DXI Capital (DXIEF) 20-F 2010 FY Annual report (foreign)

SUPPLEMENTARY OIL AND GAS RESERVE ESTIMATION AND DISCLOSURES – ASC 932 (UNAUDITED)

In January 2010, the FASB issued an ASU to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules. The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month arithmetic average of the first day of the month prices and additional disclosure requirements. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. The amendments are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments. Application of the amended guidance has only resulted in changes to the prices used to determine proved reserves at December 31, 2009, which did not result in a significant change to the Company's proved oil and natural gas reserve volumes. The new guidelines have expanded the definition of proved undeveloped reserves that can be recorded from an economic producer. The opportunity to prove reasonable certainty for spacing areas located more than one direct development spacing area from economic producer did not impact or prove undeveloped reserves.

(a)  Net proved oil and gas reserves

As at December 31, 2010, the Company’s oil and gas reserves are located in both Canada and the United States.  The Company engaged independent qualified reserve evaluators, GLJ Petroleum Consultants Ltd. (“GLJ”) to review the Company’s proved developed and undeveloped oil and gas reserves in Canada, and Gustavson Associates (“Gustavson”) to review the Company’s proved developed and proved undeveloped oil and gas reserves in U.S.A.  The changes in our net proved reserve quantities are outlined below.

The tables in this section set forth oil and gas information prepared by the Company in accordance with U.S. disclosure standards, including Accounting Standards Codification 932 (“ASC 932”).

Net reserves are Dejour royalty and working interest remaining reserves, less all Crown, freehold, and overriding royalties and interests that are not owned by Dejour.

Proved reserves are those estimated quantities of crude oil, natural gas and natural gas liquids that can be estimated with a high degree of certainty to be economically recoverable under existing economic and operating conditions.  It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

Proved developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.  Developed reserves may be subdivided into producing and non-producing.

Proved undeveloped reserves are those reserves that are expected to be recovered from known accumulations where a significant expenditure (e.g. when compared to the cost of drilling a well) is required to render them capable of production.

The Company cautions users of this information as the process of estimating crude oil and natural gas reserves is subject to a level of uncertainty.  The reserves are based on economic and operating conditions; therefore, changes can be made to future assessments as a result of a number of factors, which can include new technology, changing economic conditions and development activity.

(a)   CONSTANT PRICES AND COSTS - YEAR ENDED DECEMBER 31, 2010

Net Proved Developed and Proved Undeveloped Reserves
	Canada												United States									Total
	Light and			Natural Gas						Barrels of Oil			Light and						Barrels of Oil			Light and			Natural Gas						Barrels of Oil
	Medium Oil			Liquids			Natural Gas			Equivalent			Medium Oil			Natural Gas			Equivalent			Medium Oil			Liquids			Natural Gas			Equivalent
	(Mbbl)			(Mbbl)			(MMcf)			(Mboe)			(Mbbl)			(MMcf)			(Mboe)			(Mbbl)			(Mbbl)			(MMcf)			(Mboe)
December 31, 2009		98			4			753			227			397			60,197			10,430			495			4			60,950			10,657
Discoveries		-			-			195			33			-			-			-			-			-			195			33
Extensions *		-			-			-			-			-			-			-			-			-			-			-
Infill Drilling *		-			-			-			-			-			-			-			-			-			-			-
Improved Recovery *		66			-			(19	)		63			-			-			-			66			-			(19	)		63
Technical Revisions		70			2			654			181			(71	)		(14,889	)		(2,553	)		(1	)		2			(14,235	)		(2,372	)
Dispositions		-			-			(59	)		(10	)		-			-			-			-			-			(59	)		(10	)
Economic Factors		-			-			(69	)		(12	)		-			-			-			-			-			(69	)		(12	)
Production		(67	)		(2	)		(519	)		(155	)		-			-			-			(67	)		(2	)		(519	)		(155	)
December 31, 2010		167			4			936			327			326			45,308			7,877			493			4			46,244			8,204
Developed		74			4			955			238			-			-			-			74			4			955			238
Undeveloped		93			-			(19	)		89			326			45,308			7,877			419			-			45,289			7,966
Total		167			4			936			327			326			45,308			7,877			493			4			46,244			8,204

* The above change categories correspond to standards set out in the Canadian Oil and Gas Evaluation Handbook. For reporting under NI 51-101, reserves additions under Infill Drilling, reserves additions under Infill Drilling, Improved Recovery and Extensions should be combined and reported as “Extensions and Improved Recovery”

CONSTANT PRICES AND COSTS - YEAR ENDED DECEMBER 31, 2009

Net Proved Developed and Proved Undeveloped Reserves
				Canada									United States						Total
	Light and			Natural Gas						Barrels of Oil			Light and				Barrels of Oil		Light and			Natural Gas						Barrels of Oil
	Medium Oil			Liquids			Natural Gas			Equivalent			Medium Oil		Natural Gas		Equivalent		Medium Oil			Liquids			Natural Gas			Equivalent
	(Mbbl)			(Mbbl)			(MMcf)			(Mboe)			(Mbbl)		(MMcf)		(Mboe)		(Mbbl)			(Mbbl)			(MMcf)			(Mboe)
December 31, 2008		232			9			1,586			505			-		-		-		232			9			1,586			505
Extensions & Discoveries		-			-			-			-			397		60,197		10,430		397			-			60,197			10,430
Infill Drilling		-			-			-			-			-		-		-		-			-			-			-
Technical Revisions		14			1			65			27			-		-		-		14			1			65			27
Sales		(82	)		(5	)		(383	)		(151	)		-		-		-		(82	)		(5	)		(383	)		(151	)
Production		(66	)		(1	)		(515	)		(154	)		-		-		-		(66	)		(1	)		(515	)		(154	)
December 31, 2009		98			4			753			227			397		60,197		10,430		495			4			60,950			10,657
Developed		70			4			743			197			-		-		-		70			4			743			197
Undeveloped		28			-			10			30			397		60,197		10,430		425			-			60,207			10,460
Total		98			4			753			227			397		60,197		10,430		495			4			60,950			10,657

(b)   Capitalized Costs

As at December 31,	2010			2009			2008
Canada
Proved oil and gas properties	$	21,769,993		$	17,535,742		$	22,132,700
Unproved oil and gas properties		8,370,857			9,047,242			8,996,407
Total capital costs		30,140,850			26,582,984			31,129,106
Accumulated depletion and depreciation		(9,888,992	)		(7,691,609	)		(3,635,777	)
Impairment		( 17,320,856	)		(16,016,752	)		-
Net capitalized costs	$	2,931,002		$	2,874,623		$	27,493,329
United States
Proved oil and gas properties	$	326,098		$	266,048		$	-
Unproved oil and gas properties		28,433,768			28,350,076			29,493,398
Total capital costs		28,759,866			28,616,124			29,493,398
Impairment		(500,866	)		(500,866	)		-
Net capitalized costs	$	28,259,000		$	28,115,258		$	29,493,398
Total
Proved oil and gas properties	$	22,096,091		$	17,801,790		$	22,132,700
Unproved oil and gas properties		36,804,625			37,397,318			38,489,805
Total capital costs		58,900,716			55,199,108			60,622,505
Accumulated depletion and depreciation		(9,888,992	)		(7,691,609	)		(3,635,777	)
Impairment		(17,821,722	)		(16,517,618	)		-
Net capitalized costs	$	31,190,002		$	30,989,881		$	56,986,727

(c)   Costs Incurred

For the years ended December 31	2010		2009		2008
Canada
Property acquisition costs (1)
Proved oil and gas properties	$	-	$	434,434	$	9,637
Unproved oil and gas properties		-		-		994,476
Exploration costs (2)		982,021		1,626,120		6,983,957
Development costs (3)		3,239,311		-		15,525,608
Capital Expenditures	$	4,221,332	$	2,060,554	$	23,513,678
United States
Property acquisition costs (1)
Proved oil and gas properties	$	14,640	$	32,122	$	-
Unproved oil and gas properties		220,859		161,770		3,938,032
Exploration costs (2)		5,205		19,186		139,541
Development costs (3)		553,953		313,577		-
Capital Expenditures	$	794,657	$	526,655	$	4,077,573
Total
Property acquisition costs (1)
Proved oil and gas properties	$	14,640	$	466,556	$	9,637
Unproved oil and gas properties		220,859		161,770		4,932,508
Exploration costs (2)		987,226		1,645,306		7,123,498
Development costs (3)		3,793,264		313,577		15,525,608
Capital Expenditures	$	5,015,989	$	2,587,209	$	27,591,251

(1)   Acquisition costs are not net of disposition of properties.

(2)   Geological and geophysical capital expenditures and drilling costs for exploration wells drilled.

(3)   Includes equipping and facilities capital expenditures.

(d)   Results of Operations of Producing Activities

For the years ended December 31	2010			2009			2008
Canada
Oil and gas sales, net of royalties and commodity contracts	$	6,841,782		$	6,216,519		$	4,616,900
Lease operating costs and capital taxes		(2,096,823	)		(2,503,571	)		(1,641,304	)
Transportation costs		(507,843	)		(411,432	)		(331,996	)
Depletion, depreciation and accretion		(5,242,376	)		(6,427,454	)		(3,685,397	)
Income taxes (1)		-			-			-
Results of operations	$	(1,005,260	)	$	(3,125,938	)	$	(1,041,797	)
United States
Oil and gas sales, net of royalties and commodity contracts	$	-		$	-		$	13,883
Lease operating costs and capital taxes		-			-			-
Transportation costs		-			-			-
Depletion, depreciation and accretion		(7,518	)		(9,099	)		(5,542	)
Income taxes (1)		-			-			-
Results of operations	$	(7,518	)	$	(9,099	)	$	8,341
Total
Oil and gas sales, net of royalties and commodity contracts	$	6,841,782		$	6,216,519		$	4,630,783
Lease operating costs and capital taxes		(2,096,823	)		(2,503,571	)		(1,641,304	)
Transportation costs		(507,843	)		(411,432	)		(331,996	)
Depletion, depreciation and accretion		(5,249,894	)		(6,436,553	)		(3,690,939	)
Income taxes (1)		-			-			-
Results of operations	$	(1,012,778	)	$	(3,135,037	)	$	(1,033,457	)

(1)   Dejour is currently not taxable.

(e)   Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

The standardized measure of discounted future net cash flows is based on estimates made by GLJ and Gustavson of net proved reserves.  Future cash inflows are computed based on the average of the first day constant prices in each of the 12 months for the year ended December 31, 2010and cost assumptions applied against annual future production from proved crude oil and natural gas reserves.  Future development and production costs are computed based on the average of the first day constant prices in each of the 12 months for the year ended December 31, 2010 and assume the continuation of existing economic conditions.  Future income taxes are calculated by applying statutory income tax rates.  The Company is currently not taxable.  The standardized measure of discounted future net cash flows is computed using a 10 percent discount factor.

The Company cautions users of this information that the discounted future net cash flows relating to proved oil and gas reserves are neither an indication of the fair market value of our oil and gas properties, nor of the future net cash flows expected to be generated from such properties.  The discounted future cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations.  The prescribed discount rate of 10 percent is arbitrary and may not appropriately reflect future interest rates.

Standardized Measure of Discounted Future Net Cash Flows

As at December 31, 2010
(in thousands of Canadian dollars)	Canada			USA			Total
Future revenue, net of royalties	$	15,777		$	228,318		$	244,095
Future production costs		(8,833	)		(44,116	)		(52,949	)
Future development costs		(3,172	)		(79,711	)		(82,883	)
Future income taxes (1)		-			(15,982	)		-
Future net cash flows		3,772			88,509			108,263
Less:  10% annual discount factor		(841	)		(62,561	)		(63,402	)
Standardized measure of discounted future net cash flow	$	2,931		$	25,948		$	28,879

As at December 31, 2009
(in thousands of Canadian dollars)	Canada			USA			Total
Future revenue, net of royalties	$	9,033		$	233,259		$	242,292
Future production costs		(5,364	)		(46,024	)		(51,388	)
Future development costs		(1,225	)		(79,276	)		(80,501	)
Future income taxes (1)		-			(16,328	)		(16,328	)
Future net cash flows		2,444			91,630			94,074
Less:  10% annual discount factor		(331	)		(77,359	)		(77,690	)
Standardized measure of discounted future net cash flow	$	2,113		$	14,272		$	16,385

Note (1):  In Canada, the company had significant loss carry forwards that can be used to offset oil and gas production income in the anticipated future.  Therefore, no future income tax expense is included.

(f)   Changes in Standardized Measure of Discounted Future Net Cash Flows

For the Year Ended December 31, 2010
(in thousands of Canadian dollars)	Canada			USA			Total
Present Value January 1, 2010	$	2,113		$	14,272		$	16,385
Sales and transfers of oil and gas produced, net of production costs		(4,169	)		-			(4,169	)
Net changes in prices, production costs and royalties		1,259			13,548			14,807
Extensions, discovery, less related costs		700			-			700
Development costs incurred during the period		3,179			-			3,179
Revisions of previous quantity estimates		1,565			(1,106	)		459
Accretion of discount		211			-			211
Net change in income taxes		-			-			-
Other		(1,927	)		(766	)		(2,693	)
Present Value December 31, 2010	$	2,931		$	25,948		$	28,879

For the Year Ended December 31, 2009
(in thousands of Canadian dollars)	Canada			USA		Total
Present Value January 1, 2009	$	6,078		$	-	$	6,078
Sales and transfers of oil and gas produced, net of production costs		(2,986	)		-		(2,986	)
Net changes in prices and production costs		827			-		827
Extensions, discovery, less related costs		-			14,272		14,272
Development costs incurred during the period		1,262			-		1,262
Revisions of previous quantity estimates		138			-		138
Accretion of discount		608			-		608
Net change in income taxes		-			-		-
Other		(3,814	)		-		(3,814	)
Present Value December 31, 2009	$	2,113		$	14,272	$	16,385