Canadian Spirit Resources Inc. Announces 2011 Financial Results and Filing of Annual Disclosure Documents

CALGARY, ALBERTA--(Marketwire - March 30, 2012) - Canadian Spirit Resources Inc. ("CSRI" or the "Corporation")(TSX VENTURE:SPI) (OTCBB:CSPUF) announces the release of its financial results for the three and twelve months ended December 31, 2011 and the filing of its 2011 annual audited Financial Statements and Management Discussion and Analysis and Annual Information Form.

The financial data presented herein is in accordance with International Financial Reporting Standards ("IFRS") and all amounts are presented in Canadian dollars, unless otherwise indicated. The 2011 annual audited financial statements include certain reconciliations between the previously used Canadian Generally Accepted Accounting Principles ("previous GAAP") and IFRS.

This news release summarizes information contained in the audited financial statements and MD&A for the twelve month period ended December 31, 2011 and should not be considered a substitute for reading these documents, which are available on SEDAR at www.sedar.com or the Corporation's website at www.csri.ca for full disclosure.

CSRI is a natural resources company focusing on the identification and development of opportunities in the unconventional gas sector of the energy industry.

OPERATIONAL HIGHLIGHTS

• Natural gas sales for 2011 total $1.7 million.
• 5 wells on production - 2011 exit production of 2 MMcf/d (net).
• A vertical well at 17-7-83-24W6 was drilled and completed. The well is designed to evaluate the quantity of natural gas liquids within the eastern lands of Farrell Creek.
• Williston Reservoir Water Pipeline Project completed.
• CSRI's share proved plus probable Montney reserves as at December 31, 2011 of 10.6 Bcf with a net present value of $6.1 million (10% discount rate).

FINANCIAL HIGHLIGHTS

• Non-brokered private placement of 2.46 million units at $0.75 per unit closed in December 2011, realizing gross proceeds of $1.84 million.
• Obtained a new $3.5 million revolving credit facility with ATB Corporate Financial Services.

FINANCIAL AND OPERATIONAL OVERVIEW
Selected Financial Information
For the years ended and as at December 31	2011			2010
Gross natural gas sales, before royalties	$	1,731,024		$	-
Operating netbacks, after royalty credits applied	$	745,879		$	-
Cash flow from operating activities	$	(930,790	)	$	(1,583,394	)
Net loss and comprehensive loss	$	(17,575,219	)	$	(1,466,747	)
Loss per share, basic & diluted	$	(0.24	)	$	(0.03	)
Net working capital	$	2,520,655		$	21,001,529
Total assets	$	62,927,463		$	89,689,299
Shareholders' capital	$	59,208,853		$	75,349,547
Common shares outstanding		76,238,661			74,598,861
Total capital expenditures	$	19,390,622		$	19,519,316

Revenue and Royalties

Total gross revenue from the sale of natural gas for the three and twelve months ended December 31, 2011 was $642,431 and $1,731,024, respectively. The five wells tied into the Farrell Creek Montney Gas Facility as at December 31, 3011 are all deep horizontal wells and as such, each of these producing wells qualifies for the British Columbia Government's Deep Royalty Credit Program. This Program will generate up to $2.5 million (gross) in royalty credits for each well and the royalty credits will be drawn down over time as the wells produce natural gas. At current rates of production, the Corporation should not have to remit any crown royalties to the British Columbia Government for the next two to three years.

Production
		Three months ended December 31,					Twelve months ended December 31,
		2011		2010			2011		2010
Total production of natural gas (Mcf)			215,300		-			537,220		-
Average production of natural gas
	Mcf/d		2,340		-			1,601		-
	boe/d		390		-			267		-
Average sales price of natural gas
	$/Mcf	$	2.99	$	-		$	3.30	$	-
	$/boe	$	17.91	$	-		$	19.82	$	-
BC Spectra Station 2 Benchmark price (1)
	$/Mcf	$	2.98	$	-		$	3.31	$	-

Note:

(1) Source: NGX Natural Gas Exchange website (converted from $/GJ)

In January 2011, the Farrell Creek Montney Gas Plant commenced operations with natural gas currently being sold on a spot basis at BC Station 2 on the Spectra Energy pipeline system. For the three and twelve months ended Decemer 31, 2011, production averaged 2,340 Mcf/d (390 boe/d) and 1,601 Mcf/d (267 boe/d), respectively with the Corporation realizing an average price of $2.99 per Mcf ($17.91 per boe) and $3.30 per Mcf ($19.82 per boe), respectively.

Operating Netbacks
For the three months ended December 31, 2011			$		%			$/Mcf			$/boe
Natural gas sales		$	642,431				$	2.99		$	17.91
Royalties			(56,300	)	8.8	%		(0.26	)		(1.57	)
	Net revenue		586,131					2.73			16.34
Royalty credits applied			56,300					0.26			1.57
Operating costs			(432,345	)				(2.01	)		(12.05	)
	Operating netbacks	$	210,086				$	0.98		$	5.86
For the twelve months ended December 31, 2011			$			%		$/Mcf			$/boe
Natural gas sales		$	1,731,024				$	3.30		$	19.82
Royalties			(155,854	)	9.0	%		(0.29	)		(1.74	)
	Net revenue		1,575,170					3.01			18.08
Royalty credits applied			151,341					0.28			1.69
Operating costs			(980,632	)				(1.82	)		(10.93	)
	Operating netbacks	$	745,879				$	1.47		$	8.84

After royalties, operating costs and transportation, operating netbacks were $0.98 per Mcf ($5.86 per boe) and $1.47 per Mcf ($8.84 per boe) for the three and twelve months ended December 31, 2011 respectively.

During the three and twelve months ended December 31, 2011, the Corporation applied $56,300 and $151,341, respectively, of royalty credits against crown royalties that would otherwise have been payable. The royalty credits applied are accounted for as an offset against the capital costs accumulated within Property, Plant and Equipment. The difference between royalty expense and royalty credits applied for the twelve months ended December 31, 2011 of $4,513 represent actual crown royalties paid in relation to the sale of natural gas liquids.

Impairment

The Corporation performed impairment tests as at January 1, 2010 (date of transition to IFRS), as at January 28, 2011 (date of the Corporation's first natural gas production) and as at December 31, 2011 to assess the recoverable value of E&E assets within the Corporation's combined Farrell Creek Gething Formation project and Farrell Creek Montney Formation project E&E CGU's. The estimates of fair value less costs to sell were determined in part using prevailing land tender prices around those dates. Based on the tender prices and other factors, the estimated recoverable amount of E&E assets was greater than the carrying value of the Corporation's combined Farrell Creek Gething Formation project and Farrell Creek Montney Formation project E&E CGU's, and as such there was no impairment.

However, for the year ended December 31, 2011 CSRI recognized an impairment of $14.5 million (2010: $Nil) relating to developed and producing natural gas assets in the Corporation's Farrell Creek Montney Formation project CGU within property, plant and equipment. The impairment resulted primarily from the decline in forecasted natural gas prices.

The impairment is based on the difference between the net book value of the developed and producing natural gas assets within property, plant and equipment and their recoverable amount. The recoverable amount is calculated using fair value less costs to sell based on 9% discounted after-income tax future net cash flows for proved plus probable reserves using forecasted natural gas prices, operating costs and future costs to develop.

Reserves

The following table summarizes the Corporation's reserves and net present value ("NPV") of reserves as at December 31, 2011:

				Barrels of Oil		NPV Discounted
		Natural Gas(1)		Equivalent(5)		At 10%(6)
		Gross (2)	Net(3)	Gross (2)	Net(3)
		(MMcf)	(MMcf)	(Mboe)	(Mboe)	(Thousands)
PROVED(7)
	Developed Producing	2,471	2,435	412	406	$	4,024
	Total Proved	2,471	2,435	412	406	$	4,024
PROBABLE(8)		8,149	7,605	1,358	1,267	$	2,072
TOTAL PROVED PLUS PROBABLE(4)		10,620	10,040	1,770	1,673	$	6,096

Notes:

(1) Estimates of Reserves of natural gas include associated and non-associated gas.

(2) "Gross Reserves" are CSRI's working interest share of the remaining reserves, before deduction of royalties.

(3) "Net Reserves" are CSRI's working interest share of remaining reserves less all Crown royalties.

(4) May not add due to rounding.

(5) Boe's have been calculated using a conversion ratio of 6 Mcf of natural gas per barrel of oil energy equivalent.

(6) Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

(7) Proved Resources are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

(8) Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

General and Administrative Expenses
		Three months ended December 31,						Twelve months ended December 31,
		2011			2010			2011			2010
Consulting fees	$	7,614		$	35,201		$	173,038		$	125,326
Salaries and benefits		370,327			348,017			1,262,786			1,180,732
Other general and administrative		162,093			300,380			877,448			836,150
		540,034			683,598			2,313,272			2,142,208
Capitalized and other costs		(115,145	)		(117,285	)		(474,649	)		(471,398	)
		424,889			566,313			1,838,623			1,670,810
Share-based compensation		79,558			124,271			649,516			773,459
Capitalized portion of share-based compensation		(17,211	)		(31,488	)		(147,487	)		(210,224	)
		62,347			92,783			502,029			563,235
	$	487,236		$	659,096		$	2,340,652		$	2,234,045

In 2011 the Corporation continued consulting contracts with an investment advisor, a land consultant, a computer network maintenance company and an external IFRS consulting firm. During the twelve months ended December 31, 2011, the Corporation also entered into consulting arrangements with a staffing recruitment firm and an executive compensation firm, resulting in an increase of $47,712 or 38.1% in consulting fees, before capitalization compared to the year ended December 31, 2010. Consulting fees for the fourth quarter 2010 were higher compared to the fourth quarter 2011 due to additional IFRS consulting services.

Salaries and benefits, before capitalization, for the twelve months ended December 31, 2011 increased by $82,054 or 6.9% compared with the year ended December 31, 2010 due to general annual salary increases and the hiring of an additional employee in March 2011, but offset by efficiencies gained in the Corporation's group health benefits plan.

The increase in other general and administrative expenses for the twelve months ended December 31, 2011 was mainly attributable to increased professional fees, but offset by a decrease in office premises expenses. Professional fees are comprised of legal counsel fees for corporate and joint venture matters, audit related fees for the three 2011 quarterly interim financial statement reviews, independent reservoir engineering consultants fees for the Corporation's initial Reserve Report as at March 31, 2011 as well as fee accruals for the 2011 annual audit and reserve report, neither of which were accrued until the fourth quarter for the 2010 fiscal year. Office premises expenses decreased by 41% and 20%, respectively, from the three and twelve months ended December 31, 2010 to the three and twelve months ended December 31, 2011 due to the signing of a new lease agreement effective June 2011 for a two year main lease at $12.00 per square foot compared to the prior rate of $28.00 per square foot.

The Corporation capitalizes, within both Exploration and Evaluation assets and Property, Plant and Equipment, certain salary and benefit costs associated with staff directly involved in exploration and development activities. For the year ended December 31, 2011, the Corporation capitalized a total of $474,049 (2010: $468,998) of general and administration expenses, including salaries and benefits, directly related to exploration and development activities. Other costs capitalized during the twelve months ended December 31, 2011 of $600 (2010: $2,400) relate to consulting fees incurred as equity instruments issue costs, and are recorded by the Corporation as a reduction of shareholders' capital.

Due to the reduced levels of stock options granted as well as a decrease in the market price of the Corporation's shares, share-based compensation, before capitalization, decreased by $123,943 or 16.0% for the year ended December 31, 2011, from the comparative prior period. The closing price of the Corporations shares on the Exchange on December 31, 2011 was $0.55 per share. For the twelve months ended December 31, 2011 the Corporation capitalized $147,487 (2010: $210,224) of share- based compensation expense for those employees of the Corporation directly involved in exploration and development activities.

Capital Expenditures, Liquidity and Capital Resources

The Corporation's net capital expenditures for the three and twelve months ended December 31, 2011 and 2010 are detailed in the following table:

		Three months ended December 31,						Twelve months ended December 31,
			2011			2010		2011			2010
Lease acquisitions and retentions		$	26,593		$	238,227	$	1,613,659		$	4,269,875
Geological and geophysical			11,030			1,817		11,030			4,929
Net expenditure on drilling, completion and facilities costs			1,510,129			9,965,635		17,134,251			14,557,804
Capitalized overhead			132,356			148,173		621,536			679,222
	Total natural gas expenditures		1,680,108			10,353,852		19,380,476			19,511,830
Computer and office equipment, furniture and fixtures			4,990			-		10,146			7,486
	Total capital expenditures		1,685,098			10,353,852		19,390,622			19,519,316
Royalty credits earned			(1,632,483	)		-		(3,655,665	)		-
	Net capital expenditures	$	52,615		$	10,353,852	$	15,734,957		$	19,519,316

For the year ended December 31, 2011, gross capital expenditures, including land acquisitions but before British Columbia government incentive Summer Drilling and Deep Royalty Credits earned of $3.7 million, totaled $19.4 million (2010: $19.5 million), compared to a budgeted capital expenditure of $16.2 million (2010: $19.7 million). The capital expenditures in excess of budget for the twelve months ended December 31, 2011 were mainly as a result of unexpected cost overruns from the Corporation's joint venture partner, Canbriam, relating to the completion of the c-45-I and c-B18-I wells, the drilling of the 12-07 well, and the construction of the Williston Reservoir Water Pipeline Project.

At December 31, 2011, the Corporation had a net working capital balance of $2.5 million consisting of cash in the amount of $4.1 million, accounts receivable and prepaids of $0.1 million and the current portion of unapplied royalty credits of $0.4 million, offset by accounts payable and other accrued liabilities of $2.1 million. The accounts payable and other accrued liabilities balance at December 31, 2011 relates primarily to drilling and completion activity at c-45-I, c-B18-I and 12-07 in the Montney Project at Farrell Creek as well as the costs related to the Williston Reservoir Water Pipeline Project in conjunction with the Corporation's joint venture partner, Canbriam.

The Corporation's capital budget is reviewed and approved by the Board of Directors on a quarterly basis. The Corporation's Board of Directors has approved a total capital expenditure budget for 2012 of $2.0 million (net), including an estimated $0.5 million for capitalized overhead. CSRI has budgeted for $0.2 million (net) of capital expenditures for the first quarter 2012. Any additional capital required to complete CSRI's share of the Montney program for 2012 of $2.0 million (net) is expected to be raised either via the capital markets, generated internally by cash flow from operating activities, or sourced from borrowings against the Corporation's line of credit.

Subsequent to the year-end, the Corporation established a revolving demand bank credit facility for $3.5 million. The credit facility is fully revolving with no set date of maturity, bears interest at prime rate plus an applicable margin, and is secured by a General Security Agreement conveying a first floating charge over all the Corporation's real property and fixed assets as well as a first fixed charge on all the Corporation's property interests. The credit facility is subject to standard quarterly and annual reporting requirements as well as usual and customary covenants. To date, no draws have been made from the credit facility.

Cash administration expenses (general and administrative expenses excluding share-based compensation) for 2012 are expected to total $1.9 million (2011: $2.3 million), before capitalization of exploration and development related overhead. The Corporation has budgeted for operating netbacks from the Farrell Creek Montney operations of $0.7 million during 2012, which may not be fully achieved due to continued weak natural gas prices.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

In February 2008, the Accounting Standards Board of the Canadian Institute of Chartered Accountants confirmed that IFRS would replace previous GAAP commencing in 2011 for profit-oriented Canadian publicly accountable enterprises effective January 1, 2011. As such, the Corporation has reported its 2011 results and 2010 comparative information in accordance with IFRS. The adoption of IFRS has not had a material impact on the Corporation's operations.

ADDITIONAL INFORMATION

The Corporation's financial statements, management's discussion and analysis of operations and financial condition and annual information form ("AIF") have been filed on the System for Electronic Document Analysis and Retrieval ("SEDAR") and can be viewed at www.sedar.com or through the Corporation's website at www.csri.ca.

On behalf of the Board of Directors,

CANADIAN SPIRIT RESOURCES INC.

Phillip Geiger, President and Chief Operating Officer

The corporate information contained in this news release may contain forward-looking forecast information. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonably accurate by CSRI at the time of preparation, may prove to be incorrect. The actual results achieved during the forecast period will vary from the information provided herein and the variations may be material. Consequently there is no representation by CSRI that actual results achieved during the forecast period will be the same in whole or in part as those forecast.