Jed

EX-99 5 jedq305mdafinaldoc.htm MANAGEMENT'S DISCUSSION & ANALYSIS Jed

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following is Management’s discussion and analysis (“MD&A”) of JED Oil Inc. (“JED”) for the three and nine-month periods ended September 30, 2005. This MD&A should be read in conjunction with the unaudited interim consolidated financial statements of JED Oil Inc. (“JED”) for the three and nine-months ended September 30, 2005, other financial information included in this quarterly report and with the MD&A and the audited consolidated financial statements for the year ended December 31, 2004 and accompanying notes contained in the 2004 Annual Report. This MD&A was written as of November 8, 2005. All amounts are stated in United States dollars except where otherwise indicated.

CERTAIN FINANCIAL REPORTING MEASURES

The term “funds from operations” or “cash flow” is defined as net income (loss) before non-cash operating items such as depletion, depreciation and accretion, future income taxes, stock-based compensation and foreign exchange gains or losses and excludes changes in non-cash working capital. The term “netback”, which is calculated as the average unit sales price, less royalties and production expenses, represents the cash margin for every barrel of oil equivalent sold. These terms do not have any standardized meaning prescribed by United States Generally Accepted Accounting Principles (“GAAP”) and therefore may not be comparable with the calculation of similar measures for other companies.

It is management’s view, based on its communications with investors during events like conference calls, webcasts or road shows, that funds from operations is relevant to our investors and shareholders. Funds from operations is reconciled to GAAP earnings in a table included in this MD&A.

Natural gas volumes recorded in thousand cubic feet (“mcf”) are converted to barrels of oil equivalent (“BOE”) using the ratio of six (6) thousand cubic to one (1) barrel of oil (“bbl”). BOE’s may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf:1 bbl is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead.

SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS

This interim report includes forward-looking statements. All statements other than statements of historical facts contained in this interim report, including statements regarding our future financial position, business strategy and plans and objectives of management for future operations, are forward-looking statements. The words “believe,” “may,” “will,” “estimate,” “continue,” “anticipate,” “intend,” “should,” “plan,” “expect” and similar expressions, as they relate to us, are intended to identify forward-looking statements. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends that we believe may affect our financial condition, results of operations, business strategy and financial needs. These forward-looking statements are subject to a number of risks, uncertainties and assumptions described in our 2004 Annual Report on Form 20-F, our Annual Information Report and elsewhere in this interim report.

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

We undertake no obligation to update publicly or revise any forward-looking statements. You should not rely upon forward-looking statements as predictions of future events or performance. We cannot assure you that the events and circumstances reflected in the forward-looking statements will be achieved or occur. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements.

Incorporation and Commencement of Operations

JED Oil Inc. (“JED” or the “Company”) was incorporated under the laws of the Province of Alberta on September 3, 2003 and commenced oil and gas operations in the second quarter of 2004.

Overview

JED’s production for the third quarter averaged 759 barrels of oil equivalent per day (boe/d), including 586 barrels per day of medium and heavy oil and 1,042 thousand cubic feet per day of natural gas. This is up 313% from 184 boe/d in the same period in 2004. For the nine-month period ended September 30, 2005, the Company averaged 643 boe/d of production compared with 107 boe/d for the same period in 2004. The 501% increase in production is a result of the wells drilled late in 2004 and to date in 2005.

Summarized Financial and Operational Data


	Three Months Ended Sept 30			Nine Months Ended Sept 30
	2005	2004	Change	2005	2004	Change
Exit production rate (boe/d)	700	200	250%	700	200	250%
Petroleum and natural gas revenues	$3,294,276	$570,176	478%	$7,028,176	$966,347	627%
Average sales volumes (boe/d)	759	184	313%	643	107	501%
Funds from operations	$1,475,430	$190,792	673%	$4,003,902	$180,236	2,121%
Funds from operations per share, basic ⁽¹⁾	$0.10	$0.01	900%	$0.28	$0.02	1,300%
Net income (loss)	$446,165	($616,166)	172%	$1,445,086	($978,732)	248%
Net income (loss) per share, basic⁽¹⁾	$0.03	($0.04)	175%	$0.10	($0.10)	200%
Average number of shares outstanding - basic⁽¹⁾	14,581,186	14,250,000	2%	14,418,500	9,373,701	54%
Average price for oil and natural gas liquids (US$/bbl)	$48.07	$34.36	40%	$40.31	$33.51	20%
Average price for natural gas (US$/mcf )	$7.53	$4.28	76%	$6.58	$4.33	52%
Operating costs per boe	$4.52	($0.63)	817%	$4.85	$2.01	141%
General and administrative expenses per boe (cash portion)	$10.61	$16.36	-35 %	$6.01	$28.74	-79%

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

Production Volumes


	Three Months Ended Sept 30			Nine Months Ended Sept 30
Average daily production	2005	2004	Change	2005	2004	Change
Crude oil and natural gas liquids (bbls/d)	586	170	245%	503	102	393%
Natural gas (mcf/d)	1,042	87	1,098%	838	31	2,603%
Total (boe/d)	759	184	313%	643	107	501%


	Three Months Ended Sept 30			Nine Months Ended Sept 30
Exit production	2005	2004	Change	2005	2004	Change
Exit crude oil and liquids production (in bbls/day)	475	175	171%	475	175	171%
Exit natural gas production (in mcf/day)	1,350	150	800%	1,350	150	800%
Exit total production (in boe/day)	700	200	250%	700	200	250%

Petroleum and Natural Gas Revenue

For the three-months ended September 30, 2005, petroleum and natural gas revenues increased 478% to $3,294,276 from $570,176 for the same period in 2004. The increase is due to higher production volumes for the quarter as a result of the drilling activities in 2004 and in the first nine-months of 2005 as well as increased commodity prices. Production revenue for the three-months ended September 30, 2005 consisted of $2,572,792 of crude oil and natural gas liquids and $721,484 of natural gas sales.

For the nine-months ended September 30, 2005, petroleum and natural gas revenues increased 627% to $7,028,176 from $966,347 for the same period in 2004. The increase is due to higher production volumes for the nine-month period ended September 30, 2005 as a result of the drilling activities in 2004 and to date in 2005 as well as increased commodity prices.

For the three and nine-months ended September 30, 2005, petroleum and natural gas sales revenue were made up of the following balances compared with the same period in 2004.


	Three Months Ended Sept 30			Nine Months Ended Sept 30
Revenue by Product	2005	2004	Change	2005	2004	Change
Crude oil and natural gas liquids	$2,572,792	$535,834	380%	$5,521,612	$930,083	494%
Natural gas	$721,484	$34,342	2,001%	$1,506,564	$36,264	4,054%
Total petroleum and natural gas revenue	$3,294,276	$570,176	478%	$7,028,176	$966,347	627%

Commodity Pricing

For the three and nine-month periods ended September 30, 2005, JED realized the following commodity prices compared with the same periods in 2004:


	Three Months Ended Sept 30			Nine Months Ended Sept 30
Commodity Pricing Benchmarks	2005	2004	Change	2005	2004	Change
West Texas Intermediate (US$/bbl)	$63.19	$43.88	44%	$55.40	$39.12	42%
Exchange rate (1 $CDN = $US)	0.83	0.77	8%	0.82	0.75	9%
West Texas Intermediate (CDN$/bbl)	$75.95	$57.36	32%	$67.81	$51.95	31%
AECO monthly index (Cdn$/mcf)	$8.52	$6.95	23%	$7.73	$6.98	11%



	Three Months Ended Sept 30			Nine Months Ended Sept 30
Average Prices received by JED	2005	2004	Change	2005	2004	Change
Oil and Natural gas liquids (US$/bbl)	$48.07	$34.36	40%	$40.31	$33.51	20%
Natural gas (US$/mcf )	$7.53	$4.28	76%	$6.58	$4.33	52%
Total (US$/boe)	$47.16	$33.68	40%	$40.03	$33.15	21%

For the three and nine-month periods ended September 30, 2005, the Company earned interest revenue of $133,011 (2004 - $85,785) and $342,819 (2004 - $371,426), respectively, through the investment of idle cash balances in low risk, short term deposits and interest earned on the note receivable from Enterra Energy Trust.

JED currently does not have any financial derivative or fixed price contracts in place. All crude oil and natural gas volumes are being sold in the spot market.

Royalties

Royalties include crown, freehold and gross overriding royalties paid to respective royalty owners based on production and sales of crude oil and natural gas. Royalties for the three-month period ended September 30, 2005 were $559,464, an increase of 181% from $198,767 for the same period in 2004. For the nine-month period ended September 30, 2005, royalties were $1,125,553, an increase of 331% from $261,105 for the same period in 2004. The increase in royalties is primarily due to the increase in petroleum and natural gas revenue for both the three and nine-month periods in 2005 as compared to the same periods in 2004.

For the three-month period ended September 30, 2005, royalties as a percentage of petroleum and natural gas revenues decreased 51% from 35% to 17%. For the nine-month period ended September 30, 2005, royalties as a percentage of petroleum and natural gas revenues decreased by 41% from 27% to 16%. The decrease is attributable to the lower than anticipated royalty rates on the low productivity wells. In 2004, the Company overestimated the royalty rates for the producing wells.


	Three Months Ended Sept 30			Nine Months Ended Sept 30
	2005	2004	Change	2005	2004	Change
Royalties	$559,464	$198,767	181%	$1,125,553	$261,105	331%
As a percentage of petroleum and natural gas revenue	17%	35%	-51%	16%	27%	-41%
Royalties per boe	$8.01	$11.74	-32%	$6.41	$8.96	28%

Management anticipates that based on current commodity prices, the average royalty rates for the remainder of 2005 will remain at approximately 18% to 20% of petroleum and natural gas revenue.

Production Expenses

Production expenses increased 3,081% to $315,632 during the third quarter of 2005 compared to a credit of $10,587 during the same period in 2004. For the nine-months ended September 30, 2005, production expenses increased 1,354% to $850,690 compared to $58,520 during the same period in 2004. The increase in production expenses is mainly attributed to the increase in production volumes in 2005 compared to the same periods in 2004. JED commenced field operations during the second quarter of 2004 and has realized production volume growth for the three and nine-month periods ended September 30, 2005 of 313% and 501%, respectively, when compared with the same periods in 2004. On a boe basis, production expenses for the three-months ended September 30, 2005, increased 817% from a credit of $0.63 per boe in 2004 to $4.52 per boe for the same period in 2005. The increase in boe production costs is attributable to the drilling of wells in the Sousa area of Northern Alberta, which is a winter access only area and production costs are traditionally higher than other year-round access areas. In the third quarter of 2004, negative production costs were a result of an over accrual of operating costs in the second quarter of 2004 which was higher than the actual production costs for the Company. The over accrual was due in part to the limited operating history in the new areas that the Company had drilled.

Management expects that production costs, on a per boe basis, will remain at the $5.00 per boe level for the remainder of 2005.


	Three Months Ended Sept 30			Nine Months Ended Sept 30
	2005	2004	Change	2005	2004	Change
Production expenses	$315,632	($10,587)	3,081%	$850,690	$58,520	1,354%
As a percentage of petroleum and natural gas revenue	10%	(2%)	600%	12%	6%	100%
Production expenses per boe	$4.52	($0.63)	817%	$4.85	$2.01	141%

Depletion, Depreciation and Accretion


	Three Months Ended Sept 30			Nine Months Ended Sept 30
	2005	2004	Change	2005	2004	Change
Depletion, depreciation and accretion expense	$837,819	$221,498	278%	$2,275,614	$350,412	549%
As a percentage of petroleum and natural gas revenue	25%	39%	-36%	32%	36%	-11%
Depletion, depreciation and accretion expense per boe	$11.99	$13.08	-8%	$12.96	$12.07	7%

The Company follows the full cost method of accounting for oil and gas operations. Accordingly, the cost of all successful and unsuccessful wells are added to the Company’s capital base and depleted at the rate of production over the remaining proved reserves as determined by independent reserve engineers or the Company’s internal engineers.

For the three-months ended September 30, 2005, depletion and depreciation of property and equipment and the accretion of the asset retirement obligations (“DD&A”) increased by 278% to $837,819 from $221,498 for the same period in 2004. For the nine-month period ended September 30, 2005, DD&A increased 549% to $2,275,614 from $350,412 for the same period in 2004. The increase for both periods is due to the increased production volumes and a higher depletable base as a result of the 2005 capital program. On a boe basis, DD&A for the third quarter of 2005 decreased due to increased reserve additions as a result of the successful drilling program in the second and third quarter of 2005. For the nine-month period ended September 30, 2005, DD&A, on a per boe basis, increased 7% due to the overall increase in industry capital costs which is partially offset by the increased reserve additions in the period.

With the increased costs associated with the overall industry record drilling activity, management expects depletion, depreciation and accretion per boe to remain at its current level for the remainder of 2005.

General and Administrative Expenses


	Three Months Ended Sept 30			Nine Months Ended Sept 30
	2005	2004	Change	2005	2004	Change
General and administrative expenses - cash portion (net)	$741,335	$276,989	168%	$1,055,424	$837,912	26%
Stock-based compensation (non-cash)	$392,423	$57,889	578%	$671,937	$163,308	311%
As a percentage of petroleum and natural gas revenue - cash portion	22%	49%	-55%	15%	87%	-83%
General and administrative expenses per boe - cash portion	$10.61	$16.36	-35%	$6.01	$28.74	-79%

For the three-month period ended September 30, 2005, general and administrative (“G&A”) expenses, net of capitalized G&A, increased 168% to $741,335 from $276,989 for the same period in 2004. For the nine-month period ended September 30, 2005, G&A expenses increased by 26% to $1,055,424 from $837,912 for the same period in 2004. The increase in G&A for both the three and nine-month periods is mainly attributable to the increased staff levels required for the extensive drilling program currently underway, as well as, the increased production of the Company throughout the year. In addition, a bonus recovery of $803,737 was recorded in the second quarter of 2005 that was recovered from Enterra. The bonus was originally expensed in the Company’s 2004 records. The recovery of the bonus was approved by the Enterra shareholders and paid in July 2005. Partially

offsetting this recovery is a $630,467 provision for the Company’s 2005 bonus. No bonus recovery is expected for 2005. Without the bonus recovery in the second quarter, G&A, net of capitalized G&A, for the nine-month period ended September 30, 2005 would have increased 122% to $1,859,161 or $10.59 per boe.

For the three and nine-month periods ended September 30, 2005, stock based compensation expense relating to the Company’s stock option plan was $392,423 and $671,937, respectively, compared with $57,889 and $163,308 for the same periods in 2004. The increase for both periods is due to the increase in the fair value per share of the stock options issued based on the increased weighted average volatility of 1% for the three and nine-month periods in 2004 to 35% and 28%, respectively, for the same periods in 2005. Prior to April 6, 2004, when most of the stock options were issued, the Company was private and the volatility of the Company’s stock was set at a nominal value of 1%. Also contributing to the increase in stock-based compensation for the three and nine-month periods ending September 30, 2005 is the immediate expensing of stock options issued to a director of the Company. Stock options issued to members of the Board of Directors all vest immediately and therefore, the fair value of those stock options are expensed in the period they are issued.

Interest Expense

The Company issued $20,000,000 Convertible Subordinated Note Agreement on August 3, 2005 that bears interest at a rate of 10% per annum. The Company incurred interest expense for the three and the nine-month periods ended September 30, 2005 of $335,426 for each period. The Company had no debt in 2004; therefore, no interest expense was recorded for the three and nine-month periods in 2004.

Foreign Exchange Gain (loss)

Foreign exchange gain for the three and nine-month periods ended September 30, 2005 was $200,977 and $388,735, respectively, as compared to a loss of $527,571 and 643,855 in the same periods in 2004. The foreign exchange gain in the three and nine-month periods ending September 30, 2005 is primarily from the weakening of the Canadian dollar relative to the US dollar. The Company holds US denominated cash and cash equivalents and records a gain when the Canadian dollar weakens as compared to the US dollar.

Income Taxes

The Company has recorded no income, capital or other taxes for the three and nine-month periods ended September 30, 2005 and 2004.

Net Income


	Three Months Ended Sept 30			Nine Months Ended Sept 30
	2005	2004	Change	2005	2004	Change
Net income (loss)	$446,165	($616,166)	172%	$1,445,086	($978,732)	248%
Net income (loss) as a percentage of total revenue	14%	(108%)	113%	21%	(101%)	121%
Net income (loss) on a per boe basis	$6.39	($36.39)	118%	$8.23	($33.57)	125%
Net income (loss) per share – basic ⁽¹⁾	$0.03	($0.04)	175%	$0.10	($0.10)	200%
Net income (loss) per share – diluted ⁽¹⁾	$0.03	($0.04)	175%	$0.09	($0.10)	190%
Weighted average shares outstanding – basic ⁽¹⁾	14,581,186	14,250,000	2%	14,418,500	9,373,701	54%
Weighted average shares outstanding – diluted⁽¹⁾	15,457,579	14,281,499	8%	15,264,449	9,924,148	54%

Net income for the quarter ended September 30, 2005 was $446,165 compared to a loss of $616,166 for the same period in 2004. Net income for the nine-month period ended September 30, 2005 was $1,445,086 compared to a loss of $978,732 for the same period in 2004. The increase in earnings is due to increased oil and natural gas production revenue as a result of increased production volumes and an increase in commodity prices for the three and nine-month periods in 2005 as compared to the same periods in 2004.

Net income per basic and diluted share was $0.03 for the third quarter of 2005 compared with a loss per share of $0.04 for both basic and diluted in the same period in 2004. For the nine-month period ended September 2005, net income per basic and diluted share was $0.10 and $0.09, respectively, compared with a loss per basic and diluted share of $0.10 for the same period in 2004.

For the nine-month period ended September 30, 2005, the weighted average number of shares outstanding increased 54% from the same period in 2004 due to the initial public offering in 2004 being completed and the Company commencing trading on April 6, 2004 which reduced the weighted average share number as they were only outstanding for a partial period in 2004.

Both the 2004 and 2005 three and nine-month period per share figures have been adjusted to reflect the 3-for-2 stock split that occurred in October 2005.

Funds From Operations

Funds from operations increased 673% to $1,475,430 for the three-month period ended September 30, 2005 compared to $190,792 during the same period in 2004. The increase is primarily due to increased oil and natural gas production volumes and higher commodity prices in the third quarter of 2005 as compared to the same period in 2004. Funds from operation per basic share for the third quarter was $0.10 compared with $0.01 per basic share in the same quarter of 2004.

Funds from operations increased 2,121% to $4,003,902 for the nine-month period ended September 30, 2005 compared to $180,236 during the same period in 2004. The increase is primarily due to increased oil and natural gas production volumes and higher commodity prices in 2005 versus the same period in 2004. Funds from operations per basic share for the nine-months ended September 30, 2005 was $0.28 compared with $0.02 per basic share in the same period of 2004.

It is management’s view that funds from operations is a very useful measure of performance. Funds from operations is a good benchmark when comparing results from year to year or quarter to quarter because it excludes one-time non-cash and non-recurring events that may otherwise distort the financial results. Funds from operations is a non-GAAP measure, reconciled with GAAP net earnings in the table below:


	Three Months Ended Sept 30			Nine Months Ended Sept 30
	2005	2004	Change	2005	2004	Change
Net income (loss)	$446,165	($616,166)	172%	$1,445,086	($978,732)	248%
Add back (subtract) non-cash items:
Depletion, depreciation and accretion	$837,819	$221,498	278%	$2,275,614	$350,412	549%
Foreign exchange (gain) loss	($200,977)	$527,571	-138%	($388,735)	$643,855	-160%
Stock-based compensation	$392,423	$57,889	578%	$671,937	$163,308	311%
Amortization of deferred financing costs	-	-	-	-	$1,393	N/A
Funds from operations	$1,475,430	$190,792	673%	$4,003,902	$180,236	2,121%
As a percentage of total revenue	45%	33%	36%	57%	19%	200%
Funds from operations per boe	$21.12	$11.27	87%	$22.81	$6.18	269%
Per share information
Funds from operations per share - basic	$0.10	$0.01	900%	$0.28	$0.02	1,300%
Funds from operations per share - diluted	$0.10	$0.01	900%	$0.26	$0.02	1,200%
Weighted average shares outstanding – basic⁽¹⁾	14,581,186	14,250,000	2%	14,418,500	9,373,701	54%
Weighted average shares outstanding – diluted ⁽¹⁾	15,457,579	14,281,499	8%	15,264,449	9,924,148	54%

Capital Expenditures

Cash capital expenditures for the quarter ended September 30, 2005 were $1,457,929 compared to $671,606 in the same period in 2004. For the nine-months ended September 30, 2005, the Company has invested $16,743,793 compared to $4,802,149 for the same period in 2004.

During the third quarter of 2005, the Company drilled 17 gross wells (5.0 net) with an overall success rate of 94% which included 9 gross (2.9 net) successful wells at Provost in Central Alberta, 6 gross (1.1 net) successful wells drilled at Princess in Southern Alberta, 1 gross (0.70 net) well at Ricinus in West Central Alberta, a new area that Enterra has acquired through the acquisition of High Point Resources Inc., and 1 gross (0.3 net) dry hole.


	Three Months Ended Sept 30			Nine Months Ended Sept 30
Capital Expenditures	2005	2004	Change	2005	2004	Change
Drilling and completions	$2,145,345	($296,746)	823%	$12,955,037	$2,800,973	363%
Facilities and equipment	($698,889)	$721,077	-197%	$3,627,422	$1,427,838	154%
Corporate	$11,473	$247,276	-95%	$161,334	$573,338	-72%
Total	$1,457,929	$671,606	117%	$16,743,793	$4,802,149	249%

Liquidity and Capital Resources

The Company currently does not have a bank credit facility. On August 3, 2005, the Company closed a $20,000,000 Convertible Subordinated Note Agreement with a qualified limited partnership. The convertible note bears interest at a rate of 10% per annum payable in quarterly payments commencing on November 1, 2005 and has a term through February 1, 2008. The proceeds on the note will be used to fund the capital drilling program for the remainder of 2005. With the closing of the Convertible Note and with the anticipated cash flow from operating activities for the year, and the anticipated repayment from Enterra of the note and additional balances owing from Enterra, the Company has sufficient capital resources to fund its anticipated drilling program through the end of 2005.

On July 27, 2005, the Company entered into a Loan Agreement and Promissory Note with an arms length party whereas the Company advanced the party C$5,000,000 for the construction of drilling equipment. In return for the note, the Company will be provided five dedicated drilling rigs for a period of three years. The loan will be repaid to the Company through payment from a portion of the drilling rigs daily charges until paid in full. The note is secured by a General Security Agreement over all assets of the third party, bears no interest and has no set repayment schedule. The drilling rigs are scheduled to be delivered to the Company at various dates in late 2005 and 2006 with the first rig to be delivered on December 1, 2005.

At November 8, 2005, JED had a total of 14,617,754 shares outstanding (December 31, 2004 – 14,250,000), 1,181,250 stock options outstanding (2004 – 1,138,751), 156,000 share purchase warrants outstanding (2004 – 251,250) and 1,000,000 (2004 – Nil) shares reserved for issuance upon conversion of the Convertible Subordinated Note that closed on August 3, 2005. All share numbers are after the effectiveness of the 3-for-2 stock split which occurred in October 2005.

Commitments and Guarantees

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

The Company has entered into five separate Standard Daywork Contracts with a drilling contractor who will supply the Company with five drilling rigs for a period of three years. The terms of each contract call for a minimum requirement of 250 operating days per year for a total of 750 operating days over the three-year term of each contract.

ADDITIONAL INFORMATION

Additional information relating to the Company is filed on SEDAR and can be viewed at www.sedar.com. Information can also be obtained by contacting the Company at 2600, 500 – 4^th Avenue S.W., Calgary, Alberta, Canada, T2P 2V6 or by email at jedinfo@jedoil.com. Information is also available on the Company’s website at www.jedoil.com.