Shares and any series of Preferred Shares;

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“Joint Services Agreements” means the three Joint Services Agreements each dated effective January 1, 2007, between JED and Enterra; JED and JMG, and Enterra and JMG respectively;

“Trust” means Enterra Energy Trust, an incorporated open ended investment trust governed by the laws of Alberta;

ABBREVIATIONS

Oil and Natural Gas Liquids		Natural Gas
bbl	Barrel	Mcf	thousand cubic feet
bbls	Barrels	Mmcf	million cubic feet
mbbls	thousand barrels	Bcf	billion cubic feet
bbls/d	barrels per day	mcf/d	thousand cubic feet per day
NGLs	natural gas liquids	mmcf/d	million cubic feet per day
GJ	Gigajoule	MMBTU	million British Thermal Units
GJ/d	Gigajoule per day

Other
AECO-C	Intra-Alberta Nova Inventory Transfer Price (NIT net price)
API	American Petroleum Institute
°API	an indication of the specific gravity of crude oil measured on the API gravity scale. Liquid petroleum with a specified gravity of 28 °API or higher is generally referred to as light crude oil
ARTC	Alberta Royalty Tax Credit
BOE	barrel of oil equivalent of natural gas and crude oil on the basis of 1 BOE for 6 (unless otherwise stated) mcf of natural gas (this conversion factor is an industry accepted norm and is not based on either energy content or current prices)
BOE/D	barrel of oil equivalent per day
M3	cubic metres
MBOE	1,000 barrels of oil equivalent
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade
MW/h	Megawatts per hour

CONVERSION

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

To Convert From	To	Multiply By
Mcf	Cubic metres		28.174
Cubic metres	Cubic feet		35.494
Bbls	Cubic metres		0.159
Cubic metres	Bbls oil		6.290
Feet	Metres		0.305
Metres	Feet		3.281
Miles	Kilometres		1.609
Kilometres	Miles		0.621
Acres	Hectares		0.405
Hectares	Acres		2.47

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CURRENCY OF INFORMATION

The information set out in this annual information form is stated as at December 31, 2007 unless otherwise indicated. Capitalized terms used but not defined in the text are defined in the Glossary.

ORGANIZATIONAL STRUCTURE

JED Oil Inc.

JED was incorporated under the Business Corporations Act (Alberta) on September 3, 2003. Its Articles of Incorporation have been amended four times: to create the Series A preferred shares, split the Common Shares on the basis of 3 for 2, create the Series B preferred shares and amend the terms of the Series B preferred shares.

The Company’s principal business address and registered office is 1601 15^th, Didsbury, Alberta, T0M 0W0 and has been since April 1, 2007.

JED Production Inc.

On July 31, 2007, JED acquired all of the issued and outstanding shares of Caribou, an Alberta corporation, making it a wholly-owned subsidiary, and changed its name to JPI.

JED Oil (USA) Inc.

JED USA is JED’s other subsidiary and is wholly owned by JED. It is incorporated under the laws of Wyoming.

GENERAL DEVELOPMENT OF THE BUSINESS OF JED

3 Year History

The concept for the organization of JED was created by the management of the Trust and its administrator, Enterra. The business purpose was the creation of a company that would operate and develop Enterra’s assets and possibly be a source of additional assets for the Trust. JED was appointed the operator of Enterra’s assets and the employees of Enterra except the Chief Executive Officer and the Chief Financial Officer became employees of JED. JMG was incorporated to be an exploration company. Under the Agreement of Business Principles agreement, Enterra would acquire assets, farmout the development drilling to JED and exploration drilling to JMG, and have the opportunity to acquire JED’s production when JED decided to sell. JED, Enterra and JMG shared office space and staff under a Joint Services Agreement.

During 2005 there was recognition that the initial relationship between JED and the Trust had served its purpose in the start-up phase of both, and that it was now time for the relationship to evolve into more separation between the parties and more of a standard arms-length relationship. Enterra acquired a new management team in June, 2005 and began to employ its own staff. Effective January 1, 2006, the Technical Services Agreement was terminated and replaced by Joint Services Agreements between JED and Enterra, JED and JMG and Enterra and JMG. A number of JED’s employees that had worked primarily with the production from existing wells became employees of Enterra. In addition JED and Enterra no longer shared office space, and during 2006 completed the process of separating all remaining shared software systems and other resources. The Agreement of Business Principles and the Joint Services Agreements between JED and Enterra and JMG and Enterra were terminated effective September 28, 2006.

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During 2006 JED continued to supply staff, other than the CEO and CFO, and administrative services to JMG under their Joint Services Agreement, which was terminated at the end of 2006.

Significant Acquisitions

Effective July 31, 2007, JED acquired all of the issued and outstanding shares of Caribou under a Plan of Arrangement under the Business Corporations Act (Alberta); acquired the loan of the major secured creditor, and funded a Plan of Arrangement under the Companies’ Creditors Arrangement Act (Canada). With Caribou as a wholly-owned subsidiary of JED’s, the name was changed to JPI.

Significant Dispositions

On June 8, 2007, JED sold its North Ferrier area of Alberta oil and gas assets to an arms-length third party for $36.6 million. JED’s oil and gas assets in the Sousa area of Alberta were sold to an arms length third party for $0.7 million on June 29, 2007. The oil and gas assets in the Redwater area of Alberta of JPI were sold for $7 million to an arms length third party on October 10, 2007.

DESCRIPTION OF THE BUSINESS

Strategy

JED through itself and JPI are engaged in the development and operation of low risk and low cost crude oil and natural gas in Western Canada and through JED USA in the rocky mountain states of the United States, and sell developed production from time to time at a profit. Initially the majority of opportunities both to drill and to sell developed production were through the Trust and now have been expanded to include any opportunities that we source. Occasionally JED may purchase specific properties with drilling upside. Our drilling programs will be financed primarily with existing cash flow, sale of existing production at a profit and bank debt.

Revenue Sources

For the year ended December 31, 2007, approximately 65.7% of the revenue from our properties was derived from natural gas and approximately 34.3% was derived from crude oil and natural gas liquids.

Following the acquisition of JPI, which increased our percentage of natural gas production, currently JED’s revenues are split approximately 35.8%/64.2% between natural gas, and crude oil and natural gas liquids.

Employees

At December 31, 2007, we had approximately 28 employees and consultants working both in the Didsbury head office and in field operations.

OPERATIONS REVIEW

JED has assets in Ferrier in west central Alberta. Through JPI we acquired assets in Northern Alberta. Through JED USA, we have assets in Pinedale, Wyoming. JED has created a significant inventory of prospects in these areas.

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Alberta, Canada

     Ferrier Area

JED refers to its remaining Ferrier assets as West Ferrier to distinguish it from the North Ferrier assets that were sold in June of 2007. The property is located in west central Alberta and consists of two sections of land. In 2007 JED drilled 3 (2.4 net) wells targeting the liquids rich Ellerslie and Rock Creek Formations resulting in 1 (0.8 net) Ellerslie producing gas well and 2 (1.6 net) standing wells with Ellerslie and Rock Creek gas potential. JED is currently accepting offers for the West Ferrier assets as part of a plan that would generate funds to be re-invested into further drilling activity.

     Northern Alberta Prospect Area

JED has a 95% working interest in assets controlled by JPI, a wholly owned subsidiary of JED originating from the acquisition of Caribou Resources Corp. The northern Alberta assets are located in the north eastern corner of the province and provide a significant land base to pursue natural gas and light oil development opportunities.

JED’s drilling activities in Northern Alberta focused on light oil development drilling surrounding the Steen River Astrobleme structure. 3 wells (2.85 net) were drilled at Marlowe West. A work-over was performed on an existing well and 3 wells(2.85 net) were drilled at Marlowe North. As of Dec. 31, 2007, all of the wells at Marlowe North were on production. The Marlowe West wells were awaiting completion and testing operations.

     Pinedale, Wyoming, USA

JED has an interest in 2 producing wells located on the Pinedale Anticline. At present the company has no plans to further develop this property but is actively seeking a farm out arrangement.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The effective date of the Statement is December 31, 2007, and the preparation date of the Statement is March 31, 2008.

Disclosure of Reserves Data

The reserves data set forth below (the “Reserves Data”) is based upon an evaluation by CGE with an effective date of December 31, 2007 contained in the CGE Report. The Reserves Data summarizes the oil, liquids and natural gas reserves of the Company and the net present values of future net revenue for these reserves using constant prices and costs and forecast prices and costs. The CGE Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserves definitions contained in National Instrument 51-101 Standard for Disclosure for Oil and Gas Activities (“NI 51-101”). Additional information not required by NI 51-101 has been presented to provide continuity and additional information which we believe is important to the readers of this information. JED engaged CGE to provide an evaluation of proved and proved plus probable reserves.

JED has assigned reserves in the province of Alberta, and JED USA has assigned reserves in the states of North Dakota and Wyoming.

Disclosure provided herein in respect of BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency

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conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Oil and Natural Gas Reserves and Net Present Value of Future Net Revenue

In accordance with NI 51-101 CGE prepared the CGE Report. The CGE Report evaluated, as at December 31, 2007, JED’s oil, natural gas liquids (“NGL”) and natural gas reserves. The tables below are a summary of the oil, NGL and natural gas reserves of JED and the net present value of future net revenue attributable to such reserves as evaluated in the CGE Report based on both constant and forecast price and cost assumptions. The tables summarize the data contained in the CGE Report and as a result may contain slightly different numbers than the reports due to rounding. Also due to rounding, certain columns may not add exactly.

The net present value of future net revenue attributable to JED’s reserves is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures, and well abandonment costs for only those wells assigned reserves by CGE. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to JED’s reserves estimated by CGE represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized in this AIF. The recovery and reserve estimates of JED’s oil, NGL and natural gas reserves provided in this AIF are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

The CGE Report is based on certain factual data supplied by JED and CGE’s opinion of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to JED’s petroleum properties and contracts (except for certain information residing in the public domain) were supplied by JED to CGE and accepted without any further investigation. CGE accepted this data as presented and neither title searches nor field inspections were conducted.

Reserves Data — Constant Prices and Costs

Summary of Oil and Gas Reserves
as at December 31, 2007
Constant Prices and Costs

	Light & Medium						Natural Gas
	Oil				Heavy Oil		Liquids				Natural Gas
	Gross		Net		Gross	Net	Gross		Net		Gross		Net
Reserves Category	[mbbl]		[mbbl]		[mbbl]	[mbbl]	[mbbl]		[mbbl]		[mmcf]		[mmcf]
PROVED
Developed Producing		1,195.0		874.0	Nil	Nil		96.9		71.1		7,260.3		5,937.5
Developed Non-Producing		475.0		341.8	Nil	Nil		7.1		5.1		1,072.5		804.7
Undeveloped		712.5		514.6	Nil	Nil		3.7		2.8		840.6		612.0
TOTAL PROVED		2,382.5		1,730.4	Nil	Nil		107.7		79.0		9,173.5		7,354.2
TOTAL PROBABLE		788.5		577.6	Nil	Nil		124.9		92.6		8,097.0		6,298.1
TOTAL PROVED PLUS PROBABLE		3,171.0		2,308.0	Nil	Nil		232.6		171.6		17,270.5		13,652.3

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Net Present Values of Future Net Revenue
as at December 31, 2007
Constant Prices and Costs

	Net Present Values of Future Net Revenue
	Constant Prices and Costs
	Before Income Taxes Discounted at (%/year)										After Income Taxes Discounted at (%/year)
	0		5		10		15		20		0		5		10		15		20
Reserves Category	[$mm]		[$mm]		[$mm]		[$mm]		[$mm]		[$mm]		[$mm]		[$mm]		[$mm]		[$mm]
PROVED
Developed Producing		91,309.3		78,806.1		69,648.8		62,577.3		56,926.5		91,309.3		78,806.1		69,648.8		62,577.3		56,926.5
Developed Non-Producing		28,752.8		25,544.3		22,937.7		20,788.0		18,991.6		28,752.8		25,544.3		22,937.7		20,788.0		18,991.6
Undeveloped		35,744.0		31,201.4		27,512.2		24,471.9		21,933.7		35,744.0		31,210.4		27,512.2		24,471.9		21,933.7
TOTAL PROVED		155,806.1		135,551.8		120,098.6		107,837.2		97,851.8		155,806.1		135,551.8		120,098.6		107,837.2		97,851.8
TOTAL PROBABLE		69424.5		51,359.2		39,709.7		31,530.3		25,511.6		69,424.5		51,359.2		39,709.7		31,530.3		25,511.6
TOTAL PROVED + PROBABLE		225,230.6		186,911.0		159,808.3		139,367.5		123,363.4		225,230.6		186,911.0		159,808.3		139,367.5		123,363.4

Total Future Net Revenue
(Undiscounted)
as at December 31, 2007
Constant Prices and Costs

Future Net

Future Net

Revenue

Revenue

Royalties

Capital

Before

After

`

Net of

Operating

Development

Abandonment

Income

Income

Income

Revenue

ARTC

Costs

Costs

Costs

Taxes

Taxes

Taxes

Reserves Category

[$m]

[$m]

[$m]

[$m]

[$m]

[$m]

[$m]

[$m]

Total Proved

276,522.2

65,470.1

41,988.0

11,003.5

2,254.6

155,806.1

Nil

155,806.1

Total Probable

129,642.5

26,225.8

25,672.2

8,055.0

265.0

69,424.5

Nil

69,424.5

Total Proved + Probable

406,164.7

91,695.8

67,660.2

19,058.5

2,519.6

225,230.6

Nil

225,230.6

Future Net Revenue by Production Group
as at December 31, 2007
Constant Prices and Costs

	Future Net Revenue Before Income
	Taxes and Discounted at 10%/year
Reserves Category	[$mm]
PROVED
Light and Medium Crude Oil		100.2
Heavy Oil	Nil
Natural Gas		16.8
Natural Gas Liquids		3.1
Proved Plus Probable
Light and Medium Crude Oil		126.3
Heavy Oil	Nil

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	Future Net Revenue Before Income
	Taxes and Discounted at 10%/year
Reserves Category	[$mm]
Natural Gas		27.4
Natural Gas Liquids		6.0

Reserves Data — Forecast Prices and Costs

Summary of Oil and Gas Reserves
as at December 31, 2007
Forecast Prices and Costs

	Light & Medium						Natural Gas
	Oil				Heavy Oil		Liquids				Natural Gas
	Gross		Net		Gross	Net	Gross		Net		Gross		Net
Reserves Category	[mbbl]		[mbbl]		[mbbl]	[mbbl]	[mbbl]		[mbbl]		[mmcf]		[mmcf]
PROVED
Developed Producing		1,192.8		872.1				96.5		71.0		7,247.7		5,926.5
Developed Non-Producing		475.0		341.8				7.1		5.1		1,072.2		804.4
Undeveloped		712.5		514.6				3.7		2.8		840.1		611.5
TOTAL PROVED		2,380.3		1,728.5				107.3		78.9		9,160.0		7,342.3
TOTAL PROBABLE		787.8		577.0	Nil	Nil		123.9		92.1		8,086.2		6,288.9
TOTAL PROVED PLUS PROBABLE		3,168.1		2,305.5	Nil	Nil		231.3		171.0		17,246.2		13,631.3

Net Present Values of Future Net Revenue
as at December 31, 2007
Forecast Prices and Costs

	Net Present Values of Future Net Revenue
	Forecast Prices and Costs
	Before Income Taxes Discounted at (%/year)										After Income Taxes Discounted at (%/year)
	0		5		10		15		20		0		5		10		15		20
Reserves Category	[$mm]		[$mm]		[$mm]		[$mm]		[$mm]		[$mm]		[$mm]		[$mm]		[$mm]		[$mm]
PROVED
Developed Producing		70,564.7		60,336.5		53,133.7		47,691.5		43,394.5		70,564.7		60,336.5		53,133.7		47,691.5		43394.5
Developed Non- Producing		20,915.5		18,615.9		16,740.7		15,188.9		13,887.7		20,915.5		18,615.9		16,740.7		15,188.9		13,887.7
Undeveloped		24,119.5		20,943.1		18,350.4		16,204.2		14,404.9		24,119.5		20,943.1		18,350.4		16,204.2		14,404.9
TOTAL PROVED		115,599.7		99,895.5		88,224.8		79,084.6		71,687.1		115,599.7		99,895.5		88,224.8		79,084.6		71,687.1
TOTAL PROBABLE		53,139.5		37,850.1		28,663.9		22,392.5		17,827.4		53,139.5		37,850.1		28,663.9		22,392.5		17,827.4
TOTAL PROVED PLUS PROBABLE		168,739.2		137,745.6		116,888.7		101,477.1		89,514.5		168,739.2		137,745.6		116,888.7		101,477.1		89,514.5

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Total Future Net Revenue
(Undiscounted)
as at December 31, 2007
Forecast Prices and Costs

Future Net

Future Net

Revenue

Revenue

Royalties

Capital

Before

After

Net of

Operating

Development

Abandonment

Income

Income

Income

Revenue

ARTC

Costs

Costs

Costs

Taxes

Taxes

Taxes

Reserves Category

[$m]

[$m]

[$m]

[$m]

[$m]

[$m]

[$m]

[$m]

Total Proved

233,825.6

57,543.0

46,745.1

11,245.9

2,691.9

115,599.7

Nil

115,599.7

Total Probable

122,152.0

27,508.1

32,703.8

8,216.1

584.5

53,139.5

Nil

53,139.5

Total Proved + Probable

355,977.6

85,051.1

79,448.9

19,462.0

168,739.2

Nil

168,739.2

Future Net Revenue by Production Group

Future Net Revenue Before Income Taxes
(Discounted at 10%/year)

		Forecast Prices and Costs
Reserves Category	Production Group	$M
Proved	Light and Medium Oil		70.9
	Heavy Oil	Nil
	Natural Gas		14.7
	Natural Gas Liquids		2.6
Proved Plus Probable	Light and Medium Oil		88.7
	Heavy Oil	Nil
	Natural Gas		23.2
	Natural Gas Liquids		5.0

Pricing Assumptions — Constant Prices and Costs

CGE employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2007, in estimating JED’s reserves data using constant prices and costs.

Pricing Assumptions
Constant Prices and Costs

	Edmonton Par Price		Natural Gas		Natural Gas Liquids
	40 API		AECO’C’		Edmonton Reference Price
Year	[$Cdn/bbl]		[$Cdn/Mmbtu]		[$Cdn/bbl]		$US/$Cdn
2007 (Year End)		93.18		6.49	Ethane	17.94		0.99
					Propane	60.57
					Butane	79.20
					Pentanes +	95.98

Pricing Assumptions — Forecast Prices and Costs

CGE employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2007, in estimating JED’s reserves data using forecast prices and costs.

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			Alberta		Edmonton
	Edmonton		Average		Cond. &										US/CAN
	Par Price		Plantgate		Natural		Edmonton		Edmonton		Edmonton				Exchange
	40 API		Price		Gasolines		Propane		Butanes		NGL Mix		Inflation		Rate
Year	[$Cdn/bbl]		[$Cdn/Mmbtu]		[$Cdn/bbl]		[$Cdn/bbl]		[$Cdn/bbl]		[$Cdn/bbl]			%	$US/$CAN
Forecast
2007		78.50		6.05		80.00		43.10		54.60		54.50		2.0		0.975
2008		76.90		6.70		78.40		43.90		53.50		54.20		2.0		0.950
2009		72.90		6.90		74.50		42.80		50.70		51.90		2.0		0.950
2010		71.60		7.00		73.20		42.60		49.80		51.20		2.0		0.950
2011		70.20		7.15		71.80		42.40		48.90		50.60		2.0		0.950
2012		68.60		7.25		70.30		42.00		47.70		49.70		2.0		0.950
2013		67.10		7.40		68.80		41.70		46.70		48.90		2.0		0.950
2014		68.30		7.50		70.00		42.40		47.50		49.70		2.0		0.950
2015		69.80		7.70		71.60		43.40		48.50		50.90		2.0		0.950
2016		71.10		7.85		72.90		44.20		49.50		51.80		2.0		0.950
2017		72.60		8.00		74.40		45.10		50.50		52.90		2.0		0.950
2018		74.00		8.15		75.90		46.00		51.50		53.90		2.0		0.950
2019		75.50		8.35		77.40		47.00		52.50		55.00		2.0		0.950
2020		77.00		8.50		78.90		47.90		53.60		56.10		2.0		0.950
2021		78.60		8.70		80.60		49.00		54.70		57.30		2.0		0.950
Thereafter	+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr

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Reconciliations of Changes in Reserves and Future Net Revenue

     Reserves Reconciliation

The following tables set forth reconciliations of JED’s total proved, probable and total proved plus probable reserves as at December 31, 2007, based on constant price and cost assumptions, and then based on forecast prices and costs.

Reconciliation of Company Net Remaining Gas Reserves (After Royalties)
by Product Type as at December 31, 2007
Constant Prices and Costs

	Sales Gas (MMCF)									Light/Medium Oil (MBBL)
	TP			PA			TP + PA				TP			PA			TP + PA
December 31, 2006		6,032			2,607			8,639				40.5			14.4			54.9
Extensions
Technical Revision		80			32			112				515			205			720
Acquisitions		6093.3			6185.2			12,278.5
Dispositions		(6,335.2	)		(2577	)		(8912.2	)			(32.8	)		(33.6	)		(66.4	)
Discoveries		177.9			50.8			228.7				1,135			325			1460
Production		1,306						1306				72.3						72.3
December 31, 2007		7,354			6,298			13,652				1,730			578			2,308

	NGL (MBBL)
	TP			PA			TP + PA
December 31, 2006		276.9			120.6			397.5
Extensions
Technical Revision
Acquisitions
Dispositions		(239.2	)		(28	)		(267.2	)
Discoveries
Production		41.3						41.3
December 31, 2007		79.0			92.6			171.6

     Future Net Revenue Reconciliation

The following table sets forth a reconciliation of the estimate of the net present value of future net revenue attributable to JED’s reserves as evaluated by CGE as at December 31, 2006 against the estimate of such amount as at December 31, 2007, as evaluated in the CGE Report, calculated after tax using a discount rate of 10% and constant price and cost assumptions.

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Reconciliation of Changes in Net Present Values of Future Net Revenue
Discounted at 10% Per Year
Proved Reserves
Constant Prices and Costs

	2007
	($M)
Estimated Net Present Value at December 31, 2006		28,948
Oil and Gas Sales During the Period Net of Production Costs and Royalties		(10,320	)
Changes due to Prices Production Costs and Royalties Related to Future Production
Changes in Development Costs During the Period(3)
Changes in Forecast Development Costs(4)
Changes resulting from Extensions and Improved Recovery(5)
Changes Resulting from Discoveries(5)		70,516
Changes Resulting from Acquisitions of Reserves(5)		39,370
Changes Resulting from Dispositions of Reserves(5)		(30,851	)
Accretion of Discount(6)
Net Change in Income Tax(7)
Changes Resulting from Technical Reserves Revisions		22,436
All Other Changes
Estimated Net Present Value at December 31, 2007		120,099

(1)	JED Actual before income taxes, excluding G&A.
(2)	The impact of changes in prices and other economic factors on future net revenue.
(3)	Actual capital expenditures relating to the exploration, development and production of oil and gas revenues.
(4)	The change in forecast development costs for the properties evaluated at the beginning of the period.
(5)	End of period net present value of related reserves.
(6)	Estimated as 10% of beginning of period net present value
(7)	The difference between forecast income taxes at beginning of period and actual taxes for the period plus forecast income taxes at the end of period.

Undeveloped Reserves

The following table sets forth the proved undeveloped reserves by product type, included in the Company’s reported reserves at December 31, 2007:

	Gross	Net
Light/Medium Oil	712.5 mbbls	514.6 mbbls
Natural Gas	840.6 mmcf	612.0 mmcf
Natural Gas Liquids	3.7 mbbls	2.8 mbbl

Approximately 100% of the undeveloped reserves are scheduled to be developed in the 2007 calendar year subject to available capital.

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Properties with No Attributed Reserves

At December 31, 2007, $428,791 had been spent on capital expenses for development in the Ferrier area of Alberta and the Pinedale area of Wyoming, for which no reserves were attributed to the property at December 31, 2007. The well(s) came on production in 2007 and reserves will be assigned in the 2007 year-end reserve report.

Significant Factors or Uncertainties Affecting Reserves Data

The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserves estimates contained in this AIF are based on current production forecasts, prices and economic conditions. JED’s reserves are evaluated by CGE, an independent engineering firm.

As circumstances change and additional data become available, reserves estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions.

Although every reasonable effort is made to ensure that reserves estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserves estimates can arise from changes in year-end oil and gas prices, and reservoir performance. Such revisions can be either positive or negative.

Future Development Costs

The table below sets out the development costs deducted in the estimation of future net revenue attributable to proved reserves (using both constant prices and costs and forecast prices and costs) and proved plus probable reserves (using forecast prices and costs only).

	Forecast Prices and Costs ($M)								Constant Prices and Costs
	Proven Reserves				Proved Plus Probable Reserves				Proved Reserves
Year	0%		10%		0%		10%		0%		10%
2007		11030		10911		19246		19018		10814		10697
2008
2009
2010
2011
Thereafter		216		122		216		122		190		107
Total		11246		11033		19,462		19141		11004		10804

JED plans to fund the future development costs disclosed above with a combination of internally generated cash flow, debt financing, proceeds of disposition of minor properties and new equity issues if appropriate. In this regard, in the first quarter of 2008, JED negotiated a Revolving Demand Credit Facility with a Canadian bank.

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Future Abandonment Costs

The table below sets out the abandonment costs deducted in the estimation of future net revenue attributable to proved reserves (using both constant prices and costs and forecast prices and costs) and proved plus probable reserves (using forecast prices and costs only).

	Forecast Prices and Costs ($M)								Constant Prices and Costs
	Proven Reserves				Proved Plus Probable Reserves				Proved Reserves
Year	0%		10%		0%		10%		0%		10%
2007		97		92		97		91		95		90
2008		237		206		139		120		228		198
2009		101		79		101		80		95		75
2010		327		234		51		37		302		216
2011		182		119		190		124		148		96
Thereafter		1748		672		26981		865		1387		561
Total		2692		1402		3276		1317		2255		1236

Oil and Gas Wells

The following table summarizes JED’s interest as at December 31, 2007, in wells that are producing and non-producing.

			Gross						Net
	Producing		Shut-in		Suspended		Producing		Shut-in		Suspended
Oil:   Alberta		6		2		0		5.7		1.9		0
North Dakota		5		0		0		2.6		0		0
Wyoming		0		0		0		0		0		0
Gas: Alberta		38		4		0		25.5		3.6		0
North Dakota		0		0		0		0		0		0
Wyoming		2		0		0		0.9		0		0
Totals:		49		6		0		34.7		5.5		0

Shut in wells have encountered oil or gas and are waiting on facilities to produce.

Suspended wells have encountered oil or gas but are uneconomic to produce.

Undeveloped Acreage Summary

At December 31, 2007 JED had 148,701 acres inventory of undeveloped land.

JED estimates well abandonment costs by area. Such costs are included in the CGE Report as deductions in arriving at future net revenue. The expected total abandonment costs included in the CGE Report for 42.3 net wells under the proved reserves category is $2,691,900 undiscounted ($1,402,100 discounted at 10%).

Tax Horizon

JED did not pay income taxes during the year ended December 31, 2007. Based on a strategy of re-investing fully all internally generated cash flow in an exploration and development program and based on the commodity prices used in the CGE Report, JED estimates that it will not be required to pay income taxes for the foreseeable future.

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Costs Incurred

For the year ended December 31, 2007, JED incurred the following costs on its properties:

Cost Incurred Year Ended
December 31, 2007

	Canada		USA
	($ CDN thousands)		($ US thousands)
Property Acquisition Costs		—		—
Exploration Costs		—		15,782
Development Costs		39,825		—
TOTAL		39,825		15,782

Exploration and Development Activities
Year Ended December 31, 2007

	Exploratory Wells				Development Wells
	Gross		Net		Gross		Net
Oil		—		—		5.0		4.75
Gas		—		—		1.0		0.8
Standing		—		—		3.0		2.55
Dry and Abandoned		1.0		1.0		0		0
TOTAL		1.0		1.0		9.0		8.1

Production Estimates

The following table discloses for each product type the total volume of production estimated by CGE for 2008 in the estimates of future net revenue from proved reserves disclosed above under the heading “Oil and Natural Gas Reserves and Net Present Value of Future Net Revenue”. The following calendar day rate production estimates are applicable under both constant and forecast price scenarios for:

Company’s Production Estimated for
Year Ended December 31, 2008

	Light & Medium					Natural Gas
	Oil		Heavy Oil	Natural Gas		Liquids		BOE
	Gross		Gross	Gross		Gross		Gross
Reserves Category	[bbl/d]		[bbl/d]	[mcf/d]		[bbl/d]		[BOE/d]
PROVED
Developed Producing		810			3805		63		1507
Developed Non-Producing		326			800		5		464
Undeveloped		517			1125		5		710
TOTAL PROVED		1653			5730		72		2681
PROBABLE		29			2603		42		514
TOTAL PROVED PLUS PROBABLE		1638			8333		114		313

Production History The following table discloses, on a quarterly basis for the year ended December 31, 2007, JED’s share of average daily production volume, prior to royalties, and the prices

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received, royalties paid, production costs incurred and netbacks on a per unit of volume basis for each product type.

	Quarter Ended 2007
Average Daily Production	Mar 31		Jun 30		Sep 30		Dec 31
Nat Gas mcf/d		3,942		3,761		3,317		3,298
Oil bbl/d		52		46		258		392
NGL bbl/d		205		198		28		64
Combined (BOE/d)		914		871		839		1,005

	Quarter Ended 2007
Average Prices Received	Mar 31		Jun 30		Sep 30			Dec 31
Nat Gas ($/mcf)		6.78		7.37		5.80			4.86
Oil ($/bbl)		31.41		50.88		44.45			65.19
NGL ($/bbl)		41.90		58.50		71.62			155.18
Combined ($/BOE)		40.42		47.84		39.01			51.19
Royalties — Combined ($/BOE)		6.66		8.33		(4.37	)		(6.64	)
Operating Expenses — Combined ($/BOE)		4.71		5.65		15.93			24.01
Netback Received — Combined ($/BOE)		29.06		33.86		27.46			33.83

INDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulations imposed by various levels of government in both Canada and the United States. It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and gas companies of similar size with assets in the same areas and jurisdictions. All current legislation is a matter of public record, and we are unable to predict what additional legislation or amendments may be enacted.

Pricing and Marketing — Natural Gas

Canada, including Alberta

In Canada, the price of natural gas sold intra-provincially or to the United States is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the National Energy Board (“NEB”) and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain criteria prescribed by the NEB and the government of Canada. Natural gas exports for a term of less than two years requires a general short term export license while terms greater than two years require a long term export license for the particular gas sold (in quantities of not more than 30,000 cubic metres/d). Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export licence from the NEB and the issue of such a licence requires the approval of the Governor in Council.

The government of Alberta also regulates the volume of natural gas, which may be removed from this province for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.

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United States, including North Dakota and Wyoming

In the United States, JED’s gas production is sold under short-term (less than one year) agreements at prices negotiated with third parties, which are based on market-sensitive prices referred to as “spot market” sales. Prices on the spot market have been volatile.

Pricing and Marketing — Oil

Canada, including Alberta

In Canada, producers of oil negotiate sales contracts directly with oil purchasers. Oil prices are primarily based on worldwide supply and demand. The specific price paid depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance. Oil exports may be made pursuant to export contracts with terms not exceeding one year in the case of light crude oil, and not exceeding two years in the case of heavy crude oil, provided that an order approving any such export has been obtained from the 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 licence from the NEB and the issue of such a licence requires the approval of the Governor in Council.

United States, including North Dakota and Wyoming

In the United States, producers of oil also negotiate sales contracts directly with oil purchasers. JED’s oil production is sold under short-term (less than one year) agreements at prices negotiated with third parties.

The North American Free Trade Agreement

On January 1, 1994, the North American Free Trade Agreement (“NAFTA”) between 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.

Royalties and Incentives

Canada, including Alberta

In addition to federal regulation, each province has legislation and regulations, which govern land tenure, royalties, production rates, environmental protection and other matters. In all Canadian jurisdictions, producers of oil and natural gas are required to pay annual rental payments in respect of Crown leases and royalties and freehold production taxes in respect of oil and natural gas produced from Crown and freehold lands, respectively. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of

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the value of the gross production, and 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 Canada and Alberta have established incentive programs which have included royalty-rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects. These programs reduce the amount of Crown royalties otherwise payable.

Environmental Regulation

Canada, including Alberta

In Canada, the oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced in association with certain oil and natural gas industry operations, and can affect the location of wells and facilities and the extent to which exploration and development is permitted. In addition, legislation requires that well and facilities sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of that legislation may result in the imposition of fines or issuance of clean-up orders.

United States, including North Dakota and Wyoming

In the United States, the oil and natural gas industry is subject to environmental regulation pursuant to federal, state and local environmental laws and regulations, including those governing discharges into the air and water, the handling and disposal of solid and hazardous wastes, the remediation of soil and groundwater contaminated by hazardous substances and the health and safety of employees. Compliance with such environmental laws and regulations may require the acquisition of permits or other authorizations for certain activities and compliances with various standards or procedural requirements. These laws may provide for “strict liability” for damages to natural resources and threats to public health and safety, rendering a party liable for environmental damage without regard to negligence or fault on the part of such party. Sanctions for non-compliance may include revocation of permits, corrective action orders, administrative or civil penalties and criminal prosecution.

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. Our internal procedures are designed to ensure that the environmental aspects of new developments are taken into account prior to proceeding. We believe that we are in material compliance with applicable environmental laws and regulations.

Kyoto Protocol

Canada

In December of 2002, Canada became a signatory to the Kyoto Protocol. The implementation of this plan has not been fully defined by the Canadian government. 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 (as a necessary by-product and emission of hydrocarbon production), will bear a disproportionately large share of the anticipated cost of implementation.

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United States

The United States is not a signatory to the Kyoto Protocol.

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 Business Has a Going Concern Uncertainty

The consolidated financial statements have been prepared on a going concern basis which assumes that JED will be able to realize assets and discharge liabilities in the normal course of business for the foreseeable future.

The outcome of these matters is dependant on factors outside of the Company’s control and cannot be predicted at this time.

The consolidated financial statements do not include any adjustments relating to the recoverability or classification of assets or the amounts or classification of liabilities that might be necessary should the Company be unable to continue as a going concern.

Our Limited Number of Staff Constitutes a Material Weakness in our Internal Controls

Due to the limited number of staff at the Company, there is an inherent weakness in the system of internal controls due to our inability to achieve segregation of duties across all significant financial close and reporting processes. Our limited number of staff also results in weaknesses with respect to accounting for complex and non-routine accounting transactions as the Company does not have a sufficient number of finance personnel with technical accounting knowledge to address all complex and non-routine accounting matters that may arise, or may not recognize, or act on information due to their lack of technical accounting knowledge. As a result of these weaknesses there is no guarantee that a material misstatement would not be prevented or detected. These items have been classified as material weaknesses. Management and Board review are utilized to mitigate the risk of material misstatement in financial reporting to ensure internal controls remain effective and we will be able to remediate these weaknesses by expanding the number of individuals in our financial reporting area as we grow the Company.

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

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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. This occurred in the third quarter of 2007.

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. Our production levels will also decline as we sell production in accordance with our business plan and strategy.

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 CGE 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 CGE.

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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, and 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 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 and the drilling potential of undeveloped lands 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 and the potential for drilling undeveloped lands. Actual reserves or drilling results could vary materially from these estimates. Consequently, the reserves we acquire may be less than

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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, 2007, approximately 5% 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. The agreements governing our 10% Senior Subordinated Convertible Notes provide that if we are in

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default or fail to comply with certain covenants we can be required to immediately redeem the notes at 120% of their value.

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.

We currently have no credit facility and any future 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, state, provincial and federal legislation in both Canada and the United States. 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

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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 additional costs (future) 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 a single cost centre representing JED’s activity which is undertaken exclusively in Canada. 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 undiscounted 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 in that year, if appropriate. In addition, the value is further limited by including financing costs, administration expenses, future abandonment and site restoration costs and income taxes. 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.

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Financing and administration costs are excluded from the calculation under U.S. GAAP. At December 31, 2006, JED realized a U.S. GAAP ceiling test write-down of $5,044,975. At September 30, 2006, JED realized a U.S. GAAP ceiling test write-down of $60,970,560 million. There were no such write-downs required at December 31, 2007.

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, such as the resource allowance, 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.

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 dependent on our management and staff 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 may be, 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,

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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, we cannot guarantee that an active trading market will be sustained.

DESCRIPTION OF SHARE CAPITAL

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 December 31, 2007 there were 23,852,292 Common Shares issued and outstanding, 1,792,500 Common Shares reserved for issuance pursuant to stock options, 358,193 Common Shares reserved for issuance pursuant to share purchase warrants, 8,217,024 Common Shares are reserved for the conversion of the outstanding Senior Subordinated Convertible Notes, 3,880,024 Common Shares are reserved for the conversion of the outstanding Preferred B Shares; nil issued and outstanding Series A Preferred shares, and 1,797,498 Series B Preferred Shares issued and outstanding.

Common Shares

Each Common Share entitles its holder to receive notice of and to attend all meetings of the shareholders of JED and to one vote at such meetings. The holders of Common Shares will be, at the discretion of the JED Board and subject to applicable legal restrictions and to any preferences of holders of preferred shares, entitled to receive any dividends declared by the JED Board on the Common Shares. The holders of Common Shares will be entitled to share equally with each other and the holders of Series A Preferred Shares in any distribution of the assets of JED upon the liquidation, dissolution, bankruptcy or winding up of JED or other distribution of its assets among its Shareholders for the purpose of winding up its affairs. Such participation is subject to the rights, privileges, restrictions and conditions attaching to the Preferred Shares and other authorized series of preferred shares.

Series A Preferred Shares

JED has created a series of preferred shares consisting of 8,000,000 Series A Preferred Shares. Each Series A Preferred Share carries the right to one vote, to be converted to one Common Share during a conversion period commencing on the effective date of a registration statement filed with the Securities and Exchange Commission. The holders of Series A Preferred Shares will be, at the discretion of the JED Board and subject to certain applicable legal restrictions and to any preferences of holders of any other series of preferred shares, entitled to receive any dividends declared by the JED Board on the Series A Preferred Shares. The holders of Series A Preferred Shares will be entitled to share equally with each other and the holders of Common Shares in any distribution of the assets of JED upon the liquidation, dissolution, bankruptcy or winding up of JED or other distribution of its assets among its shareholders for the purpose of winding up its affairs.

Series B Preferred Shares

JED has created a series of preferred shares consisting of 2,200,000 Series B Preferred Shares. Each Series B Preferred Share will be redeemed by the Company on February 1, 2008 at a redemption amount of $16.00 per share and may be converted, at the holder’s option, to one Common Share at any time prior to redemption. Holders of Series B Shares receive dividends, payable quarterly, at the rate of 10% per annum, and are not entitled to vote at meetings of

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shareholders of JED, except in circumstances where otherwise non-voting shares are entitled to vote. At the holder’s option, dividends may be paid in Common Shares. In any distribution of the assets of JED upon the liquidation, dissolution, bankruptcy or winding up of JED or other distribution of its assets among its shareholders for the purpose of winding up its affairs the holders of Series B Preferred Shares will be entitled to receive the amount of $16.00 per share in priority to any distributions to holders of Common Shares and Series A Preferred Shares.

DIVIDENDS

Dividend Record

JED has not declared or paid any dividends on its Common Shares or its Series A Preferred Shares since its incorporation. Holders of the Series B Preferred Shares receive dividends of 10% per annum, payable quarterly. At the holder’s election, the dividends may be paid in Common Shares valued at the weighted closing average trading price of the Common Shares for the fifteen trading days immediately preceding the last day of the quarter for which the dividend is being paid. Since May 24, 2006 when Series B Preferred Shares were first issued, JED has paid a total of $4.4 million in dividends on the Series B Preferred Shares, of which $35,508.63 was paid by the issuance of 12,533 Common Shares.

Restrictions on Dividend Payments

The Business Corporations Act (Alberta) prohibits the declaration or payment of dividends by a corporation if there are reasonable grounds for believing that the corporation is, or would after the payment be, unable to pay its liabilities as they become due, or the realizable value of the corporation’s assets would thereby be less than the aggregate of its liabilities and stated capital of all classes of shares. In addition JED can not declare of pay dividends on any class of shares if any due and unpaid dividends on the Series B Preferred Shares are outstanding.

Dividend Policy

JED will continue to pay the dividends on the Series B Preferred Shares until all of the outstanding Series B Preferred Shares have been converted to Common Shares or redeemed. JED does not foresee the declaration or payment of any dividends on its Common Shares in the near future. Any future decision to pay dividends on the Common Shares will be made by the board of directors on the basis of JED’s earnings, financial requirements and other conditions existing at such future time.

MARKET FOR SECURITIES

Trading Price and Volume

The outstanding Common Shares are traded on the American Stock Exchange (“AMEX”) under the trading symbol “JDO”. The following table sets forth the price range and trading volume of the Common Shares as reported by AMEX for the periods indicated.

	AMEX
2007	High ($)		Low ($)		Volume
January		2.90		2.10		200,400
February		2.37		1.53		195,000
March		2.39		1.30		262,600
April		2.98		1.55		521,600
May		2.45		1.36		264,400

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	AMEX
2007	High ($)		Low ($)		Volume
June		2.40		1.80		189,100
July		2.17		1.87		112,200
August		2.62		1.92		145,100
September		2.09		1.66		128,400
October		1.90		1.50		109,600
November		1.87		1.40		115,800
December		1.21		1.26		91,400

Prior Sales

During 2007, issued 3,852,956 Common shares in exchange for the issued shares of Caribou on the basis of one Common share of JED for each ten common shares of Caribou, and issued 5,000,000 shares for the benefit of creditors of Caribou under the Plan of Arrangement under the Companies’ Creditors Arrangement Act (Canada).

DIRECTORS AND OFFICERS

The JED Board currently consists of 4 individuals. The directors are elected by the holders of Common Shares by ordinary resolution, and hold office until the next annual meeting of shareholders, which is anticipated to be held in June, 2008

Name, Occupation and Security holding

The following table sets forth certain information respecting the directors and officers of JED.

Name and Municipality		Date First Appointed as
of Residence	Position Held	Director or Officer
Thomas J. Jacobsen(3) Didsbury, Alberta	Chief Executive Officer and Director	September 3, 2003
Ludwig Gierstorfer(1)(2) (3) (4) Cochrane, Alberta	Director	September 3, 2003
Justin W. Yorke(1)(2) (3) (4) Pasadena, California	Director	November 7, 2005
Horst H. Engel(1)(2)(4) Indio, California	Director	May 9, 2006
James T. Rundell Tees, Alberta	President	November 14, 2006
Richard D. Carmichael, C.A. Calgary, Alberta	Chief Financial Officer	January 2, 2007
Marcia L. Johnston, Q.C. Cochrane, Alberta	Vice-President Legal & Corporate Affairs and Corporate Secretary	May 28, 2007

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Notes:
(1)	Member of Audit Committee.
(2)	Member of Compensation Committee.
(3)	Member of Reserves Committee.
(4)	Member of Governance and Nominating Committee.

As at March 21 2008 the directors and executive officers of JED, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, 550,430 Common Shares, representing approximately 2.3% of the issued and outstanding Common Shares.

Profiles of JED’s directors and executive officers and the particulars of their respective principal occupations during the last five years are set forth below.

Thomas J. Jacobsen, Chief Executive Officer and Director

Mr. Jacobsen became our President, Chief Operating Officer and a director in September 2003 and currently continues to serve as Chief Executive Officer and a director. He is also serving as a director of JMG. Mr. Jacobsen became Enterra’s Chief Operating Officer in February 2002, after previously serving as a director, Executive Vice-President Operations and Vice-Chairman of predecessor Westlinks Resources Ltd., 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, 2996 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. All of the above companies were publicly traded in either the U.S., Canada, or both, during the periods indicated.

James T. Rundell, President

Mr. Rundell was appointed President of JED on November 14, 2007. Prior to that date he had been an independent consultant to the oil and gas industry through Rundell Consulting since 1990 and has over 30 years experience in many areas of oilfield operations world-wide. Through Rundell Consulting, Mr. Rundell served as JED’s drilling manager since our incorporation in September, 2003, before being named President.

Richard D. Carmichael, CA, Chief Financial Officer

Mr. Carmichael joined JED as Chief Financial Officer on January 2, 2007. Prior to joining JED, he was CFO at Geophysical Service Incorporated since late February, 2004; a financial consultant from 2001 through February, 2004 consulting to Patch Safety Services Ltd., Advanced NPD Inc. and Krang Energy Inc., and Controller and Financial Advisor to Maximum Energy Trust 1998 — 2001. Mr. Carmichael has a Bachelor of Commerce degree from the University of Calgary and received his Chartered Accountant designation with Ernst & Young LLP. Since leaving Ernst & Young in 1981 he has held financial positions in a number of companies in the oil and gas industry.

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Marcia L. Johnston, q.c., Vice-President Legal & Corporate Affairs and Corporate Secretary

Ms. Johnston was appointed Vice-President Legal & Corporate Affairs and Secretary of JED, as well as General Counsel, on May 28, 2007, after joining JED as General Counsel in November, 2004. From April, 2000 through November, 2004 she was a partner in the national law firm of Gowlings Lafleur Henderson llp, and from 1986 until joining Gowlings she was founder and Managing Partner of Johnston Robinson Clark Anderson and predecessor law firms. Marcia has acted as legal counsel to JED since its incorporation. She immigrated to Canada from the United States in 1981 and has over 25 years experience in acting on behalf of Canadian oil and gas companies in the areas of corporate, securities and oil & gas law, and as served as an officer as well as counsel for over 20 public companies. Ms. Johnston received a Bachelor of Arts degree in 1970 and Juris Doctor degree in 1973 from Washburn University, Topeka, Kansas; was admitted to the practice of law in the State of Kansas and U.S. Federal District Court in 1974; was admitted to the Law Society of Alberta in 1985, and was granted Letters Patent as Queen’s Counsel in January, 2006.

Ludwig (Louie) Gierstorfer, Director

Mr. Gierstorfer was appointed to our board of directors in September 2003. He retired in 2000 after serving 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, Director

Mr. Yorke, who was appointed as a director of JED in November 2006, 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, and a director of JMG. 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, Director

Mr. Engel was appointed to our board of directors in May 2007. He has spent over 40 years in the travel industry and has been the President of V.I.P. Travel since January 1, 1965. Mr. Engel has served as a director or officer of a number of companies and organizations, and has consulted to businesses in marketing and management areas. He holds a community college credential in business and industrial management. He is a certified Travel Counsellor, a life member of the Travel Institute and a life member of the Royal Geographical Society.

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Cease Trade Orders, Bankruptcies, Penalties or Sanctions

Except as set out below, no director or executive officer of JED is, as at the date hereof, or has been, within the 10 years prior to the date hereof, a director or executive officer of any company that, while that person was acting in that capacity:

(a)	was the subject of a cease trade or similar order or an order that denied such company access to any exemption under securities legislation for a period of more than 30 consecutive days,
(b)	was subject to an event that resulted, after the director or executive officer ceased to be a director or executive officer, in the company being the subject of a cease trade or similar order or an order that denied such company access to any exemption under securities legislation for a period of more than 30 consecutive days, or
(c)	within a year of such person ceasing to act in such capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.

Mr. Jacobsen served as a director of Caribou, 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.

Ms. Johnston served as the Corporate Secretary of Caribou, 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.

In addition, no director or executive officer of JED has, within the 10 years prior to the date hereof, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of such director or officer.

Conflicts of Interest

Circumstances may arise where members of the board of directors or officers of JED are directors or officers of corporations which are in competition to the interests of JED. No assurances can be given that opportunities identified by such board members or officers will be provided to JED. In accordance with Business Corporations Act (Alberta), a director or officer who is a party to a material contract or proposed material contract with JED or is a director or an officer of or has a material interest in any person who is a party to a material contract or proposed material contract with JED shall disclose to JED the nature and extent of the director’s or officer’s interest. In addition, a director shall not vote on any resolution to approve a contract of the nature described except in limited circumstances.

LEGAL PROCEEDINGS

There are no outstanding legal proceedings material to JED to which we are a party or in respect of which any of our properties are subject, nor are there any such proceedings known to be contemplated, except as follows:

The Company received notification in 2007 of a legal action against it by one of its note holders. In its complaint, the party has alleged a breach of a covenant of the convertible note and has claimed a right of redemption at 120% of the face value of the note plus interest. The claim totals $3,607,500

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plus interest which includes the original face value of the note and an additional $607,500 which has not been booked as management of the Company does not consider that the action has merit and is vigorously defending against it. Currently the status of the legal action is that discoveries are continuing and the Court is considering arguments on a motion by the plaintiff for the summary judgment.

At December 31, 2007 and 2006 the Company had no derivative financial or physical delivery contracts in place.

Various of the Company’s petroleum and natural gas properties have had liens registered against them by suppliers totaling approximately $2.4 million in the normal course of business. There exists a possibility of additional liabilities for creditors of Caribou that may be secured by security superior to that of the security acquired by JED.

DURING THE YEAR ENDED DECEMBER 31, 2007, THE COMPANY EXPERIENCED A WELL-SITE BLOW OUT. THE TOTAL POTENTIAL ENVIRONMENTAL CLEAN-UP COSTS CANNOT BE ESTIMATED AT THIS DATE BUT THE COMPANY EXPECTS ANY AMOUNTS PAID TO BE COVERED BY INSURANCE CLAIMS. The Company has received reimbursement from its main insurer, and has filed a legal action against its insurer and its former insurance agent with respect to subsurface environmental clean-up, and against the seller of the pipe with respect to any costs not covered by either of the insurance policies.\

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

None of JED’s directors or executive officers, nor any person who beneficially owns directly or indirectly or exercises control or direction over securities carrying more than 10% of the voting rights attaching to the Common Shares, nor any known associate or affiliate of these persons, had any material interest, direct or indirect in any transaction since the commencement of JED’s last completed financial year which has materially affected JED.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for our Common Shares is Olympia Trust Company in Calgary, Alberta.

MATERIAL CONTRACTS

Note Purchase Agreement dated May 31, 2007. See “MARKET FOR SECURITIES” — “Prior Sales”.

Securities Purchase Agreement dated June 9, 2007. See “MARKET FOR SECURITIES” — “Prior Sales”.

INTERESTS OF EXPERTS

Reserve estimates contained herein are derived from reserve reports prepared by CGE. As of the date hereof, CGE, as a group, does not beneficially own, directly or indirectly, any Common Shares.

ADDITIONAL INFORMATION

SEDAR

Additional information in respect of JED may be found on SEDAR at www.sedar.com.

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Management Information Circular

Additional information, including information related to the remuneration and indebtedness of the directors and officers of JED; the principal holders of Common Shares; and Common Shares authorized for issuance under equity compensation plans, is contained in the management information circular in respect of JED’s last annual general meeting.

Financial Statements and MD&A

Additional financial information is provided in the audited financial statements and MD&A of JED for the year ended December 31, 2007.

AUDIT COMMITTEE

General

JED has established an Audit Committee (the “Audit Committee”) comprised of three members: Justin W. Yorke, Chairman, Ludwig Gierstorfer and Horst H. Engel, each of whom is considered “independent”, and is considered “financially literate”, within the meaning of Multilateral Instrument 52-110 — Audit Committees.

Mandate of the Audit Committee

The mandate of the Audit Committee is to assist the JED Board in its oversight of the integrity of the financial and related information of JED and its subsidiaries and related entities, including the financial statements, internal controls and procedures for financial reporting and the processes for monitoring compliance with legal and regulatory requirements. In doing so, the Audit Committee oversees the audit efforts of our external auditors and, in that regard, is empowered to take such actions as it may deem necessary to satisfy itself that our external auditors are independent of us. It is the objective of the Audit Committee to have direct, open and frank communications throughout the year with management, other Committee chairmen, the external auditors, and other key committee advisors or JED staff members as applicable.

The Audit Committee’s function is oversight. Management of JED is responsible for the preparation, presentation and integrity of the financial statements of JED. Management is responsible for maintaining appropriate accounting and financial reporting principles and policy and internal controls and procedures that provide for compliance with accounting standards and applicable laws and regulations.

While the Audit Committee has the responsibilities and powers set forth above, it is not the duty of the Audit Committee to plan or conduct audits or to determine whether the financial statements of JED are complete and accurate and are in accordance with generally accepted accounting principles. This is the responsibility of management and the external auditors, on whom the members of the Committee are entitled to rely upon in good faith.

The Charter of the Audit Committee is attached hereto as Appendix “A”.

Relevant Education and Experience of Audit Committee Members

The following is a brief summary of the education or experience of each member of the Audit Committee that is relevant to the performance of his responsibilities as a member of the Audit Committee, including any education or experience that has provided the member with an understanding of the accounting principles used by us to prepare our annual and interim financial statements.

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Name of Audit
Committee Member	Relevant Education and Experience
Justin W. Yorke	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. He is familiar with financial information as presented in audited financial statements and annual and interim reports that present a breadth and level of complexity of accounting issues comparable to those issues that can reasonably be expected to be raised in JED’s financial statements.
Ludwig Gierstorfer	Mr. Gierstorfer is the former founder, CEO and director of a privately held drilling company. He is familiar with financial information as presented in audited financial statements and annual and interim reports that present a breadth and level of complexity of accounting issues comparable to those issues that can reasonably be expected to be raised in JED’s financial statements.
Horst H. Engel	Mr. Engel is the former co-owner and President of a privately held executive travel agency and has held positions as directors and officers in a number of companies and organizations. He is familiar with financial information as presented in audited financial statements and annual and interim reports that present a breadth and level of complexity of accounting issues comparable to those issues that can reasonably be expected to be raised in JED’s financial statements.

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External Auditor Services Fees

For the year ended December 31, 2007, Meyers Norris Penny and its affiliates were paid approximately C$206,850 as detailed below:

	Year Ended
	December 31, 2007
	C$
Myers Norris Penny LLP
Audit Fees	$	190,250
Audit Related Fees	$	16,600
Tax Fees	$	0
All Other Fees	$	0
TOTAL	$	206,850

Note:

The Audit Committee has the authority to pre-approve non-audit services which may be required from time to time.

Audit Committee Oversight

At no time since the commencement of our most recently completed financial year, has a recommendation of the Audit Committee to nominate or compensate an external auditor not been adopted by the board of directors of JED.

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APPENDIX “A”
AUDIT COMMITTEE CHARTER

Organization

This charter governs the operations of the Audit Committee of JED Oil Inc. The Board of Directors shall appoint an Audit Committee (the “Committee”) of at least three members, consisting entirely of independent directors of the Board, and shall designate one member as chairperson or delegate the authority to designate a chairperson to the Committee. For purposes hereof, members shall be considered independent as long as they satisfy all of the independence requirements for Board Members as set forth in the applicable stock exchange listing standards and Rule 10A-3 of the Exchange Act.

Each member of the Committee shall be financially literate, or become financially literate within a reasonable period of time, and at least one member shall be an “audit committee financial expert,” as defined by SEC rules.

Members shall not serve on more than three public company audit committees simultaneously.

The Committee shall meet in person, or telephonically, at least quarterly. The Committee shall meet separately and periodically with management, the personnel responsible for the internal audit (or equivalent) function, and the independent auditor. The Committee shall report regularly to the Board of Directors with respect to its activities.

Purpose

The purpose of the Committee shall be to:

• Provide assistance to the Board of Directors in fulfilling their oversight responsibility to the shareholders, potential shareholders, the investment community, and others relating to: (i) the integrity of the Company’s financial statements; (ii) the Company’s compliance with legal and regulatory requirements; (iii) the independent auditor’s qualifications and independence; (iv) and the performance of the Company’s internal audit (or equivalent) function and independent auditors;

• Prepare the Audit Committee report that SEC proxy rules require to be included in the Company’s annual proxy statement.

The Committee shall retain and compensate such outside legal, accounting, or other advisors, as it considers necessary in discharging its oversight role.

In fulfilling its purpose, it is the responsibility of the Committee to maintain free and open communication between the Committee, independent auditors, the internal auditors (or equivalent function), and management of the Company, and to determine that all parties are aware of their responsibilities.

Duties and Responsibilities

The Committee has the responsibilities and powers set forth in this Charter. Management is responsible for the preparation, presentation, and integrity of the Company’s financial statements, for the appropriateness of the accounting principles and reporting policies that are used by the Company and for implementing and maintaining internal control over financial reporting. The independent auditors are responsible for auditing the Company’s financial statements and for reviewing the Company’s unaudited interim financial statements.

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The Committee, in carrying out its responsibilities, believes its policies and procedures should remain flexible, in order to best react to changing conditions and circumstances. The Committee will take appropriate actions to set the overall corporate “tone” for quality financial reporting, sound business risk practices, and ethical behaviour.

The following shall be the principal duties and responsibilities of the Committee. These are set forth as a guide with the understanding that the Committee may supplement them as appropriate.

• The Committee shall be directly responsible for the appointment, compensation, retention, and oversight of the work of the independent auditors (including resolution of disagreements between management and the auditor regarding financial reporting) for the purpose of preparing or issuing an audit report or performing other audit, review, or attest services for the listed issuer, and the independent auditors must report directly to the Committee.

• At least annually, the Committee shall obtain and review a report by the independent auditors describing: (i) the firm’s internal quality control procedure; (ii) any material issues raised by the most recent internal quality control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm, and any steps taken to deal with any such issues; and (iii) all relationships between the independent auditors and the Company (to assess the auditors’ independence).

• After reviewing the foregoing report and the independent auditors’ work throughout the year, the Committee shall evaluate the auditors’ qualifications, performance and independence. Such evaluation should include the review and evaluation of the lead partner of the independent auditors and take into account the opinions of management and the Company’s personnel responsible for the internal audit function.

• The Committee shall determine that the independent audit firm has a process in place to address the rotation of the lead audit partner and other audit partners serving the account as required under the SEC independence rules.

• The Committee shall pre-approve all audit and non-audit services provided by the independent auditors and shall not engage the independent auditors to perform non-audit services proscribed by law or regulation. The Committee may delegate pre-approval authority to a member of the Audit Committee. The decisions of any Committee member to whom pre-approval authority is delegated must be presented to the full Committee at its next scheduled meeting.

• The Committee shall discuss with the internal auditors (or equivalent function) and the independent auditors the overall scope and plans for their respective audits, including the adequacy of staffing and budget or compensation.

• The Committee shall regularly review with the independent auditors any audit problems or difficulties encountered during the course of the audit work, including any restrictions on the scope of the independent auditors’ activities or access to requested information, and management’s response. The Committee should review any accounting adjustments that were noted or proposed by the auditors but were “passed” (as immaterial or otherwise); any communications between the audit team and the audit firm’s national office respecting auditing or accounting issues presented by the engagement; and any “management” or “internal control” letter issued, or proposed to be issued, by the audit firm to the Company.

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• The Committee shall review and discuss the quarterly financial statements, including Management’s Discussion and Analysis of Financial Condition and Results of Operations, with management and the independent auditors prior to the filing of the Company’s Quarterly Report on Form 10-Q, or other SEC filings as required. Also, the Committee shall discuss the results of the quarterly review and any other matters required to be communicated to the Committee by the independent auditors under generally accepted auditing standards.

• The Committee shall review and discuss the annual audited financial statements, including Management’s Discussion and Analysis of Financial Condition and Results of Operations, with management and the independent auditors prior to the filing of the Company’s Annual Report on Form 10-K (or the annual report to shareholders if distributed prior to the filing of Form 10-K or other SEC forms as required). The Committee’s review of the financial statements shall include: (i) major issues regarding accounting principles and financial statement presentations, including any significant changes in the company’s selection or application of accounting principles, and major issues as to the adequacy of the company’s internal controls and any specific remedial actions adopted in light of material control deficiencies; (ii) discussions with management and the independent auditors regarding significant financial reporting issues and judgments made in connection with the preparation of the financial statements and the reasonableness of those judgments; (iii) consideration of the effect of regulatory accounting initiatives, as well as off-balance sheet structures on the financial statements; (iv) consideration of the judgment of both management and the independent auditors about the quality, not just the acceptability of accounting principles; and (v) the clarity of the disclosures in the financial statements. Also, the Committee shall discuss the results of the annual audit and any other matters required to be communicated to the Committee by the independent auditors under professional standards.

• The Committee shall receive and review a report from the independent auditors, prior to the filing of the Company’s Annual Report on Form 10-K (or the annual report to shareholders if distributed prior to the filing of Form 10-K or other SEC forms as required), on all critical accounting policies and practices of the Company; all material alternative treatments of financial information within generally accepted accounting principles that have been discussed with management, including the ramifications of the use of such alternative treatments and disclosures and the treatment preferred by the independent auditor; and other material written communications between the independent auditors and management.

• The Committee shall review and approve all related party transactions.

• The Committee shall review and discuss earnings press releases, as well as financial information and earnings guidance provided to analysts and rating agencies.

• The Committee shall review management’s assessment of the effectiveness of internal control over financial reporting as of the end of the most recent fiscal year and the independent auditors’ report on management’s assessment.

• The Committee shall discuss with management, the internal auditors (or equivalent function), and the independent auditors the adequacy and effectiveness of internal control over financial reporting, including any significant deficiencies or material weaknesses identified by management of the Company in connection with its required quarterly certifications under Section 302 of the Sarbanes-Oxley Act. In addition, the Committee shall discuss with management, the internal auditors (or equivalent function), and the

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	independent auditors any significant changes in internal control over financial reporting that are disclosed, or considered for disclosures, in the Company’s periodic filings with the SEC.
•	The Committee shall review the Company’s compliance systems with respect to legal and regulatory requirements and review the Company’s code of conduct and programs to monitor compliance with such programs. The Committee shall receive corporate attorneys’ reports of evidence of a material violation of securities laws or breaches of fiduciary duty.
•	The Committee shall discuss the Company’s policies with respect to risk assessment and risk management, including the risk of fraud. The Committee also shall discuss the Company’s major financial risk exposures and the steps management has taken to monitor and control such exposures.
•	The Committee shall establish procedures for the receipt, retention, and treatment of complaints received by the Company regarding accounting, internal accounting controls, or auditing matters, and the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters.
•	The Committee shall set clear hiring policies for employees or former employees of the independent auditors that meet the SEC regulations and stock exchange listing standards.
•	The Committee shall determine the appropriate funding needed by the Committee for payment of: compensation to the independent audit firm engaged for the purpose of preparing or issuing an audit report or performing other audit, review, or attest services for the Company; compensation to any advisers employed by the Committee; and (3) ordinary administrative expenses of the Committee that are necessary or appropriate in carrying out its duties.
•	The Committee shall perform an evaluation of its performance at least annually to determine whether it is functioning effectively.
•	The Committee shall review and reassess the charter at least annually and obtain the approval of the board of directors.

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APPENDIX “B”
REPORT ON RESERVES DATA BY INDEPENDENT
QUALIFIED RESERVES EVALUATOR OR AUDITOR

March 31, 2008

JED Oil Inc.
1601 — 15^th Avenue
Didsbury, AB T0M 0W0

Attention: The Board of Directors of JED Oil Inc.

Re:	Form 51-101F2
	Report on Reserves Data by an Independent Qualified Reserves Evaluator of JED Oil Inc. (the “Company”)

To the Board of Directors of JED Oil Inc. (the “Company”):

1. We have evaluated the Company’s reserves data as at December 31, 2007. The reserves data consists of the following:

(a)	proved and proved plus probable oil and gas reserves estimated as at December 31, 2007 using forecast prices and costs and the related estimated future net revenue; and
(b)	proved and proved plus probable oil and gas reserves estimated as at December 31, 2007 using constant prices and costs and the related estimated future net revenue.

2.	The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
	We carried out our evaluated in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).
3.	Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions in the COGE Handbook.
4.	The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated by us for the year ended December 31, 2007, and identifies the respective portion thereof that we have evaluated, audited and reviewed and reported on to the Corporation’s management.

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	Location of	Net Present Value of Future Net Revenue
	Reserves	(before income taxes 10% discount rate - $M)
Preparation Date of	(Country or Foreign
Evaluation Report	Geographic Area)	Audited		Evaluated	Reviewed		Total
February 5, 2008	Canada and United States		—	116,888.7		—		116,888.7

5.	In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook.
6.	We have no responsibility to update this evaluation for events and circumstances occurring after their respective preparation date.
7.	Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

Executed as to our report referred to above:

CG ENGINEERING LTD.

/s/ Greg Neufeld

                                        
Greg Neufeld, P. Eng.
President

Calgary, Alberta

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APPENDIX “C”
REPORT ON RESERVES DATA BY MANAGEMENT AND DIRECTORS

Terms to which a meaning is ascribed in National Instrument 51-101 have the same meaning herein.

Management of JED Oil Inc. (the “Corporation”) are responsible for the preparation and disclosure, or arranging for the preparation and disclosure of information with respect to the Corporation’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:

(i)	proved and proved plus probable oil and gas reserves estimated as at December 31, 2007 using forecast prices and costs; and
(ii)	the related estimated future net revenue; and
(iii)	proved oil and gas reserves estimated as at December 31, 2007 using constant prices and costs; and
(iv)	the related estimated future net revenue.

An independent qualified reserves evaluator has evaluated the Corporation’s reserves data. The report of the independent qualified reserves evaluator will be filed with the securities regulatory authorities concurrently with this report.

The Reserves Committee of the Board of Directors of the Corporation has:

• reviewed the Corporation’s procedures for providing information to the independent qualified reserves evaluator;

• met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation, to inquire whether there had been disputes between the previous independent qualified reserves evaluator and management;

• reviewed the reserves data with management and the independent qualified reserves evaluator.

The Reserves Committee of the Board of Directors has reviewed the Corporation’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with Management. The Board of Directors has, on the recommendation of the Reserves Committee approved:

(a)	the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;
(b)	the filing of the report of the independent qualified reserves evaluator; and
(c)	the content and filing of this report.

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Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

(signed)

Justin W. Yorke
Chairman and Director

(signed)

Thomas J. Jacobsen
CEO and Director

(signed)

Ludwig Gierstorfer
Director

(signed)

Horst H. Engel
Director

March 31, 2008