ENTERRA

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.

GLOSSARY OF TERMS

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

"Amended and Restated Agreement of Business Principles" means the Amended and Restated Agreement of Business Principles among the Trust, JED and JMG, dated effective September 1, 2003 as between the Trust and JED and August 1, 2005 as among the Trust, JED and JMG;

"board of directors" means the board of directors of JED;

"common shares" means the common shares in the capital stock of JED;

"Enterra" means Enterra Energy Corp., a corporation incorporated under the laws of Alberta and a wholly-owned subsidiary of JED;

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

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

"McDaniel" means McDaniel & Associates Ltd., independent petroleum engineering consultants of Calgary, Alberta;

"McDaniel Report" means the independent engineering evaluation of certain oil, NGL and natural gas interests of JED prepared by McDaniel dated February 14, 2006 and effective December 31, 2005;

"Non-Resident" means (a) a Person who is not a resident of Canada for the purposes of the Tax Act; or (b) a partnership that is not a Canadian partnership for the purposes of the Tax Act;

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

"Tax Act" means the Income Tax Act (Canada), R.S.C. 1985, c. 1. (5th Supp), as amended, including the regulations promulgated thereunder;

"Technical Services Agreements" means the two Technical Services Agreements each dated effective January 1, 2005, between JED and JED, and JED and JMG.

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

"1933 Act" means the United States Securities Act of 1933, as amended;

"1934 Act" means the United States Securities Exchange Act of 1934, as amended.

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

CURRENCY OF INFORMATION

The information set out in this annual information form is stated as at December 31, 2005 unless otherwise indicated. Capitalized terms used but not defined in the text are defined in the Glossary.

ORGANIZATIONAL STRUCTURE

JED Oil Inc.

JED Oil Inc. (“JED”) was incorporated under the Business Corporations Act (Alberta) on September 3, 2003.

The Company’s principal business address is Suite 2200, 500 4th Avenue S.W., Calgary, Alberta T2P 2V6. The Company’s registered office is 2200, 500 4th Avenue S.W., Calgary, Alberta, T2P 2V6.

JED Oil (USA) Inc.

JED Oil (USA) Inc. is JED’s only subsidiary and is wholly owned by JED. It is incorporated under the laws of Wyoming.

GENERAL DEVELOPMENT OF THE BUSINESS OF JED

History

The concept for the organization of JED was created by the management of Enterra Energy Trust (the “Trust”), an oil and gas income trust, and its administrator, Enterra Energy Corp. (“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.

In 2004, it was decided to incorporate another company to be an exploration company, and JMG Exploration, Inc. (“JMG”) was incorporated under the laws of Nevada. In February 2004, JED, the Trust and JMG formalized their verbal agreements for their synergistic relationships to each other and their joint business plans, by executing the Amended and Restated Agreement of Business Principles, dated effective September 1, 2003 as between JED and the Trust, and August 1, 2005 as among JED, Enterra and JMG. The principle concepts of the agreement are that:

JED will be the operator or contract operator of Enterra’s assets with production, and JMG will be the operator and contract operator of Enterra’s assets without productions.

Enterra will farm-out its development assets to JED for development drilling. JED will pay 100% of the costs to earn 70% of Enterra’s interests.

When JMG has done sufficient exploratory drilling in an area to prove the commercial viability of the production, Enterra has the right to purchase 80% of JMG’s interest at a value determined by an independent engineering report. Both Enterra and JMG will farm-out the development drilling to JED.

Enterra has a first right of refusal to purchase JED’s assets by meeting a bona fide third party offer or otherwise at a value determined by our independent engineering report.

JED will enter into agreements to provide administrative services and personnel to Enterra and JMG. Accordingly JED, Enterra and JMG entered into a Technical Services Agreement (the “Technical Services Agreement”) effective January 1, 2005 to provide these services.

In specific cases the terms can be revised by mutual agreement of the affected parties.

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. A number of JED’s employees that worked primarily with the production from existing wells became employees of Enterra. In addition JED and Enterra no longer share office space and are in the process of separating all remaining shared software systems and other resources. The 2nd Amended and Restated Agreement of Business Principles remains in effect to govern the farmouts between JED and Enterra, but the Technical Services Agreement was terminated effective January 1, 2006. It was replaced with a Joint Services Agreement between JED and Enterra to cover the few remaining transitional issues in the separation evolution.

JED continues to supply staff, other than the CEO and CFO, and administrative services to JMG. As discussed above the Technical Services Agreement among JED, Enterra and JMG was terminated January 1, 2006, but has been replaced with a Joint Services Agreement dated January 1, 2006 between JED and JMG. The growth and evolution of the business in 2005 also led to a conclusion that both companies would be strengthened by becoming one company, and JED and JMG have announced that they are pursuing a merger during 2006.

JED’s Common Shares were listed for trading on the American Stock Exchange on April 6, 2004 under the symbol “JDO”.

DESCRIPTION OF THE BUSINESS

Strategy

JED is engaged in the development and operation of crude oil and natural gas in Western Canada and under its wholly-owned subsidiary JED Oil (USA) Inc. in the rocky mountain states of the United States. It is anticipated that the majority of drilling opportunities will be the farm-outs from the Trust and its operating subsidiaries. Occasionally JED may purchase specific properties in the drilling upside. Our drilling programs will be financed primarily with existing cash flow and bank debt.

Revenue Sources

For the year ended December 31, 2005, approximately 30% of the revenue from our properties was derived from natural gas and approximately 70% was derived from crude oil and natural gas liquids.

Employees

At December 31, 2005, we had approximately 30 employees and consultants working both in the Calgary head office and in field operations.

OPERATIONS REVIEW

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

Desan

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

JED has obtained a farm-in on 43,320 acres of land in this area whereby we will be paying 100% to earn a 70% working interest in each spacing unit drilled. In Q4, 2005 and Q1, 2006 JED drilled 6 wells with a success rate of 83%, these wells will be tied-in and on production by the end of March, 2006. Expected initial production rates from these wells should be between 500 mcf/d and 2 mmcf/d.

Peggo

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

Ferrier

The Ferrier property is located 85 miles southwest of the City of Edmonton, Alberta. On this property JED has the option to earn a 70% working interest per spacing unit by paying 100% of the drilling costs. 35,877 acres of land are available for farm-in in this area. In Q4, 2005 JED drilled 9 wells (6.3 net) with 100% success encountering gas in the liquids rich Ellerslie and Rock Creek Formations. In Q1, 2006 JED drilled an additional 6 wells (3.8 net), again with 100% success for a total of 15 (10.1 net). A 10 mmcf/d compression facility is being constructed, all of which should be on production by the end of March, 2006. JED has the potential to drill 5 additional wells on this acreage without further downspacing and another 22 wells with further downspacing. Four sections of land were purchased at a recent Alberta Crown land sale with up to 12 additional wells that can be drilled on these lands. Expected initial production rates from these wells should be between 500 mcf/d and 4 mmcf/d.

Ricinus

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

Cummings “Y” Unit

The Cummings “Y” Unit is located within the area known as Provost, Alberta, southwest of the town of Provost. The target is the Cummings Formation. JED has an average working interest of 32.7% over 340 gross acres (111.2 net acres) of land. JED drilled and completed 15 wells in the Cummings “Y” Unit over the past year. In order to optimize oil recovery 2 water injector wells were drilled and 1 older oil well was converted into a water injector to restore pressure to the field. This increased production from 90 BOE/d to 140 BOE/d net to JED. Total proved and probable preliminary reserves assigned are 305.9 mbbl of oil. Currently there are no further development plans.

North Dakota, USA

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

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

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

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

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The effective date of the Statement is December 31, 2005 and the preparation date of the Statement is February 14, 2006.

Disclosure of Reserves Data

The reserves data set forth below (the “Reserves Data”) is based upon an evaluation by McDaniel with an effective date of December 31, 2005 contained in the McDaniel 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 McDaniel Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in 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 McDaniel to provide an evaluation of proved and proved plus probable reserves.

All of JED’s assigned reserves are in Canada and, specifically, in the province of Alberta.

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

All evaluations and reviews of future net cash flow are stated prior to any provision for interest costs or general and administrative costs and after the deduction of estimate future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimated future net cash flow shown below is representative of the fair market value of the Company’s properties. There is no assurance that such price and cost assumptions

will be attained and variances could be material. The recovery and reserve estimates of crude oil, NGLs and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will

be recovered. Actual crude oil, NGLs and natural gas reserves may be greater than or less than the estimates provided herein.

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

In accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities, McDaniel prepared the McDaniel Report dated February 14, 2006. The McDaniel Report evaluated, as at December 31, 2005, JED's oil, 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 McDaniel Report based on constant and forecast price and cost assumptions. The tables summarize the data contained in the McDaniel Report and as a result may contain slightly different numbers than such report 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 McDaniel. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to JED's reserves estimated by McDaniel represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of JED's oil, NGL and natural gas reserves provided herein 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 McDaniel Report is based on certain factual data supplied by JED and McDaniel’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 McDaniel and accepted without any further investigation. McDaniel 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, 2005
Constant Prices and Costs

	Light and		Heavy		Natural Gas
	Medium Oil		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	427.6	368.8	129.3	120.9	127.9	90.8	3,151	2,514
Developed Non-Producing	8.5	8.4	Nil	Nil	243.6	178.9	4,408	3,596
Producing
Undeveloped	47.3	41.5	Nil	Nil	331.0	231.2	10,813	7,988
TOTAL PROVED	483.4	418.6	129.3	120.9	702.4	501.0	18,372	14,098

PROBABLE	167.6	153.2	35.0	32.7	446.2	317.2	10,591	8,166

TOTAL PROVED PLUS PROBABLE	651.0	571.8	164.3	153.7	1148.6	818.2	28,963	22,264


Net Present Values of Future Net Revenue
as at December 31, 2005
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	42.8	37.9	34.2	31.3	28.9	42.8	37.8	34.2	31.3	28.9
Developed Non-Producing	43.0	36.8	32.3	28.9	26.2	31.9	27.4	24.1	21.6	19.6
Undeveloped	41.9	28.0	18.6	11.9	7.1	27.3	16.5	9.2	4.0	0.2
TOTAL PROVED	127.7	102.7	85.1	72.1	62.2	102.0	81.7	67.5	56.9	48.7

PROBABLE	91.7	63.6	47.4	37.2	30.3	60.9	41.9	30.8	23.8	19.1

TOTAL PROVED PLUS PROBABLE	219.4	166.3	132.5	109.3	92.5	162.9	123.6	98.3	80.7	67.8


Total Future Net Revenue
(Undiscounted)
as at December 31, 2005
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	259,927	51,168	25,941	53,062	2,173	127,583	25,661	101,922
Proved Plus Probable Reserves	406,305	80,114	38,557	66,089	2,300	219,245	56,422	162,824


Future Net Revenue by Production Group
as at December 31, 2005
Constant Prices and Costs

	Future Net Revenue Before
	Income Taxes and
	discounted at 10%/year
Reserves Category	[$m]

Proved
Light and Medium Crude Oil ⁽¹⁾		9,890
Heavy Oil		2,924
Natural Gas ⁽²⁾		69,537

Proved Plus Probable
Light and Medium Crude Oil ⁽¹⁾		12,665
Heavy Oil		3,491
Natural Gas ⁽²⁾		112,857


Notes:	(1) Including by-products, but excluding solution gas from oil wells
	(2) Including solution gas and other by-products

Reserves Data – Forecast Prices and Costs


Summary of Oil and Gas Reserves
as at December 31, 2005
Forecast Prices and Costs

	Light and
	Medium		Heavy		Natural Gas
	Oil		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	427.9	369.0	129.3	120.3	128.5	91.3	3,163	2,524
Developed Non-Producing	8.5	8.4	Nil	Nil	243.6	178.9	4,408	3,596
Producing
Undeveloped	47.3	41.6	Nil	Nil	331.0	231.2	10,813	7,988
TOTAL PROVED	483.7	419.0	129.3	120.3	703.1	501.4	18,384	14,108

PROBABLE	169.4	146.1	35.0	32.7	446.6	316.5	10,596	8,149

TOTAL PROVED PLUS PROBABLE	653.1	565.0	164.3	153.0	1,149.7	817.9	28,980	22,257


Net Present Values of Future Net Revenue
as at December 31, 2005
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	39.2	35.6	32.7	30.3	28.3	39.2	35.6	32.7	30.3	28.3
Developed Non-Producing	35.3	31.0	27.7	25.1	23.1	27.8	24.2	21.5	19.4	17.7
Undeveloped	24.2	14.5	8.0	3.3	(0.1)	15.6	7.6	2.1	(1.8)	(4.7)
Total Proved	98.7	81.1	68.4	58.7	51.3	82.6	67.4	56.3	47.9	41.3

Probable	70.7	49.1	36.6	28.8	23.5	47.0	32.2	23.5	18.1	14.5

Total Proved Plus Probable	169.4	130.2	105.0	87.5	74.8	129.6	99.6	79.8	66.0	55.8


Total Future Net Revenue
(Undiscounted)
as at December 31, 2005
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	230,802	44,848	29,704	54,614	2,946	98,690	16,003	82,687
Total Proved Plus Probable	356,281	69,160	46,300	68,070	3,351	169,401	39,769	129,633

Future Net Revenue by Production Group

Future Net Revenue Before Income Taxes

(Discounted at 10%/year)


Reserves Category	Production Group	Forecast Prices and Costs $M

Proved	Light and Medium Oil ⁽¹⁾	10,525
	Heavy Oil ⁽¹⁾	3,059
	Natural Gas⁽²⁾	52,276

Proved Plus Probable	Light and Medium Oil⁽¹⁾	13,274
	Heavy Oil	3,602
	Natural Gas⁽²⁾	84,864
Notes:
(1) Including by-products, but excluding solution gas from oil wells
(2) Including solution gas and other by-products

Pricing Assumptions – Constant Prices and Costs

McDaniel and Associates employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2005 in estimating JED's reserves data using constant prices and costs.


Pricing Assumptions
Constant Prices and Costs

		Edmonton	Cromer	Hardisty	Alberta	Natural Gas	US/CAN
	WTI at	Par Price	Medium	Heavy	Average	Liquids FOB	Exchange
Year	Cushing	40 API	25 API	29.3 API	Plantgate Price	Field Gate	Rate
	[$US/bbl]	[$Cdn/bbl]	[$Cdn/bbl]	[$Cdn/bbl]	[$Cdn/Mmbtu]	[$Cdn/bbl]	$US/$Cdn
2005 (Year end)	61.04	68.46	51.65	30.86	9.80	56.3	0.85

Pricing Assumptions – Forecast Prices and Costs


		Edmonton	Cromer	Hardisty	Alberta	Natural Gas		US/CAN
	WTI at	Par Price	Medium	Heavy	Average	Liquids FOB		Exchange
Year	Cushing	40 API	29.3 API	12 API	Plantgate Price	Field Gate	Inflation	Rate
	[$US/bbl]	[$Cdn/bbl]	[$Cdn/bbl]	[$Cdn/bbl]	[$Cdn/Mmbtu]	[$Cdn/bbl]	%	$US/$Cdn
Forecast
2006	57.50	66.60	58.50	35.50	10.40	51.40	2.5	0.85
2007	55.40	64.20	56.30	36.10	9.35	48.90	2.5	0.85
2008	52.50	60.70	53.30	36.00	8.30	45.80	2.5	0.85
2009	49.50	57.20	50.20	35.30	7.20	42.60	2.5	0.85
Thereafter

The weighted average realized sales prices for JED for the year ended December 31, 2005 were $9.33/Mcf for natural gas, $48.50/Bbl for crude oil and $52.10/Bbl for NGL's.

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, 2005 based on forecast price and cost assumptions, and then based on constant prices and costs.


Reconciliation of Company Net Reserves by Product Type
as at December 31, 2005
Forecast Prices and Costs


	Light and Medium Oil			Natural Gas Liquids
	Total Proved	Probable	Total Proved	Total Proved	Probable	Total Proved
	Reserves	Reserves	Plus Probable	Reserves	Reserves	Plus Probable
	[mbbl]	[mbbl]	[mbbl]	[mbbl]	[mbbl]	[mbbl]

December 31, 2004	278.5	84.9	363.4	10.8	3.7	14.5
Extensions	43.5	29.0	72.5
Technical Revision Negative	(64.2)	(21.4)	(85.6)	(2.9)	(1.3)	(4.2)
Technical Revision Positive	42.1	2.4	44.5	7.9	0.6	8.5
Discoveries	212.0	51.2	263.2	489.3	313.5	801.8
Production	(92.9)		(92.9)	(2.7)	-	(2.7)
December 31, 2005	419.0	146.1	565.1	501.4	316.5	817.9

	Associated and Non-Associated Gas			Heavy Oil
	Total Proved	Probable	Total Proved	Total Proved	Probable	Total Proved
	Reserves	Reserves	Plus Probable	Reserves	Reserves	Plus Probable
	[mmcf]	[mmcf]	[mmcf]	[mbbl]	[mbbl]	[mbbl]

December 31, 2004	335	114	449	159.6	53.0	212.6
Extensions	--	-	-	-	-	-
Technical Revision Negative	(85)	(15)	(100)	(9.2)	(20.3)	(29.5)
Technical Revision Positive	209	20	229	-	-	-
Discoveries	13918	8030	21948	-	-	-
Production	(269)		(269)	(30.1)		(30.1)
December 31, 2005	14108	8149	22257	120.3	32.7	153.0


Reconciliation of Company Net Reserves by Product Type
as at December 31, 2005
Constant Prices and Costs


	Light and Medium Oil			Natural Gas Liquids
	Total Proved	Probable	Total Proved	Total Proved	Probable	Total Proved
	Reserves	Reserves	Plus Probable	Reserves	Reserves	Plus Probable
	[mbbl]	[mbbl]	[mbbl]	[mbbl]	[mbbl]	[mbbl]

December 31, 2004	276.9	84.2	361.1	10.6	3.7	14.3
Extensions	44.1	28.5	72.6
Technical Revision Negative	(62.1)	(12.9)	(75.0)		(1.3)	(1.3)
Technical Revision Positive	44.5	2.4	46.9	3.6	0.6	4.2
Discoveries	208.2	51.0	259.2	489.3	314.2	803.5
Production	(92.9)		(92.9)	(2.6)	-	(2.6)
December 31, 2005	418.7	153.2	571.9	500.9	317.2	818.1

	Associated and Non-Associated Gas			Heavy Oil
	Total Proved	Probable	Total Proved	Total Proved	Probable	Total Proved
	Reserves	Reserves	Plus Probable	Reserves	Reserves	Plus Probable
	[mmcf]	[mmcf]	[mmcf]	[mbbl]	[mbbl]	[mbbl]

December 31, 2004	331	113	444	159.0	53.2	212.2
Extensions	Nil	Nil	Nil	Nil	Nil	Nil
Technical Revision Negative	(81)	(15)	(96)	(8.0)	(20.5)	(28.5)
Technical Revision Positive	119	19	218	Nil	Nil	Nil
Discoveries	13918	8049	21967	Nil	Nil	Nil
Production	(269)		(269)	(30.1)		(30.1)
December 31, 2005	14098	8166	22264	120.9	32.7	153.6

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 in the McDaniel Report as at December, 31, 2004 against the estimate of such amount as at December, 31, 2005, calculated after tax using a discount rate of 10% and constant price and cost assumptions.


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

	After Tax 2005 ($M)	Before Tax 2005 ($M)

Estimated Net Present Value at December 31, 2004	6,112.6	6,112.6

Oil and Gas Sales During the Period Net of Production Costs and Royalties (1)	(7,971.8)	(7,971.8)
Changes due to Prices Production Costs and Royalties Related to Future Production (2)	5,533.0	5,533.0
Changes in Development Costs During the Period (3)	53,927.0	53,927.0
Changes in Forecast Development Costs (4)	(52,815.5)	(52,815.5)
Changes resulting from Extensions and Improved Recovery (5)	1,163.0	1,163.0
Changes Resulting from Discoveries (5)	76,465.0	76,465.0
Changes Resulting from Acquisitions of Reserves (5)	-	-
Changes Resulting from Dispositions of Reserves (5)	-	-
Accretion of Discount (6)	611.3	611.3
Net Change in Income Tax (7)	(17,587.3)
Changes Resulting from Technical Reserves Revisions	294.0	294.0
All Other Changes	1,769.4	1,769.4

Estimated Net Present Value at December 31, 2005	67,500.7	85,088.0

Notes:
(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 different 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, 2005.

Light/Medium Oil

47.3 mbbl

Natural Gas

10,813.4 mccf

Natural Gas Liquids

331 mbbl

A significant portion of the undeveloped reserves is scheduled to be developed in the 2006 calendar year subject to available capital.

Properties with no attributed reserves

At December 31, 2005 $1.8 million had been spent on one property in development in the United States. No reserves were attributed to the property at December 31, 2005. The well came on production in January 2006 and reserves will be assigned in the 2006 year.

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 reserve estimates contained herein are based on current production forecasts, prices and economic conditions. JED's reserves are evaluated by McDaniel, an independent engineering firm.

As circumstances change and additional data become available, reserve 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 reserve 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 reserve 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
Year	Proven Reserves		Proved Plus Probable Reserves		Proved Reserves
	0%	10%	0%	10%	0%	10%
2006	45,374	43,263	54,621	52,079	44,268	42,207
2007	9,240	8,009	13,448	11,657	8,795	7,623
2008
2009
2010
Thereafter
Total	54,614	51,272	68,070	63,736	53,062	49,831

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 2006, JED negotiated a Revolving Demand Credit Facility with a Canadian bank.

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
Year	Proven Reserves		Proved Plus Probable Reserves		Proved Reserves
	0%	10%	0%	10%	0%	10%
2006	-	-	-	-	-	-
2007	32	28	32	28	30	26
2008	24	19	24	19	22	18
2009	128	91	128	91	115	82
2010	141	92	141	92	125	81
Thereafter	2,621	822	3,026	749	1,881	620
Total	2,946	1,052	3,351	979	2,173	827

Oil and Gas Wells

The following table summarizes JED's interest as at December 31, 2005 in wells that are producing and non-producing.


			Gross			Net
		Producing	Shut-in	Suspended	Producing	Shut-in	Suspended

Oil:	Alberta	44	0	6	16	0	2.36
	British Columbia	0	0	0	0	0	0
	North Dakota	0	1	0	0	0.3	0

Gas:	Alberta	31	7	9	22	2.6	5.76
	British Columbia	0	0	0	0	0	0
	North Dakota	0	0	0	0	0	0

	Totals:	75	8	15	38	2.9	8.12

Shut in (have encountered oil or gas, waiting on facilities to produce)

Suspended (have encountered oil or gas, uneconomic to produce)

Mineral Acreage Summary For JED Oil Inc.

JED has no undeveloped land inventory.

Additional Information Concerning Abandonment and Reclamation Costs

JED estimates well abandonment costs by area. Such costs are included in the McDaniel Report as deductions in arriving at future net revenue. The expected total abandonment costs included in the McDaniel Report for 45 net wells under the proved reserves category is $2,173,000 undiscounted ($827,000 discounted at 10%).

Tax Horizon

JED did not pay income taxes during the year ended December 31, 2005. 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 McDaniel Report, JED estimates that it will not be required to pay income taxes for the foreseeable future.

Costs Incurred

For the year ended December 31, 2005, JED incurred the following costs on its properties:

Cost Incurred Year Ended

December 31, 2005

($thousands)

Property Acquisition Costs

Proved Properties

148

Unproved Properties

Exploration Costs

Development Costs

53,927

54,075

Exploration and Development Activities

Year ended December 31, 2005

Exploratory Wells

Development Wells

Gross

Net

Gross

Net

Oil

8.42

Gas

22.5

Standing

10.1

D&A

2.89

Total

43.9

Production Estimates

The following table discloses for each product type the total volume of production estimated by McDaniel for 2006 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 estimates are applicable under both constant and forecast price scenarios.


Company's Production Estimated for
Year Ended December 31, 2006


	Light and			Natural Gas
	Medium Oil	Heavy Oil	Natural Gas	Liquids	BOE
Reserve Category	Gross [bbl/d]	Gross [bbl/d]	Gross [mcf/d]	Gross [bbl/d]	Gross [BOE/d]

Proved
Developed Producing	391	68	2,864	116	1,052
Developed Non-Producing	5	-	3,228	176	719
Undeveloped	6	-	5,384	168	1,071
Total Proved	445	68	11,476	460	2,842

Probable	36	-	2191	109	510

Total Proved Plus Probable	481	68	13,667	569	3,352



The Ferrier North area, which is located in Townships 40 to 42, 8W5, accounts for approximately 47% of the total
proved production as set forth below:



	Light and			Natural Gas
	Medium Oil	Heavy Oil	Natural Gas	Liquids	BOE
Reserve Category	Gross [bbl/d]	Gross [bbl/d]	Gross [mcf/d]	Gross [bbl/d]	Gross [BOE/d]

Proved
Developed Producing	-	-	1,179	69	265
Developed Non-Producing	-	-	2,554	148	574
Undeveloped	-	-	2,241	130	504
Total Proved	-	-	5,975	347	1,343

Probable	-	-	1,284	75	289

Total Proved Plus Probable	-	-	7,259	422	1,632


The Desan, British Columbia area, which is located in Township 38-02W5, accounts for approximately 18% of the total proved
production as set forth below:


	Light and			Natural Gas
	Medium Oil	Heavy Oil	Natural Gas	Liquids	BOE
Reserve Category	Gross [bbl/d]	Gross [bbl/d]	Gross [mcf/d]	Gross [bbl/d]	Gross [BOE/d]

Proved
Developed Producing	-	-	-	-	-
Developed Non-Producing	-	-	144	1	25
Undeveloped	-	-	2,814	18	487
Total Proved	-		2,958	19	512

Probable	-	-	258	2	45

Total Proved Plus Probable	-	-	3,216	21	557

Production History

The following table discloses, on a quarterly basis for the year ended December 31, 2005, JED's share of average daily production volume, prior to royalties, and the prices received, royalties paid, production costs incurred and netbacks on a per unit of volume basis for each product type.


	Quarter Ended
	2005
Average Daily Production	Mar 31	Jun 30	Sep 30	Dec 31

Nat Gas mcf/d	403	1,063	1,042	1,636
Oil bbl/d	507	388	561	313
NGL bbl/d	10	18	25	11
Combined (BOE/d)	585	583	759	596

	Quarter Ended
	2004
Average Prices Received	Mar 31	Jun 30	Sep 30	Dec 31

Nat Gas ($/mcf)	6.94	7.45	9.06	11.28
Oil ($/bbl)	40.36	47.58	58.01	45.47
NGL ($/bbl)	40.78	48.79	45.44	83.66
Combined ($/BOE)	40.52	46.74	56.77	56.31

Royalties - Combined ($/BOE)	9.11	4.10	9.64	11.31

Operating Expenses - Combined ($/BOE)	4.06	8.46	5.44	12.08

Netback Received - Combined ($/BOE)	27.35	34.18	41.69	32.92

DIRECTORS AND OFFICERS

The JED Board currently consists of 4 individuals. The directors are elected by the Shareholders by ordinary resolution, and hold office until the next annual meeting of Shareholders, which is anticipated to be held in May, 2006.

Name, Occupation and Securityholding

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


Name and Municipality of Residence	Position Held	Date First Elected or Appointed as Director
Reginald J. Greenslade^{(2) (3)}Calgary, Alberta	Chairman, and Director	September 3, 2003
Thomas J. Jacobsen^{(2) (4)} Didsbury, Alberta	CEO and Director	September 3, 2003
Alan F. Williams Calgary, Alberta	President	N/A
Justin W. Yorke^{(1) (3) (4) (5)} Pasadena, California	Director	November 7, 2005


James F. Dinning^{(1) (3) (4) (5)}Calgary, Alberta	Director	December 16, 2003
Ludwig Gierstorfer^{(1) (2) (3) (4) (5)}Cochrane, Alberta	Director	September 3, 2003

Notes:

(1)

Member of Audit Committee

(2)

Member of Compensation Committee

(3)

Member of Reserves Committee

(4)

Member of Governance and Nominating Committee

(5)

Member of Independent Committee for merger with JMG Exploration, Inc.

As at March 1, 2006, the directors and executive officers of JED, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, 589,782 Common Shares, representing approximately 4% 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 is set forth below.

Reginald (Reg) J. Greenslade. Chairman and Director

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

Thomas J. Jacobsen

Mr. Jacobsen became our President, Chief Operating Officer and Director in September 2003 and currently continues to serve as Chief Executive Officer and a Director. Mr. Jacobsen joined Westlinks Resources Ltd., a predecessor of Enterra Energy Trust, as a director in February 1999, and was appointed Executive Vice President, Operations in October 1999. In October 2000, he resigned from this position and was appointed Vice Chairman of The Board of Directors. Mr. Jacobsen became Enterra Energy Corp.’s Chief Operating Officer in February 2002 and resigned in November 2003. Mr. Jacobsen has more than 40 years experience in the oil and gas industry in Alberta and Saskatchewan including serving as President, Chief Operating Officer and a director of Empire Petroleum Corporation from June 2001 to April 2002, President and Chief Executive Officer of Niaski Environmental Inc. from November, 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. Mr. Jacobsen served as a director of Cariboo Resources Corp., formerly Niaski Environmental Services Inc. Niaski’s proposal to its creditors under the Bankruptcy and Insolvency Act (Canada) was accepted in April 2000 and Niaski was discharged in May 2001. All of the above companies were publicly traded in either the U.S., Canada, or both, during the periods indicated.

Alan F. Williams

Mr. Williams became our President in November 2005. Prior to that he helped form and was Chief Operating Officer and Vice President, Exploration of Endev Energy Inc. since April 2002. From September 1999 to December 2001 he was Vice President, Exploration of Allied Oil & Gas Corp., a Toronto Stock Exchange listed oil and gas issuer. From October 1997 to July 1999 he held the position of Vice President Exploration of Edge Energy Inc., and was Vice President, Exploration of Chancellor Energy Ltd. From November 1994 to April 1996.

Justin 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.

James F. Dinning

Mr. Dinning was appointed to our Board of Directors in December 2003. Since September, 2005 he has served as non-executive chairman of the board of Western Financial Group, Inc., a financial services company with a focus on "small town" Western Canada. From 1997 to 2005, he served in various executive vice-president roles at TransAlta Corporation. He has been a director of Shaw Communications, Inc. and Finning International, Inc. since 1997, Russel Metals, Inc. since 2003 and the Alberta Energy Research Institute. Prior to Q2 1997, Mr Dinning held several key positions during his 11 years as a member of the legislative assembly in Alberta. Of note is his service as Provincial Treasurer from 1992 to 1997. All the above private sector companies cited as work experience were publicly traded in Canada during the period indicated.

Ludwig (Louie) Gierstorfer

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

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 Cariboo Resources Corp., formerly Niaski Environmental Services Inc. Niaski’s proposal to its creditors under the Bankruptcy and Insolvency Act (Canada) was accepted in April 2000 and Niaski was discharged in May 2001.

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.

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 are authorized. At December 31, 2005 there were 14,630,256 Common Shares issued and outstanding, 1,291,255 Common Shares reserved for issuance pursuant to stock options, 118,500 Common Shares reserved for issuance pursuant to share purchase warrants, 1,000,000 Common Shares are reserved for the conversion of the outstanding Secured Subordinated Convertible Note and no Preferred Shares issued and outstanding.

Stock Split

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

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 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. As of December 31, 2004, 9,500,000 Common Shares were issued and outstanding. In addition, 190,000 Common Shares were reserved for issuance upon the exercise of outstanding warrants granted to the underwriter in JED’s initial public offering and 759,167 Common Shares were reserved for issuance upon the exercise of issued stock options.

Preferred Shares

JED has created a series of preferred shares consisting of 8,000,000 Series A convertible preferred shares (the “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, on the date, a receipt for a final prospectus is issued by the Alberta Securities Commission and lasting for 10 days. 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 holder 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. At December 31, 2004, JED had nil issues and outstanding Preferred Shares.

Dividend Record and Policy

JED has not declared or paid any dividends on its Common Shares since its incorporation, and 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.

INDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulations imposed by various levels of government. 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 and trusts of similar size. 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

In Canada, the price of natural gas sold intraprovincially 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 specific 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 governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas, which may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.

Pricing and Marketing – Oil

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.

The North American Free Trade Agreement

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

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

Royalties and Incentives

In addition to federal regulation, each province has legislation and regulations, which govern land tenure, royalties, production rates, environmental protection and other matters. 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 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, Alberta, British Columbia and Saskatchewan 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

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.

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

In December of 2002, Canada became a signatory to the Kyoto Protocol. The implementation of this plan has not been fully defined by the federal 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.

RISK FACTORS

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

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

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

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

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

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

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

The level of production from our existing properties may decline at rates greater than anticipated due to unforeseen circumstances, many of which are beyond our control. A significant decline in our production could result in materially lower revenues and cash flow.

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

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

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

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

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

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

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

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

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

initial production rates;

production decline rates;

ultimate recovery of reserves;

success of future development activities;

marketability of production;

effects of government regulation; and

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

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

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

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

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

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

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

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

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

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

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

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

restrictions imposed by lenders;

accounting delays;

delays in the sale or delivery of products;

delays in the connection of wells to a gathering system;

blowouts or other accidents;

adjustments for prior periods;

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

the establishment by the operator of reserves for these expenses.

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

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

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

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

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

The amounts available under our existing credit facility may not be sufficient for future operations, or we may not be able to obtain additional financing on economic terms attractive to us, if at all. Our current credit facility consists of a revolving operating demand loan. Repayment of all outstanding amounts may be demanded at any time. If this occurs, we may need to obtain alternate financing. Any failure to obtain suitable replacement financing may have a material adverse effect on our business.

The oil and natural gas industry is highly competitive.

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

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

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

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

The oil and natural gas industry is subject to extensive environmental regulation pursuant to local, provincial and federal legislation. A breach of that legislation may result in the imposition of fines or the issuance of "clean up" orders. Legislation regulating the oil and natural gas industry may be changed to impose higher standards and potentially more costly obligations. For example, the 1997 Kyoto Protocol to the United Nation's Framework Convention on Climate Change, known as the Kyoto Protocol, was ratified by the Canadian government in December, 2002 and will require,

among other things, significant reductions in greenhouse gases. The impact of the Kyoto Protocol on us is uncertain and may result in significant 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. Financing and administration costs are excluded from the calculation under U.S. GAAP. At December 31, 2004 JED realized a U.S. GAAP ceiling test write-down of US$4.2 million. There were no such write-downs required at December 31, 2005.

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

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

Although we conduct title reviews in accordance with industry practice prior to any purchase of resource assets, such reviews do not guarantee that an unforeseen defect in the chain of title will not arise and defeat our title to the purchased assets. If such a defect were to occur, our entitlement to the production from such purchased assets could be jeopardized.

Aboriginal Land Claims

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

Changes in tax and other laws may adversely affect Shareholders.

Income tax laws, other laws or government incentive programs relating to the oil and gas industry, 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.

Income Tax Matters

On October 31, 2003, the Department of Finance (Canada) released, for public comment, proposed amendments to the Tax Act that relate to the deductibility of interest and other expenses for income tax purposes for taxation years commencing after 2005. In general, the proposed amendments may deny the realization of losses in respect of a business if there is no reasonable expectation that the business will produce a cumulative profit over the period that the business can reasonably be expected to be carried on. If such proposed amendments were enacted and successfully invoked by the CCRA against JED or a subsidiary entity, it could materially adversely affect our cash flow. However, JED believes that it is reasonable to expect JED and each subsidiary entity to produce a cumulative profit over the expected period that the business will be carried on.

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

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

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

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

Shareholders are entirely dependent on the management of JED with respect to the acquisition of oil and gas properties and assets, the development and acquisition of additional reserves and the management and administration of all matters relating to our oil and natural gas properties. The loss of the services of key individuals who currently comprise the management team could have a detrimental effect on JED. Investors should carefully consider whether they are willing to rely on the existing management before investing in the Common Shares.

There may be future dilution.

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

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

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

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

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

diversion of management's attention;

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

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

inability to retain the acquired company's customers;

exposure to legal claims for activities of the acquired business prior to acquisition; and inability to integrate the acquired company and its employees into our organization effectively.

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
	High (US$)	Low (US$)	Volume (000's)
2005
January	12.05	9.44	1,174
February	12.73	10.50	752
March	12.51	10.40	693
April	11.45	10.11	1,020
May	12.30	10.43	870
June	17.13	11.87	2,617
July	19.64	16.17	1,181
August	21.50	17.47	2,020
September	18.63	15.93	1,726
October	19.33	15.79	1,303
November	19.20	16.38	659
December	15.87	11.65	3,073

Prior Sales

During 2003, JED issued 7,600,000 Series A Preferred Shares, which were all converted to 7,600,000 Common Shares during 2005.

In April 2005, 1,900,000 Common Shares were sold to underwriter Gilford Securities Incorporated in an initial public offering of the Common Shares.

In August 2006, JED issued a Senior Subordinated Convertible Note in the amount of US$20 million to an arms-length California limited partnership. This Note bears interest at the rate of 10% per annum, is due February 1, 2008 and is convertible at the holder’s option into one million common shares for the principal amount and the conversion of accrued interest into common shares on the basis of US$20.00 per share

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.

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

Underwriting Agreement dated April 12, 2005. See “Prior Sales”.

Senior Subordinated Secured Note dated August 3, 2006. See “Prior Sales”.

INTERESTS OF EXPERTS

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

AUDIT COMMITTEE

General

JED has established an Audit Committee (the "Audit Committee") comprised of three members: Justin W. Yorke, Chairman, Ludwig Gierstorfer and James F. Dinning, each of whom is considered "independent", and Mr. Yorke 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.


*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.

Ludwig Gierstorfer		Mr. Gierstorfer is the former founder, CEO and director of a privately held public drilling company. He is familiar with financial information as presented in audited financial statement and annual and interim reports.



James F. Dinning		Mr. Dinning was the Provincial Treasurer of Alberta from 1992 to 1997 and has held positions as directors and officers in a number of public companies. He holds a Bachelor of Commerce honors degree and a Masters degree in Public Administration, both from Queens University, and an honorary Doctor of Laws from the University of Calgary.

External Auditor Services Fees

For the year ended December 31, 2005, Ernst & Young and its affiliates were paid approximately C$172,810 as detailed below:


		Year ended December 31, 2005
Ernst & Young		C$
	Audit fees⁽¹⁾	$	136,623
	Audit-related fees	$
	Tax Fees	$	1,665
	All Other Fees	$	34,522
	Total	$	172,810

Note:

(1)

The audit fees include the costs related to the annual audit and services related to public financings and related reporting to regulators.

The Chairman of 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.

ADDITIONAL INFORMATION

Additional information in respect of JED may be found on SEDAR at www.sedar.com. JED will provide to any person, upon request to the Corporate Secretary of JED:

when the securities of JED are in the course of a distribution pursuant to a short form prospectus or a preliminary short form prospectus has been filed in respect of a proposed distribution of its securities:

one copy of the Annual Information Form of JED, together with one copy of any document, or the pertinent pages of any document, incorporated by reference in the Annual Information Form;

one copy of the financial statements of JED for the completed financial year ended December 31, 2005, together with the accompanying report of the auditors thereon, as well as one copy of any interim financial statements of JED subsequent to December 3,1 2005;

one copy of any other documents that are incorporated by reference into the preliminary short form prospectus or the short form prospectus that are not required under paragraphs (a) or (b) above; or

at any time, one copy of any of the document referred to in paragraphs 1(a), (b), and (c) above, provided that JED may require the payment of a reasonable charge if the request is made by a person who is not a security holder of JED.

Additional information related to the remuneration and indebtedness of the directors and officers of JED, and the principal holders of Common Shares and rights to purchase Common Shares, where applicable, is contained in the management information circular in respect of the next annual meeting of Shareholders of JED. Additional financial information is provided in the audited financial statements and MD&A of JED for the year ended December 31, 2005.

Additional copies of this Annual Information Form may be obtained from JED. Please contact:

JED Oil Inc.
2200, 500 - 4th Avenue SW.
Calgary, Alberta T2P 2V6

Telephone: (403) 537-3250
Fax: (403) 536-3221

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.

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 behavior.

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.

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 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: (1) 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; (2) 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.

APPENDIX "B" –
REPORT ON RESERVES DATA BY INDEPENDENT
QUALIFIED RESERVES EVALUATOR OR AUDITOR

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

To the board of directors of JED Oil Inc. (the "Company"):

We have evaluated the Company’s reserves data as at December 31, 2005. The reserves data consists of the following:

(a)

(i)

proved and proved plus probable oil and gas reserves estimated as at December 31, 2005 using forecast prices and costs; and

(ii)

the related estimated future net revenue; and

(b)

(i)

proved oil and gas reserves estimated as at December 31, 2005 using constant prices and costs; and

(ii)

the related estimated future net revenue.

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).

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.

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, 2005, and identifies the respective portion thereof that we have evaluated, audited and reviewed and reported on to the Corporation's management.


Description and Preparation Data of Audit/ Evaluation/ Review Report	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (before income taxes 10% discount rate - $M)
	Location of Reserves (Country or Foreign Geographic Area)	Audited	Evaluated	Reviewed	Total
December 31, 2005	Canada	$ -	$104,930	$ -	$104,930

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.

We have no responsibility to update this evaluation for events and circumstances occurring after their respective preparation date.

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.

(signed)

McDaniel & Associates Consultants Ltd.
Calgary, Alberta

Dated March 31, 2006.

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:

(a)

(i)

proved and proved plus probable oil and gas reserves estimated as at December 31, 2005 using forecast prices and costs; and

(ii)

the related estimated future net revenue; and

(b)

(i)

proved oil and gas reserves estimated as at December 31, 2005 using constant prices and costs; and

(ii)

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:

(c)

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

(d)

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;

(e)

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:

(f)

the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;

(g)

the filing of the report of the independent qualified reserves evaluator; and

(h)

the content and filing of this report.

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

(signed)

Reg J. Greenslade
Chairman and Director

(signed)

Thomas J. Jacobsen
CEO and Director

(signed)

Ludwig Gierstorfer
Director

(signed)

James F. Dinning

Director

(signed)

Justin W. Yorke
Director

March 31, 2006