10-K/A 1 eh1100525_form10ka.htm AMENDMENT NO. 1 eh1100525_form10ka.htm


U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K/A
(Amendment No. 1)
(Mark One)

 
þ
ANNUAL REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED APRIL 30, 2011.


OR


 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES   EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD OF                     TO                    

Commission File Number: 001-32994

OILSANDS QUEST INC.
(Exact Name of Registrant as Specified in its charter)

Colorado
   
98-0461154
State or other jurisdiction of incorporation or organization
   
(I.R.S. Employer Identification No.)

800, 326 11th AVENUE SW, CALGARY, ALBERTA, CANADA T2R 0C5
(Address of principal executive offices, including zip code)

Issuer’s telephone number: (403) 263-1623

Securities registered under Section 12(b) of the Act:
 
Title of each class
   
Name of each exchange on which is registered
Common Stock, $.001 Par Value
   
NYSE Amex

 
Securities registered under Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known, seasoned issuer, as defined in Rule 405 of the Securities Act.

 
Yes o
No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

 
Yes o
No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 
 
Yes þ
No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
 
 
Yes o
No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (s 229.405 or this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

 
Yes þ
No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer: o
Accelerated filer: þ
Non-accelerated filer: o
Smaller reporting company: o
   
(Do not check if a smaller reporting company)
 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The aggregate market value of the common stock held by non-affiliates of the Registrant as of October 31, 2010 was approximately $138,270,741 based upon the closing sale price of the Registrant’s Common Stock on such date.

As of June 30, 2011 there were 348,495,556 shares of common stock issued and outstanding.

Certain portions of the Registrant's definitive proxy statement to be filed with the Securities and Exchange Commission within 120 days after the fiscal year end of April 30, 2011 are incorporated by reference into Part III of this Annual Report on Form 10-K.

 
 
 
 

 

EXPLANATORY NOTE
 
 
This Amendment No. 1 to our Annual Report on Form 10-K for the fiscal year ended April 30, 2011 is filed solely to correct the Consent of KPMG LLP, Independent Registered Public Accounting Firm filed as Exhibit 23.2 to the Form 10-K,  to correct a clerical error in the footnote to Exhibit 10.22 on the Exhibit Index, and to remove "Common Stock Purchase Warrants" from the list of securities registered under Section 12(b) of the Act on the cover page of the Form 10-K which had been inadvertently included. The corrected Consent is filed herewith as Exhibit 23.2 and the Exhibit Index to Amendment No. 1 has been updated accordingly.
 
This Form 10-K/A is limited in scope to the foregoing, and should be read in conjunction with the Form 10-K previously filed and our other filings with the SEC. Except as described above, we have not modified or updated other disclosures or information presented in the original Form 10-K.

 
 
 

 
 

   
Page
Forward-Looking Statements
 
Currency
   
   
Item 1.
  2
Item 1A.
  10
Item 2.
  15
Item 3.
  18
Item 4.
(REMOVED AND RESERVED)
  19
   
Item 5.
  19
Item 6.
  21
Item 7.
  21
Item 7A.
  25
Item 8.
  26
Item 9.
  26
Item 9A.
  26
Item 9B.
  26
   
Item 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
  26
Item 11.
  26
Item 12.
  26
Item 13.
  27
Item 14.
  27
   
Item 15.
 27

 
 
1

 
 
Cautionary Statement about Forward-Looking Statements

This Annual Report on Form 10-K includes certain statements that may be deemed to be “forward-looking statements.” All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that our management expects, believes or anticipates will or may occur in the future are forward-looking statements. Such forward-looking statements include discussion of such matters as:

 
the amount and nature of future capital, development and exploration expenditures;

 
the timing of exploration activities;

 
potential reservoir recovery optimization processes; and

 
business strategies and development of our business plan and drilling programs.

Forward-looking statements are statements other than relating to historical fact and are frequently characterized by words such as “plan”, “expect”, “project”, “intend”, “believe”, “anticipate”, “estimate”, “potential”, “prospective” and other similar words or statements that certain events or conditions “may” “will” or “could” occur. Forward-looking statements such as references to Oilsands Quest’s drilling program, geophysical programs, reservoir field testing and analysis program, preliminary engineering and economic assessment program for a first commercial project, and the timing of such programs are based on the opinions and estimates of management and the Company’s independent evaluators at the date the statements are made, and are subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those anticipated in the forward-looking statements, which include but are not limited to risks inherent in the oil sands industry, regulatory and economic risks, land tenure risks, lack of infrastructure in the region in which the company’s resources are located and risks associated with the company’s ability to implement its business plan.  The Company undertakes no obligation to update forward-looking information if circumstances or management’s estimates or opinions should change, except as required by law. The reader is cautioned not to place undue reliance on forward-looking statements.

Currency

Unless otherwise specified, all dollar amounts are expressed in United States dollars. All future payments in Canadian dollars have been converted to United States dollars using an exchange rate of $1.00 U.S. = $1.054185 CDN, which was the April 30, 2011 exchange rate.

PART I

When we use the terms “Oilsands Quest Inc.”, the “Company,” “we,” “us,” “our,” or “OQI,” we are referring to Oilsands Quest Inc. and its subsidiaries, unless the context otherwise requires. We have included technical terms important to an understanding of our business under “Glossary of Common Terms” at the end of “Item 1. Description of Business”. Throughout this document we make statements that are classified as “forward-looking.” Please refer to the “Cautionary Statement about Forward-Looking Statements” section at the front of this document for an explanation of these types of assertions.

Item 1.  DESCRIPTION OF BUSINESS

Background and Corporate Structure

We are a Colorado corporation formed on April 3, 1998 as Uranium Power Corporation. On November 2, 2004 we changed our name to CanWest Petroleum Corporation. On October 31, 2006 we changed our name to Oilsands Quest Inc. Our principal executive office is located at Suite 800, 326 – 11th Avenue S.W., Calgary, Alberta, Canada T2R 0C5. Our website is www.oilsandsquest.com.

The Company operates through its subsidiary corporations. Our primary operating subsidiary is Oilsands Quest Sask Inc. (“OQI Sask”), an Alberta corporation. OQI Sask was established as an operating subsidiary of the Company primarily to explore for and develop oil sands deposits in the provinces of Saskatchewan and Alberta. We currently own 100% of the issued and outstanding voting common shares of OQI Sask following the acquisition of the non-controlling (minority) interest of OQI Sask on August 14, 2006.
 
In addition to OQI Sask, we also have the following wholly-owned subsidiaries:

 
Township Petroleum Corporation (“Township”), an Alberta corporation. Township owns an oil sands lease in the Province of Alberta acquired in 2005, (referred to as the Eagles Nest), and is currently developing plans for exploring the oil sands potential on the lease.

 
Western Petrochemicals Corp. (“WPC”), an Alberta corporation. WPC formerly owned certain rights relating to exploration for oil shale, referred to as the Pasquia Hills Oil Shale, and is currently inactive.

 
Stripper Energy Services Inc. (“Stripper”), acquired in 2007 and currently a wholly- owned subsidiary of OQI Sask.

 
1291329 Alberta Ltd., incorporated in 2007 to own assets related to camp facilities and equipment.

 
Oilsands Quest Technology Inc., incorporated in 2007 to assess technologies related to bitumen and shale oil extraction and to ensure any proprietary information created from the development of our prospects can be commercially exploited.

 
1259882 Alberta Ltd. incorporated on August 4, 2006.  The only activity conducted by this subsidiary to date is to have an over-riding call right to acquire the Exchangeable Shares (as defined below) in consideration of it delivering to the shareholder the number of common shares in the Company that a shareholder would otherwise have been entitled to upon a redemption or retraction of the Exchangeable Shares.
 
Strategy

Our strategy is to focus on business opportunities in the oil sands sector with the objective of maximizing shareholder value on a per share basis.  We will execute our strategy by:

Exploring and delineating resources on our lands. Our operating teams have conducted extensive exploration and development programs, consisting of drilling 466 wells, conducting 2,136 kilometres of 2-D and 3-D seismic surveys, and other exploration activities resulting in the discovery of the Axe Lake, Raven Ridge and Wallace Creek reservoirs and the identification of other oil sands prospects. We manage and operate all of our activities.

Exploiting the oil sands resources identified. We are focused on continuing the development of our reservoirs, including reservoir and overburden testing programs at Axe Lake.  Our development strategy includes the use of commercially reliable recovery methods to develop our projects in a timely and responsible manner.

General Development of the Business

Acquisition of Oil Sands Exploration Rights

Oil sands permits and licenses in Saskatchewan

On September 24, 2004 we acquired all of the issued and outstanding shares of 808099 Alberta Ltd., which was previously inactive, and on November 3, 2004 this company changed its name to Oilsands Quest Inc. On November 1, 2006, this entity changed its name to Oilsands Quest Sask Inc. Following external issuances of equity by OQI Sask, at July 31, 2006 we owned 64.08% of the shares of common stock of OQI Sask. On August 14, 2006, we closed a reorganization agreement with OQI Sask, which was executed on June 9, 2006, whereby we acquired the non-controlling (minority) interest in OQI Sask, increasing from a 64.08% ownership interest to a 100% voting interest (the “Reorganization Agreement” or the “Reorganization”). In connection with the Reorganization Agreement, we also entered into a Voting and Exchange Trust Agreement with OQI Sask and Computershare Trust Company of Canada (“CTC”), and a Support Agreement with OQI Sask. Collectively, these agreements are referred to as the “Acquisition Agreements”.
 
 
2

 
 
In accordance with the Acquisition Agreements, all OQI Sask common shares other than those held by us were exchanged for a new class of OQI Sask shares called Exchangeable Shares pursuant to a ratio of one OQI Sask common share to 8.23 Exchangeable Shares. The Exchangeable Shares are exchangeable at any time on a one-for-one basis, at the option of the holder, for shares of our common stock. An Exchangeable Share provides a holder with economic terms and voting rights which are, as nearly as practicable, equivalent to those of a share of our common stock. Holders of Exchangeable Shares have registration rights with respect to the resale of our common stock to be received upon exchanging the Exchangeable Shares into our shares. The holders of the Exchangeable Shares will receive up to an aggregate of 76,504,304 shares of our common stock at each holder’s election. The Exchangeable Shares are represented for voting purposes in the aggregate by one share of our Series B Preferred Stock (the “Preferred Share”), which Preferred Share is held by CTC. CTC will in turn vote the one Preferred Share as indicated by the individual holders of Exchangeable Shares. The one Preferred Share represents a number of votes equal to the total outstanding Exchangeable Shares on the applicable record date for the vote submitted to our shareholders. At April 30, 2011, 46,346,867 shares of common stock had been issued on exchange of Exchangeable Shares, 3,237,131 shares have expired and 26,920,305 shares of common stock remain to be issued on future exchanges of Exchangeable Shares.

On September 29, 2004, OQI Sask acquired a 49% interest in certain oil shale exploration permits that covered approximately 2,000 square miles (1,400,000 acres) in northwestern Saskatchewan along the Alberta border. The 49% interest in the permits was acquired for $769,125, plus 50,000 shares of our common stock and a 2.5% gross overriding royalty (the “2.5% GORR”). In order to finance the purchase of the 49% interest, OQI Sask borrowed funds from the Company in the form of a convertible debenture. On November 18, 2005, the principal and accrued interest on the debenture was converted into 788,769 shares of common stock of OQI Sask.

We entered into an agreement dated November 8, 2004, as amended (the “WCM Agreement”), to acquire all of the shares of Western Canadian Mint Inc. (“WCM”), a company that owned all of the shares of American Oilsands Company Inc., which owned the remaining 51% working interest in the permits, subject to a $0.07 per barrel royalty which could be bought at any time by paying $7,000,000 and a $0.04 per barrel royalty held by various arm’s-length parties. Prior to completing this acquisition, we assigned all of our rights and obligations to OQI Sask pursuant to a letter agreement dated November 12, 2004 and an assignment dated April 27, 2005. As a result, on May 3, 2005, pursuant to the terms of the WCM Agreement, OQI Sask acquired all of the outstanding shares of WCM. The combined consideration paid by us and OQI Sask was $1,202,131, 2,000,000 shares of our common stock and the assumption of the $0.07 per barrel royalty which could be bought at any time by paying $7,000,000 and a $0.04 per barrel royalty held by various arm’s-length parties. WCM was then merged with OQI Sask.

As a result of these transactions, OQI Sask held an undivided 100% interest, subject to the above noted royalties, in Saskatchewan Oil Shale Exploration Permit Nos. PS00205, PS00206, PS00207, PS00208, PS00209, PS00210, PS00211, PS00212, PS00213, PS00214, PS00215, PS00216 and PS00217, granted originally on June 1, 2004. The permits were granted by the Province of Saskatchewan in 2004 under the Oil Shale Regulations, 1964 as amended, revised or substituted from time to time, for a term of five years. The permits provide for the right to explore and work the permit lands but not to remove, produce or recover, except for test purposes, oil products until a lease pursuant to these regulations has been granted. The term of the permits may be extended for up to three, one-year extensions subject to regulatory approvals, as required. On May 27, 2011, the Company received the third and final one year extension pursuant to the regulations.

As of April 30, 2011, the Company held 406,274 acres consisting of Saskatchewan Oil Shale Exploration Permit Nos. PS00205, PS00206, PS00208, PS00210 and PS00212.  On May 31, 2011, OQI Sask relinquished three of the permits, PS00205, PS00206 and PS00212, representing 245,642 acres.

The permits, when granted, were subject to annual rental payments and commitments to certain levels of expenditures annually pursuant to the terms of the permits and government regulations. The annual rentals were payable in advance as to $0.02 ($0.02 CDN) per acre for the first year and escalating to $0.11 ($0.10 CDN) per acre in the fifth year. On May 7, 2007, the Saskatchewan government updated the Oil Shale Regulations, 1964 requiring an increase to annual rentals of $0.11 ($0.10 CDN) per acre for the remaining term of the permits. The required exploration expenditures to hold the permits were also increased to $0.85 ($0.81 CDN) per acre for each of the remaining years of the permits and $1.28 ($1.21 CDN) per acre for each year that the permits are extended. The Company has paid all required annual rentals and complied with the annual exploration expenditure requirements.

On August 13, 2007, the Company acquired five oil sands licenses totaling 109,920 acres granted under the Petroleum and Natural Gas Regulations, 1969 (Saskatchewan), as amended, revised or substituted from time to time, for a term of five years for an aggregate cost of $2,140,233 ($2,249,089 CDN). The licenses provide for the exclusive right to search for oil sands on the lands granted and to win, recover, extract, carry off, dispose of and sell the oil sands products found on the licensed lands. The oil sands licenses provide the opportunity to convert up to 100% of the licenses to a production lease on the basis of one section of land for every well that intersects an oil sands zone. Licenses require annual rental payments of $0.75 ($0.71 CDN) per acre. The Company has paid all required annual rental payments for the licenses granted.  The Company expects to relinquish these licenses on August 12, 2011.

Gross Overriding Royalties on original Saskatchewan oil sands permit lands

As noted above, as part of the acquisition of the Saskatchewan permits, OQI Sask assumed the 2.5% GORR and a $0.04 per barrel royalty held by various arm’s-length parties.  On August 15, 2006, the Company closed a transaction with the shareholders of Stripper Energy Services Inc. (“Stripper”), a then non-related inactive entity. The Company purchased all of the issued and outstanding shares of Stripper’s common stock for a total purchase price of $17,948,722 ($20,000,000 CDN), including the original option payment of $1,250,000 CDN. Stripper’s sole asset is the 2.5% GORR royalty on the permits. As a result of the transaction, the 2.5% GORR is now held by Stripper, a wholly-owned subsidiary of OQI Sask. 

On September 21, 2007, in conjunction with the acquisition of the interests of an external joint venture partner to the Triple 7 Joint Venture described below, the Company acquired the $0.07 per barrel royalty obligation for consideration of $99,980 ($100,000 CDN) cash plus the issuance of 500,000 shares of its common stock valued at $2,195,000 based on the September 20, 2007 closing market price of the shares.

The Saskatchewan permits are now only subject to $0.04 per barrel royalty.

Oil sands permits and lease in Alberta

- Raven Ridge

During the year ended April 30, 2007, the Company acquired four oil sands permits totaling 67,053 acres in a public offering of Crown Oil Sands Rights for an aggregate cost of $22,221,968 ($25,651,985 CDN). The permits were granted by the Province of Alberta under the terms of the Mines and Minerals Act, Alberta. The permits provide the opportunity to convert up to 100% of the permits to a production lease following the completion of specified work requirements. Permits are granted for a five-year primary term and require annual rental payments of $1.50 ($1.42 CDN) per acre.  The Company expects to relinquish Permit No. 7006080098 in August of 2011.  For a description of the location of this permit, see Part 1, Item 2 Properties and Statement of Oil and Gas Information.

Raven Ridge is located in Alberta directly west of our Axe Lake oil sands permits in Saskatchewan.

- Wallace Creek

On January 23, 2008, the Company acquired two oil sands permits totaling 45,546 acres in a public offering of Crown Oil Sands Rights (permits were officially granted on January 24, 2008). The total consideration paid for these permits was $9,732,500 ($10,010,880 CDN). The permits were granted by the Province of Alberta under the terms of the Mines and Minerals Act, Alberta. The permits provide the opportunity to convert up to 100% of the permits to a production lease following the completion of specified work requirements. Permits are granted for a five-year primary term and require annual rental payments of $1.50 ($1.42 CDN) per acre. On June 27, 2011, the Company received approval from Alberta Energy to extend the Wallace Creek permits for an additional 67 days to March 31, 2013.

Wallace Creek is located in Alberta directly west of our Axe Lake oil sands permits in Saskatchewan.

- Eagles Nest

On August 25, 2005, Township acquired Oil Sands Lease No. 7405080355 located in northern Alberta for $727,187 at an Alberta Crown land sale. This lease comprises an area of approximately 22,773 acres and is located in the Athabasca oil sands region in Alberta in Township 101, Range 13 West of the fourth Meridian. The lease provides for the right to drill for, win, work and recover and the right to remove bitumen resources from the lease for a term of 15 years, subject to the Mines and Minerals Act, Alberta.

Prior to bidding on Eagles Nest, on June 1, 2005, Township entered into an agreement with three third parties (collectively the “Triple 7 Joint Venture”) to post, acquire, develop and produce oil sands deposits located in the Athabasca Region of Alberta, Canada (the “Triple 7 Joint Venture Agreement”). As a result of this agreement, Township acquired one lease consisting of approximately 22,773 acres (the “Eagles Nest Oil Sands Lease”) at a cost of $727,187. Pursuant to the terms of this agreement we issued the Triple 7 Joint Venture 114,015 shares of our common stock with a fair value of $127,432. Township also agreed to pay the Triple 7 Joint Venture partners, as ongoing fees, $125,628 ($150,000 CDN) in cash or in shares of our common stock (at the discretion of the Company) on the first and second anniversary dates of the agreement. On the third anniversary date and each subsequent anniversary date of the agreement Township agreed to pay the Triple 7 Joint Venture $376,884 ($450,000 CDN) until such time as the lease is surrendered or a commercial project has been identified.  On September 21, 2007, in conjunction with the acquisition of the royalty described above, the Company acquired all of the rights of one of the three external joint venture partners for consideration of $49,939 ($50,000 CDN) plus the issuance of 250,000 shares of the Company’s common stock valued at $1,097,500 based on the September 20, 2007 closing market price of the shares.
 
 
3

 
 
On June 17, 2008, we acquired the rights of the remaining external joint venture partners for aggregate consideration of $1,632,000 CDN and 640,000 shares of the Company’s common stock valued at $3,718,400 based on the June 17, 2008 closing market price of the shares. The Company’s obligations under the Triple 7 Joint Venture Agreement have therefore been eliminated.
 
To finance the acquisition of Eagles Nest in 2005 the Company issued convertible debentures pursuant to which Township also granted royalties of $0.0061 ($0.0058 CDN), net after a buy back, on each barrel of crude bitumen produced, saved and sold from the project. The convertible debentures have all been converted to common stock.

Pursuant to the terms of the lease, Township’s annual lease rentals are $34,004 ($32,256 CDN). OQI Sask has paid all required annual rentals and the lease is in good standing.

Acquisition of Oil Shale Rights in Saskatchewan

- Pasquia Hills Oil Shale

On April 21, 2005, we acquired a 97.53% interest in Western Petrochemicals Corporation (“WPC”) through the issuance of 10,728,124 shares of our common stock and then in April 2006 increased our ownership to 100% by issuing 271,865 shares of our common stock to the remaining WPC shareholders. WPC held a 100% interest in exploration permits covering an area of approximately 337,775 acres granted under the provisions of the Oil Shale Regulations, 1964, as amended or revised or substituted from time to time by the Province of Saskatchewan. The exploration permits were scheduled to expire in 2006, and during the year ended April 30, 2007, all of the original Pasquia Hills exploration permits held by WPC expired and were returned to the Saskatchewan government.

We reacquired nine exploration permits on the original Pasquia Hills oil shale prospect area from the Province of Saskatchewan in September and October 2006. In accordance with the terms of the new permits and following an initial assessment, we relinquished 30% of the total acreage of the granted permits within 90 days of the grant. As of April 30, 2011 we held Oil Shale Permit Nos. PS00222, PS00223, PS00224, PS00225, PS00226, PS00237 and PS00238 granted under the Oil Shale Regulations, 1964, as amended or revised or substituted from time to time for five-year terms from the date of grants. The term of the permits may be extended for up to three one-year extensions subject to regulatory approvals, as required. The permits total 405,961 acres and are located near Hudson Bay, Saskatchewan. The permits provide for the right to explore, mine, quarry and work the permit lands, but not to produce or recover oil shale except for test purposes until a lease has been granted.

The annual rental payable in advance was $0.05 ($0.05 CDN) per acre for the first year, and on May 7, 2007 the Saskatchewan government updated the regulations requiring annual rentals of $0.11 ($0.10 CDN) per acre for the remaining term of the permit. The required exploration expenditures to hold the permits were also increased to $0.42 ($0.40 CDN) per acre for the second year of the permits, $0.85 ($0.81 CDN) per acre for the last three years of the permits and $1.28 ($1.21 CDN) per acre for each year that the permit is extended, as required.

On August 13, 2007, we acquired one additional oil shale exploration permit granted under the Petroleum and Natural Gas Regulations, 1969 (Saskatchewan) as amended, revised or substituted from time to time for a term of five years totaling 83,769 acres in the same area near Hudson Bay, Saskatchewan. This permit, together with the nine exploration permits acquired in September and October 2006 as described above, are collectively referred to as Pasquia Hills Oil Shale. The permit provides for the right, license, privilege and authority to explore for oil shale within the permit lands. The term of the permit may be extended for up to three one-year extensions subject to regulatory approvals, if required. This oil shale permit was acquired under a land sale work commitment bid for the first two years of the permit. The Company bid a total work commitment of $298,110 ($301,568 CDN) to be incurred during the first two years of the permit and the permit requires a further work commitment of $0.85 ($0.81 CDN) per acre for the last three years and $1.28 ($1.21 CDN) for each extension year plus annual rental payments of $0.11 ($0.10 CDN) per acre.
 
Activities to Date

Oil sands permits and licenses

Exploration of our Saskatchewan oil sands permits commenced in the winter of 2005/2006. An initial exploration drilling program consisting of 24 resource delineation wells was completed by April 2006. In August 2006, the Company received the independent geological consultants’ assessment of in-place volumes of bitumen in the area covered by the winter 2005/2006 exploration program. The assessment, prepared by Norwest Corporation of Calgary, was made in accordance with the Canadian Oil and Gas Evaluation Handbook (“COGEH”), which is a primary reference for reporting resources under Canadian Securities Administrators National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).  The End of Season Report for the winter 2005/2006 exploration drilling program documenting conformance with the original plans and summarizing the environmental effects of the program, impacts, socio-economic benefits, reclamation and mitigative actions was prepared and submitted to the adjacent communities, aboriginal groups and Canadian federal and provincial governments.

In July 2006, we commenced the development of site infrastructure, including road construction, drill pad preparation, camp construction and the installation of an airstrip.

In October 2006, an approximately 5-kilometre (3-mile), 2-D geophysical program was successfully completed, demonstrating that seismic techniques could contribute to the planned exploration program. In November 2006, exploration drilling began with one drilling rig and by the end of the month three drilling rigs were working on the site. These three rigs drilled continuously until the scheduled Christmas break on December 21, 2006. Drilling recommenced in early January 2007 with four rigs and by the end of February 2007 a total of eight rigs were in place and drilling. Overall, for the winter 2006/2007 exploration program, a total of 150 exploration test wells were drilled in Saskatchewan.
 
In January 2007, due to the extent of land covered by our drilling, we designated an  area, plus certain additional prospective lands associated with it, as Axe Lake. The Axe Lake area is currently comprised of approximately 65 sections (65 square miles) located in Townships 94 and 95, Ranges 24 and 25 West of the 3rd Meridian of Permits PS00208 and PS00210 (100% Oilsands Quest).

In February 2007, an 850-kilometre (528-mile) helicopter-borne, combined electromagnetic and magnetic survey was undertaken and a 166-kilometre (103-mile) 2-D seismic program was completed. This included 64 kilometres (40 miles) of surveys in Alberta.

In May and June 2007, two fixed-wing aircraft completed a high-resolution, intensive 21,000-kilometre (13,000-mile) airborne magnetic survey program within the Company’s Saskatchewan permit lands building further on the airborne surveys made during the 2006/2007 winter program.

In August 2007, we received approvals from the Province of Saskatchewan for the following: testing of Electrical Resistance Tomography; exploration drilling of up to 97 holes under non-frozen ground conditions; miscellaneous use general construction (including road and airstrip construction) permits on the Saskatchewan permit lands; and an extensive 2-D and 3-D seismic program on the Saskatchewan permit lands under non-frozen ground conditions. Approval from the Province of Alberta for a major 2-D and 3-D seismic program on the Raven Ridge Prospect was also received in August 2007. Field work under these approved work programs began immediately with drilling in Saskatchewan commencing on September 14, 2007.

In November 2007, we announced the results of the independent review and evaluation of the Axe Lake area by McDaniel & Associates Consultants Ltd. (“McDaniel”) based on data obtained from the results of drilling up to March 31, 2007 and other sources, including the physical examination of cores and geophysical logs. The independent review and evaluation was prepared and presented in accordance with the standards set out in COGEH and NI 51-101.

In December 2007, a comprehensive exploration program application, consisting of drilling up to 316 core test wells, 2-D seismic surveys and 3-D seismic surveys to be conducted under frozen ground conditions, was submitted to the Federal and Saskatchewan governments for approval. The application also included requests for approvals for conducting reservoir tests, which included the installation and operation of steam generation facilities, thermally completed vertical reservoir test wells and related observation wells including fluid storage facilities at three potential test sites at the Axe Lake area.

In January 2008, we received regulatory approval for our applications and we announced a program of reservoir testing at up to three sites within the Axe Lake area. This reservoir test program was designed on the basis of extensive, ongoing laboratory testing and reservoir simulation studies conducted since June 2007 by our independent consultants and on the studies undertaken by our in-house reservoir engineering group. For a complete description of the nature and activities of the test program, see "-- Axe Lake Area -- Reservoir Development Activities".

We believe our winter 2007/2008 exploration program demonstrated continued success on the Company’s contiguous oil sands exploration lands in Saskatchewan and Alberta. Overall, a total of 175 test wells were drilled with 150 in Saskatchewan and 25 in the Company’s first exploration program conducted on its adjacent land holdings in Alberta. The exploration drilling in Alberta was completed in 12 sections (12 square miles). Of the 175 test wells drilled in the winter 2007/2008 exploration program, 155 were exploration and delineation test wells in Saskatchewan and Alberta of which 103 encountered meaningful intercepts of bitumen-bearing McMurray/Dina formation (67 percent).

A 3-D seismic program conducted in early 2008 covered over 24 square kilometres (15 square miles) in Saskatchewan and 10 square kilometres (6 square miles) in Alberta. A 40-metre (124-foot) by 40 metre grid density was used. The data from this program has been processed and interpretation of the data is complete.  3-D seismic surfaces have been incorporated into our reservoir model and this allows us to map the top and bottom of the reservoir in detail.

In the fall of 2008, we drilled 31 exploration and delineation test wells in the Axe Lake area, and 3 exploration test wells in Saskatchewan. In early 2009, we drilled 23 exploration and delineation test wells in Raven Ridge.  A 25 mile (40 kilometer) 2D seismic program was conducted on Saskatchewan permits which had not been explored by us through drilling or seismic exploration. We are also continuing with the interpretation of the 1,847 kilometers (1,149 miles) of 2-D and 3-D seismic data collected and processed in the 2007/2008 winter program, which is aiding in the characterization of the reservoir and adjacent formation specific to our three test sites at Axe Lake and the reservoirs at Raven Ridge and in assessing the geological structures on our lands.
 
 
4

 
We continued conducting environmental monitoring and baseline assessment activities in support of our exploration and future development activities on our Saskatchewan and Alberta permits. Environmental programs are required as part of the regulatory process for approvals and to ensure compliance with regulatory requirements.  The work has formed the basis of an Environmental Protection Plan submitted to and approved by the Federal and Saskatchewan Provincial governments. This program is integral to the timeline for potential project development at Axe Lake, which began in early April 2007, and is an ongoing part of our activities.

In mid-2008 we released McDaniel's independent estimates of discovered and undiscovered bitumen resource volumes, which were prepared in accordance with COGEH and NI 51-101.  As of December 31, 2008, McDaniel classified a portion of the discovered resources as contingent resources. These contingent resource estimates were prepared for portions of the Axe Lake and Raven Ridge areas only.
In October 2009 we released an updated independent engineering estimate of contingent, discovered and undiscovered resources which were prepared in accordance with the standards set out in COGEH and NI 51-101.  This resource estimate incorporated the results of our 53 well drilling program at Axe Lake in late 2008, and at Raven Ridge in early 2009 and updated the previous estimates provided in December 2008 which were based upon 330 wells drilled up to mid-2008.
 
In July 2010 we released an updated independent engineering estimate of contingent, discovered and undiscovered resources which were prepared in accordance with the standards set out in COGEH and NI 51-101.  This resource estimate incorporated the results of our 9 well drilling program at Wallace Creek in early 2010, the 16 overburden core holes drilled in late 2009 and updated the previous estimates provided in October 2009 which were based upon 383 wells drilled up to early 2009.

In October 2010 we completed a 4 well drilling program which completed our work commitment for the extension of Exploration Permits 208, 210 and 212 in Saskatchewan. The results of this drilling program helped to answer key geological questions in the Axe Lake area but did not have a material effect, positive or negative, on the resource totals.

In November 2010 we completed an 18 well re-abandonment program in which we re-entered 18 core holes previously drilled by the Company in an effort to re-cement and abandon to the specifications required for thermal in-situ operations. 14 of the re-abandonments were fully successful in getting thermal cement to the bottom of the original well bore. 4 of the re-abandonment attempts were not successful in getting thermal cement to the bottom of the original well bore and will require future monitoring or remediation, or potential set-back of production wells.

In 2010 we completed the engineering design for a SAGD pilot project at Axe Lake, which modifies existing surface facilities. We also procured materials with certain long lead times for the facilities and horizontal wells.  The test was originally scheduled for start-up in fall 2010 and intended to run for approximately 6 months. The test has been deferred indefinitely while the Company pursues strategic funding or partnering alternatives.

On January 13, 2011 we provided an operational update and comprehensive review of the geology, reservoir characteristics, and potential development plans for all of our assets.

In May 2011, we released an updated independent engineering estimate of contingent, discovered and undiscovered resources which were prepared in accordance with the standards set out in COGEH and NI 51-101.  This resource estimate applied only to Wallace Creek and incorporated the results of our 5 well drilling program at Wallace Creek in early 2011.  Resource estimates at Axe Lake, Raven Ridge and Eagle’s Nest were not updated.
 
The below table summarizes the drilling program accomplishments to date.

Table 1: Results of Oil Sands Drilling Programs

     
2010/2011
   
Drilled to Date
(Nov.22/05 to April 30/11)
 
   
Wells
Drilled
   
Wells Drilled
   
Sections Drilled
   
Wells per
Section
 
Axe Lake Exploration
   
3
     
323
     
78
     
4.1
 
Axe Lake Development/Reservoir Test
   
0
     
26
     
n/a
     
n/a
 
Axe Lake Groundwater Monitoring
   
0
     
19
     
n/a
     
n/a
 
Saskatchewan Exploration (outside Axe Lake)
   
1
     
36
     
29
     
1.2
 
Raven Ridge Exploration
   
0
     
48
     
23
     
2.1
 
Wallace Creek Exploration
   
5
     
14
     
14
     
1.0
 
Eagles Nest Exploration
   
0
     
0
     
0
     
0.0
 
Total
   
9
     
466
     
144
     
3.2
 
 
The table below summarizes Oilsands Quest’s completed seismic programs.  All of the noted seismic programs were completed prior to fiscal 2011. 

Table 2: Seismic Surveys

   
Saskatchewan
   
Alberta
 
   
Km
   
Miles
   
Km
   
Miles
 
2-D
    337       209       106       66  
3-D
    1,192       741       501       311  
Total
    1,529       950       607       377  

We commenced an overburden characterization study in October 2009 and completed a 16 hole coring and logging program portion that yielded core material and advanced logging data (Nuclear Magnetic Resonance (NMR), Dipole, sonic and standard suite geophysical) of the formation overlying the bitumen-bearing McMurray/Dina formation.

The cores have been analyzed by Weatherford laboratories and results show that the overburden is composed of clay-rich till, which is a dense, low permeability cap layer that demonstrates steam containment characteristics in laboratory and 3-D reservoir computer simulations.

Weatherford Laboratories conducted a high temperature caprock study on the samples provided.  6 samples from the core holes 16-33-092-25W3M, 04-21-094-25W3M, 12-12-095-25W3M, 5-12-095-05W3M, 142/8-11-095-25W3M, and 143/8-11-095-25W3M have been processed, and the laboratory work demonstrates a range of permeabilities from 0.1-0.002md at 20°C.  When the samples are subjected to temperatures of 200°C, a further decrease in permeability to the range of 0.04-0.002 millidarcies ("md") is observed in the laboratory.  These permeability measurements indicate that the ability of the fluid or gas to migrate into the glacial till is significantly impaired allowing the overburden to act as an effective cap for SAGD operations. 

The core samples have been correlated with previously drilled exploration core holes and with our extensive Axe Lake and Raven Ridge 3-D seismic data-sets to determine the extent and continuity of this glacial till layer across the various reservoirs on both sides of the Saskatchewan/Alberta border.  Based on the current data set it appears that the dense glacial till layer is present over the majority of the potential commercial development area.  To the extent that we are able to secure additional financing and continue as a going concern, we plan to conduct further 3-D seismic and overburden drilling and to fully map the dense overburden across all reservoir areas.

Generally the dense glacial till layer lies directly on top of the oil sands reservoir zone, however in some areas there are several meters of top water between the oil sands zone and the glacial till. The impact of these zones is being studied and the results will be incorporated into our commercial development plan.

Axe Lake Area – Reservoir Development Activities

The 3-D seismic survey program in northwest Saskatchewan was concentrated in Axe Lake and covered over 24 square kilometres (15 square miles). We are using the detailed, three component 3-D seismic survey data as one of the key tools to further define the geological structure and reservoir architecture to assist in the ongoing reservoir studies and technical planning related to the development of this resource. For a description of the seismic program on Axe Lake, see tables in “Description of Business -- Activities to Date”. Geological models have been developed and have incorporated laboratory measurements of fluid properties, geo-mechanical characterization, porosity, permeability as well as special core floods and cap rock integrity measurements.

At Test Site 1, we drilled and completed six vertical test holes and drilled three 750-metre horizontal holes (300 metres length within the reservoir) and procured the horizontal well instrumentation strings necessary to measure the temperature and pressure in the reservoir. We have completed construction of water treatment, steam generation and extraction collection facilities, which includes three steam generators totaling 38 million BTU/hour steam generation capacity, two diesel power generators each with 750 kilowatt power output capacity, water/oil treatment and oil handling equipment, control systems and eight 1,000-barrel heated liquid storage tanks to support related Test Site 1 activities.
 
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Also at Test Site 1, we completed two mini-frac tests that successfully measured the relevant geo-mechanical properties of the oil sands reservoir, as well as the overburden (glacial till materials above the oil sands reservoir) and underburden (Devonian limestone materials below the oil sands reservoir) close to the oil sands reservoir. Calibration of the numerical reservoir simulation tools to the mini-frac tests by conventional history matching techniques has also been completed.

We constructed Test Site 2 for the potential testing and development of alternative recovery technologies.  There are currently no plans for this site.

At Test Site 3, we conducted low energy tests using a custom, downhole electrical heater. We measured pressures and temperatures at ten different locations inside the oil sands reservoir. This information has been used for preliminary calibration of our reservoir simulator to help maximize the efficiency of the SAGD Pilot at Test Site 1. We drilled, completed and instrumented two vertical test holes and we have constructed the supporting infrastructure. One vertical test hole is equipped with a downhole electric heater to provide heat to the reservoir and both test holes are equipped with pressure and temperature sensors to allow for determination of the effective reservoir heat transfer and mobilization of the bitumen at lower temperatures. Heating of the reservoir was initiated in late October 2008 and re-commenced in mid-January of 2009 with the heater placed at the depth of the Devonian underburden. In April of 2009, the heater was raised to the bottom of the oil sands reservoir and heating continued, until the heater was removed from the well on June 26, 2009.

Pressures and temperatures were measured and recorded continuously at ten locations in the hot heater well, 1OBS 5-29-94-25, and the cold observation well, INJ 5-29-94-25.  The heater was removed from the well on June 26, 2009.  Our detailed engineering and numerical simulation analysis has confirmed the formation characteristics and related fluid and thermal properties to be used in continued reservoir planning at Axe Lake. The electrical heating program at Test Site 3 enabled the determination of reservoir properties such as effective thermal conductivity.

In October of 2009, we perforated the two vertical wells at Test Site 3, which are approximately 3.5 meters apart, and installed temporary water, heating and injection facilities.  The objective of this test was to inject water and produce water and bitumen at different temperatures in order to:
 
1.
confirm the establishment of initial fluid movement in areas with water saturation of greater than 35%;
2.
confirm the ability to establish convective heat transfer at the bottom of the reservoir;
3.
determine the conductive heat transfer characteristics at the bottom of the reservoir;
4.
recover bitumen by using both hot water and solvent injection; and
5.
gather preliminary data on the horizontal displacement of fluids.
 
We commenced injecting cold water at low pressure and volume into the base of the McMurray/Dina formation on October 25, 2009 and established communication between the two wells.  Cold water circulation was maintained for 24 hours, following which heated water was circulated, resulting in the mobilization of bitumen in the reservoir.  On October 29, 2009, a small amount of naphtha was injected and bitumen recovery commenced on October 30, 2009.  We continued to circulate hot water until November 5, 2009, at which time the test equipment was removed.  

On October 18, 2009, the electrical, mechanical and boiler facilities at Test Site 1 were successfully commissioned and, on December 5, 2009, we commenced the injection of cold water into the reservoir at Test Site 1. The test was to measure heat and fluid movement under specific operating conditions on a field scale to complement our ongoing simulation and laboratory analysis studies and further enhance our knowledge and modeling of the thermal and geo-mechanical characteristics of our reservoir.

Initial injectivity was achieved and circulation tests were conducted between three sets of well pairs that are 1.5m, 10m, and 18m apart respectively. Tracer tests were also conducted by injecting a saline solution down the injector well and measuring the produced volumes of salt and water in the producer well. Inter-well communication was positively confirmed by measurement of substantial percentages of saline tracer at the producer wells.

The next phase of testing, subject to regulatory approvals and our ability to secure additional financing and continue as a going concern will be a SAGD pilot at Test Site 1.  This will include the drilling of a new SAGD well pair in close proximity to the existing wells at Test Site 1 to build on our growing knowledge of the reservoir and cap rock characteristics and test the commercial viability of SAGD at Axe Lake.  The test plan will use one 100 metre long horizontal well pair, with the upper well placed five metres below the top of the interface between the overburden and the oil sands, and will also make use of the existing surface facilities.  SAGD has been the most widely used, and therefore best understood, in situ recovery technique for the production of immobile bitumen (at initial reservoir conditions) in the McMurray/Dina formations.

The objectives of this pilot are to:

1.  
test the effects of steam contact on the glacial till overburden at Axe Lake and demonstrate that the cap will perform as a competent steam containment barrier in SAGD operations;
2.  
confirm early stage SAGD production and steam rates with a scalable well length in order to improve forecasting for a commercial project;
3.  
determine the optimal producing pressure for a commercial project;
4.  
establish gas production rates and composition and produced water composition for facility design; and
5.  
better understand the initial critical water saturation (minimum saturation at which water becomes mobile) in bitumen rich zones for use in forecast model.

Following the successful completion and interpretation of the initial steam test results, we would like to submit an application to continue the test for up to another six months in order to further evaluate injection pressures to help determine the optimal operational pressure for designing a commercial project.

At Test Site 1 we drilled two water source wells which showed excellent fluid mobility and sufficient water withdrawal capacity to meet the current needs of the reservoir test program at Axe Lake. At Test Site 3 we drilled and tested two water source wells which did not demonstrate sufficient water mobility and were abandoned.

We drilled, perforated and tested one vertical well (Oilsands Quest Clearwater OBS 4-21-94-25 W3M) near Test Site 3 for water disposal into the McMurray/Dina formation. The testing was positive and an application to dispose water in this well was submitted to the Saskatchewan government in June 2009. Approval to use the 4-21 week for disposal of water for the first phase of testing at Test Site 1 was granted and the well was used for water disposal in fall 2009. At Test Site 2 we drilled one deep well to test the potential of the underlying Devonian Methy formation for waste water disposal. The results of this well showed that the Devonian Methy formation does not contain enough porosity in the tested location to support water disposal.  Other test locations are being investigated.

In May 2010, we filed an application with the Saskatchewan Ministry of Environment ("SME") for approval to develop a 30,000 barrels per day of bitumen project at Axe Lake using SAGD.  We are currently working with SME and CEAA on the project specific guidelines under which the environmental impact would be evaluated.

Filing with the SME is the first step in a two-stage process to apply for approval of a commercial lease for oil sands development.  This application provides the complete vision for the project, giving the regulator helpful context when approving testing activity and giving all stakeholders clarity around the long-term development plans. The second stage of the process consists of an application for commercial project approval to the Saskatchewan Ministry of Energy and Resources ("SMER"). We plan to submit the second application following the successful completion of the SAGD pilot. In preparing the second application, we will continue to develop detailed engineering plans, cost estimates and financing plans for the project based on the ongoing production testing activities at Axe Lake.

The proposed commercial project includes components typical of SAGD operations such as multi-well production pads of horizontal well pairs, and a central processing and bitumen and natural gas treatment facility that includes water treatment, water recycling, steam generation and tank storage facilities. Options for site access, utility service corridors, electricity and natural gas supplies are also being evaluated.

In May 2010, we relinquished two of our northernmost land permits (permits PS00213 and PS00215) as we focus our activities to include only those lands that recent exploration activity has demonstrated to be prospective.  Exploration activities on these two permits included over 42 miles (68 kilometres) of 2-D seismic and 14 core holes.  The relinquishment of these permits did not impact the Company’s resource estimates or development plans.

In May 2011, we received the third and final one-year extension of Saskatchewan oil sands permits PS00208 and PS00210. We have a work commitment of one core hole on each of the 2 permits to keep the permits in good standing for lease conversion. All other remaining exploration permits (PS00215, PS00206, PS00212) were relinquished to the crown on their anniversary date of May 31, 2011, as we see the lands outside of the core Axe Lake Area in permits PS00208 and PS00210 and having low prospectivity.  We intend to relinquish all of our oil sands licenses to the south of Axe Lake on their anniversary date of August 12, 2011. Relinquishing these permits and licenses will not impact the Company’s resource estimates or developments plans.  A full impairment allowance was taken on the licenses at April 30, 2011.

At the conclusion of the formal phase of the strategic alternative review process (described more fully in the Corporate section), management determined that the carrying value of the Axe Lake permits was greater than their fair value at April 30, 2011, thus resulting in impairment in the value of the permits. We recorded a valuation allowance of $296.2 million at April 30, 2011.

Development of a commercial project at Axe Lake remains subject to financing, regulatory approval and other contingencies such as successful reservoir tests, internal approvals, and other risks inherent in the oil sands industry (See Part I, Item 1A. "Risk Factors" and see Part II, Item B. "Other Information").  Currently, we do not have the financial resources to complete a commercial development.

 
6

 
 
Raven Ridge
 
In March 2007, prior to acquiring the key permits comprising Raven Ridge, we completed 64 kilometres of 2-D seismic survey to assess the potential of the permit land and identify potential drilling targets. As a result of this survey, we expected that the Axe Lake oil sands reservoir would extend into Alberta and that numerous attractive exploration drilling targets would be identified. A detailed, three component 3-D seismic survey was undertaken covering 6.4 square kilometers (4 square miles) adjacent to the program undertaken at Axe Lake, in Saskatchewan. Initial approval for exploration drilling in Alberta was received in December 2007 and 25 exploration holes were drilled in 12 sections (12 square miles) during the 2007/2008 program. Of the 25 holes, 18 encountered meaningful intercepts of McMurray/Dina formation (72 percent) at depths of 113 metres (371 feet) to 227 metres (745 feet). The thickness of the bitumen-bearing zone within the McMurray/Dina formation was observed to be between 7 metres (23 feet) and 34 metres (112 feet) (net pay) with an average of 15.5 metres (51 feet).
 
In early 2009, we drilled an additional 23 exploration and delineation test wells in Raven Ridge. The Raven Ridge drilling program has demonstrated continuity of bitumen characteristics extending from Axe Lake in Northwest Saskatchewan westward into Alberta and we have identified, through drilling, two areas of specific interest for potential development. There was significant correlation observed between the drilling results and the estimates made based on the Company’s 2007 2-D seismic program.
 
McDaniel reviewed the results and provided an updated resource estimate in compliance with COGEH and NI 51-101 in July 2010.

We do not currently have the commercial or technical wherewithal to develop our Raven Ridge area.  Following the conclusion of the formal phase of the strategic alternative review process (described more fully in the Corporate section), an impairment provision of $27.2 million was recorded in the year ended April 30, 2011.
 
Wallace Creek

In January 2008, prior to acquiring the Wallace Creek permits, we completed 53 kilometres (32 miles) of 2-D seismic survey to assess the potential of the permit lands prior to their purchase. During the 2006/2007 winter exploration program, the Company drilled two holes in Saskatchewan, directly to the east of Wallace Creek and both intercepted bitumen-bearing oil sands. Within the Wallace Creek permit lands, there are also five legacy test wells drilled.

In March 2010, we completed a 9 hole exploration drilling program on lands in the western township (TWP 96 R2 W4) of the Wallace Creek permits that are immediately adjacent to Cenovus' Borealis project area.  4 of the wells drilled encountered significant quantities of bitumen with one well intercepting up to 26 meters of oil sand in the McMurray/Dina formation. McDaniel reviewed the results and provided an updated resource estimate in compliance with COGEH and NI 51-101 in June 2010.

In March 2011, we completed a 5 hole exploration drilling program on lands in the western township (TWP 96 R2 W4) of the Wallace Creek permits.  2 of the wells drilled encountered significant quantities of bitumen in the McMurray/Dina formation.

McDaniel reviewed the results and provided an updated resource estimate in compliance with COGEH and NI 51-101 in May 2011.

In June 2011, we received approval from Alberta Energy to extend the Wallace Creek permits for an additional 67 days to March 31, 2013. This extension will allow us to have 2 full winter exploration seasons in which to complete more exploratory seismic and drilling prior to any applications for conversion to lease. 

Eagles Nest

Over the winter of 2005/2006 we undertook a detailed assessment of the historical data available on the Eagles Nest Prospect. During 2007/2008 we concentrated our efforts in acquiring the interests of the Triple 7 Joint Venture partners, which was completed in June 2008.

McDaniel reviewed the results and provided an updated resource estimate in compliance with COGEH and NI 51-101 in July 2010.

We also announced our intention to divest our Eagles Nest oil sands lease.  The Eagles Nest property is geographically distant from our other oil sands discoveries and is largely unexplored.  We have not yet received any offers under financial terms that are acceptable to us and have determined that it is in our best interest to retain these assets until an adequate offer is received or additional funds are available for the development of these longer-term assets. 
 
We do not currently have the commercial wherewithal to develop the Eagles Nest area.  Following the conclusion of the formal phase of the strategic alternative review process (described more fully in the Corporate section), an impairment provision of $8.4 million was recorded in the year ended April 30, 2011.
 
Pasquia Hills Oil Shale Permit Area

In September 2008, we drilled 11 exploration test holes (covering an area of approximately 100 square miles) on our oil shale prospect in southeastern Saskatchewan with all the holes drilled encountering meaningful intercepts of oil shale of up to 21.5 meters in thickness.  

In September and October 2009, we drilled and logged 12 exploration test holes on our oil shale prospect in eastern Saskatchewan with ten out of twelve holes drilled experiencing meaningful intercepts of oil shale of up to 37.0 meters in thickness.  The key challenge is in the development of our oil shale properties will be finding an economic process to produce kerogen (oil shale) on a commercial basis.  A geologic assessment of our permit lands based on the drill results, together with the data obtained from legacy drilling has been prepared by Norwest Corp.

As previously disclosed, the Company had reached an agreement to sell its Pasquia Hills oil shale properties to Canshale Corp., a private company formed by the former President and Chief Executive Officer of the Company (the “Purchaser”) for consideration of $1 million CDN ($0.9 million USD) in cash and 8,000,000 shares of the private company. The sale was conditional on the Purchaser raising a minimum financing amount as defined in the terms of the agreement. As Canshale Corp. was unable to secure the financing by the extended deadline of July 30, 2010, the Company announced on August 13, 2010 the cancellation of this transaction.

On September 22, 2010, the Company announced the undertaking of a process to divest the oil shale permits at Pasquia Hills following a determination by the Board of Directors (the "Board") that these assets are non-core as both properties are located outside the Company’s primary project and discovery areas of Axe Lake, Wallace Creek and Raven Ridge.

As of January 31, 2011, these properties were no longer considered to be held for sale nor were the related operations considered discontinued. Since the Company has not yet received any offers under financial terms that are acceptable under the current divestiture plan for the non-core assets, management has determined that it is in our best interest to retain these assets until an adequate offer is received or additional funds are available for the development of these long-term assets.  We do not currently have the commercial or technical wherewithal to develop our Pasquia Hills oil share properties.

Management recognized a full impairment on the property and wrote down the remaining carrying value of $5.0 million ($5.0 million CDN) to zero at January 31, 2011. The cumulative impairment to date on the Pasquia Hills properties amounts to $11.9 million ($11.3 million CDN).

Corporate

On August 17, 2010, we announced that we had initiated a process to explore strategic alternatives for enhancing shareholder value. The Board’s decision reflected careful consideration of our financial position and the capital required to execute the business plan. In light of the significant incremental capital required to advance the development of the oil sands assets in Saskatchewan and Alberta, the Board determined that it was in the best interests of shareholders to engage financial advisors and formally explore all alternatives. The strategic alternatives process was overseen by a Special Committee chaired by Brian MacNeill and including Ronald Blakely and Paul Ching.

The Special Committee considered all alternatives to increase shareholder value, including strategic financing opportunities, asset divestitures, joint ventures and/or a corporate sale, merger or other business combination. We retained TD Securities Inc. (“TD”) as a financial advisor to assist us with this process.
 
 
7

 
 
As part of this process, TD and the Company made contact with a large number of companies. From that initial outreach, we entered into confidentiality agreements with eight different entities, which then had access to the Company’s data room. To date, the formal strategic alternatives process has not resulted in any proposals to the Company. The discussions and negotiations throughout this process have illustrated that potential future partners or acquirers would need to see a further level of development and de-risking of the assets in order to be prepared to make a substantial investment. We are therefore seeking funding to advance our assets toward commercial development, while remaining open to offers of joint venture opportunities, asset sales or other opportunities. In the interim, we intend to conduct a rights offering (the "Rights Offering") under which our existing shareholders would be given the right to purchase, on an equal, proportional basis, additional shares in the Company and shareholders who fully exercise their rights would be entitled to subscribe for additional shares that remain unsubscribed as a result of any unexercised rights.
 
The proceeds from the Rights Offering will be used to continue with the delineation and development of the assets (as described more fully under the “Outlook” section below), and for general corporate purposes.

There can be no assurance that the Rights Offering will result in the Company raising sufficient funds to carry out its exploration and development plans and the Company may continue to seek other sources of financing or asset sales.
 
On July 5, 2011, the Board accepted the resignations of Ronald Phillips and John Read effective September 6, 2011.  As well, T. Murray Wilson informed the Board that he did not intend to stand for re-election at the 2011 Annual General Meeting of Shareholders.  Further, Leigh Peters, the Company’s Vice President Legal and Corporate Secretary, left the Company effective immediately.   These changes reflect proactive moves on the part of the Board and Management to address the Company’s current financial situation.
 
Environmental and Regulatory

The Company is in discussion with SMER to assess a re-abandonment issue relating to the abandonment of early exploration core holes.  We have drilled 359 exploration core holes in Saskatchewan and during a review of our development plans and well records, we determined that 242 of the early-year wells were not abandoned to a standard that meets our thermal development requirements or were not abandoned in accordance with the regulatory requirements

We have applied for waivers on 99 core holes, the majority of which are located outside the current potential commercial development area and the regulator has indicated that they are willing to consider such waivers on a case by case basis.  Our waiver applications are based on the fact that these core holes fall outside the current commercial development area and are therefore located in areas that are not expected to be economically recoverable.  We have included approximately 143 core holes in our management's best estimate of the re-abandonment costs as described in our financial statements.

During the year ended April 30, 2011, we completed an 18 hole re-abandonment program.  We successfully re-abandoned 14 core holes and were only partially successful in our attempt to re-abandon the other four core holes. Those four core holes may still contain conduits which will require the Company to undertake further monitoring should a SAGD project be implemented within the vicinity of these core holes. The re-abandonment of these four core holes occurred early in the program, and we anticipate high success rates on the re-abandonments still to come.
 
The remaining 125 core holes are comprised of a combination of locations that are in or adjacent to the commercial development area plus a portion of the core holes for which we intend to seek waivers.  Our best estimate of the undiscounted/gross cost to complete this program over the next four years is $26.0 million.

Outlook

Our reservoir development and exploration activities over the next few months will be focused on preparing to execute the SAGD pilot at Axe Lake, designing and executing a seismic program at Wallace Creek and working with SMER to convert our Axe Lake permits to a long-term lease.  All of these plans are subject to our receipt of the necessary financing.  See "Risks Related to Our Business - Due to our history of operating losses, we are uncertain that we will be able to maintain sufficient cash to accomplish our business objectives".

At Axe Lake, we are seeking to retain portions of PS00208 and PS00210 and convert them to leases. The permits are currently held under the Oil Shale Regulations, 1964. We have applied to SMER to convert these permits to licenses and then to leases under the terms of the Petroleum and Natural Gas Regulations, 1969. The outcome of these discussions is not certain.

We expect to relinquish the balance of our Axe Lake lands in Saskatchewan as we do not believe that the licenses to the south of the Axe Lake permits are prospective, either due to the presence of interbedded water in the reservoirs that would not allow for commercial development or lack of bitumen in the reservoirs in the licenses in the southern portion of our Saskatchewan lands. We expect to relinquish these licenses in August 2011.

Based on the drilling results at Wallace Creek and our knowledge of the regional geology, we believe there is good potential for that project area to support a commercial SAGD project. Further seismic work or delineation drilling is required to confirm this potential and retain certain portions of these permits.
 
After analysis of available drilling and seismic data, we have concluded that the lands in the south part of Raven Ridge on Permit No. 7006080098 are not prospective and we expect to relinquish this permit in August 2011. Relinquishing these lands will have no impact on the Company's current resource estimates or development plans.

The Company may offer and sell shares of common stock by way of "at-the-market" distributions on NYSE Amex, until January 18, 2012. Funds raised from the ATM program will be used for general corporate purposes.  In addition, the Company intends to conduct a Rights Offering described above under the "Corporate" section. 
 
There can be no assurance that the Rights Offering will result in the Company raising sufficient funds to carry out the exploration and development plans described above.

Employees
 
As at June 30, 2011, the Company had 18 employees.  Additional consultants may be added as activity levels dictate and field exploration and development activities increase.

Available Information

We maintain an internet website at www.oilsandsquest.com. The information on our website is not incorporated by reference in this Annual Report on Form 10-K.  We make available on or through our website annual, quarterly and periodic reports, proxy statements and other information that we file with or furnish to the Securities and Exchange Commission (the “SEC”) in accordance with the Securities Exchange Act of 1934, as amended. Alternatively, you may read and copy any information we file with the SEC at the SEC's public reference room at 100 F Street N.E., Washington, D.C. 20549. You may obtain information about the operation of the public reference room by calling 1-800-SEC-0330. You may also obtain this information from the SEC’s website, www.sec.gov. We also file this information with Canadian securities regulators and it is available at www.sedar.com.

The Oil Sands Industry in Canada

The following information quotes liberally from the Canadian Association of Petroleum Producers, the Energy Resources Conservation Board of Alberta, the National Energy Board of Canada and a variety of technical reports and publications.

The International Energy Agency (“IEA") projects that world primary energy demand will maintain steady growth over the next two decades, increasing on average by 1.5% per year from 2007 - 2030, resulting in an aggregate demand growth of approximately 40%. Fossil fuels, primarily crude oil, coal and natural gas, are expected to remain the dominant sources of primary energy, accounting for nearly 77% of this demand growth. Oil, in particular, is expected to remain the single largest fuel source throughout this period, accounting for 30% of demand in 2030.

According to the IEA, worldwide demand for oil was 85 million barrels per day (“bbls/d”) in 2008 and is expected to grow to 105 million bbls/d by 2030, an annual growth rate of approximately 1%.  Although the majority of this growth is expected in non-OECD countries such as China and India, North America is projected to be a large consumer of oil, representing 21% of total demand in 2030.

The IEA estimates that approximately one-third of the world's ultimately recoverable conventional oil resources have already been produced.  By 2030, it is expected that one-half of the world's ultimately recoverable conventional oil resources will have been produced. Non-OPEC conventional production is not expected to be sufficient to keep pace with rising demand.  Therefore, oil markets are expected to become more reliant on OPEC production and unconventional sources of crude oil.

Unconventional oil production, including bitumen, is expected to grow as a percentage of total world production from approximately 2.2% in 2008 to approximately 7.2% in 2030. This reflects an average annual growth rate of 6.6% per annum, far in excess of the expected annual growth rate for total production of 1.0% per annum. Canada's unconventional production, in particular, is expected to grow at approximately 5.4% per annum, reaching total production of 3.9 million bbls/d in 2030.
 
 
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In terms of global energy sources, Canada’s oil reserves are second only to those of Saudi Arabia, which has an estimated 264 billion barrels of oil reserves. Canada’s oil reserves are estimated to be 179 billion barrels, of which 173 billion barrels are oil sands reserves considered economically recoverable with today’s technology.
 
Canada’s oil sands deposits contain a vast quantity of crude bitumen: an initial volume-in-place of 1.7 trillion barrels which includes an ultimate potential of 315 billion barrels recoverable. The Canadian Association of Petroleum Producers (“CAPP”) estimates that, at current production levels, oil sands reserves could sustain production of 3.0 million barrels/day for more than 150 years.
 
CAPP predicts oil sands production to increase to approximately 2.2 million bbls/d in 2015 and up to 3.5 million bbls/d in 2025. This increase in production from the oil sands is expected to occur over a period in which conventional oil production in Canada declines.
 
Oil sands deposits are composed primarily of sand, silt and clay, water and bitumen, along with minor amounts of other minerals. Typical composition might be 75 to 80 percent inorganic material (mostly quartz sands), 3 to 7 percent water, and 10 to 12 percent by weight bitumen, with bitumen saturation varying between zero and 18 percent by weight.

Oil from the oil sands is often called “crude bitumen” to distinguish it from conventional crude oil. Bitumen is a thick, black, tar-like substance that pours extremely slowly. Compared to typical crude oils, which contain approximately 14 percent hydrogen, bitumen is deficient in hydrogen. In order to make crude bitumen an acceptable feedstock for conventional refineries, it must be upgraded through the addition of hydrogen or the rejection of carbon. In order to transport crude bitumen to refineries, it must be blended with a diluent, usually condensate, to meet pipeline specifications for density and viscosity.

Oil sands deposits are located at a variety of depths. Economically recoverable oil sands that are located less than 200 feet deep can be recovered by open pit mining methods; those located deeper than 200 feet can be produced using in situ (or “in place”) methods of bitumen recovery.

Alberta has three major oil sands areas, each with a number of bitumen-bearing deposits: Athabasca, Cold Lake and Peace River. According to the Energy Resources Conservation Board (“ERCB”) of Alberta, an estimated 20 percent of the Province’s initial established reserves are mineable; the remainder are suitable only for in situ recovery methods. The Athabasca oil sands cover the largest area; this is also where the province’s mineable deposits are located. The ERCB also estimates that, in Alberta, the vast majority of lands thought to contain bitumen that could be recovered by either method are currently already leased.

While both oil sands mining and in situ production methods impact the land, the surface footprint of in situ production is significantly smaller than that of a mine, and according to CAPP on a per barrel basis can be smaller than conventional oil production. An open pit mine's footprint ultimately affects the entire surface area over the resource and also requires tailings ponds, while in situ production requires only well pads on the surface for well heads, similar to conventional oil and gas, but, with more barrels typically recovered per well pad.

In open pit mining operations, overburden is removed, oil sands ore is mined and bitumen is extracted from the mined material essentially using hot water processes. With in situ recovery, generally steam, water or other solvents are injected into the reservoir to reduce the viscosity of the bitumen, which allows it to flow to a vertical or horizontal wellbore.

Commercial production from the Alberta oil sands began in the 1960s. The first two integrated mining projects were Great Canadian Oil Sands (now Suncor), which began operations in 1967, and Syncrude, which came onstream in 1978. The ERCB estimates that, at the end of 2008, almost three-quarters of the initial established reserves in the surface-mineable area were under active development. There are now three mining projects, another two mine projects are under construction and seven are in various stages of project development.

Aside from primary production (including water injection), which has limited use in Cold Lake and Peace River areas, two main in situ methods are being used to commercially produce bitumen: cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD).

Upgrading is a process performed by specialized refineries called upgraders that transform bitumen into higher value hydrocarbons, most of which require additional processing at a refined products refinery before they can be used by end users. The primary output of oil sands upgraders is a light crude oil. All oil sands mining projects currently in operation are integrated with upgraders, while most in situ projects are not integrated with upgraders. In recent years, the differential of bitumen pricing to light crude oil pricing (the "Bitumen - Light Differential") has narrowed considerably. The increased demand for bitumen relative to the available supply has reduced the economic attractiveness of upgrading and has resulted in higher netbacks for non-upgraded bitumen.

Bitumen blends from Canadian oil sands could potentially be exported to world markets as early as 2016, assuming planned developments are completed as scheduled.  If completed, these future pipelines will potentially allow oil sands producers to compete with other regions such as the Persian Gulf and South America since the nautical distance between Kitimat and east Asia is comparable to the distance between east Asia and the Persian Gulf and is shorter than the distance between Asia and South America. These pipeline projects are currently being evaluated and constructed in response to strong support from oil sands producers.

In CAPP’s most recent forecast they state "given signs of the beginning of economic recovery, oil sands producers are proceeding with a more balanced pace of development.  Producers have returned many projects back to active development but remain mindful to establish a more controlled cost environment as they remain cautious with their estimates for future oil prices."

In addition to economic factors, the challenges Canada’s oil sands industry faces include long term skilled labour shortages and environmental issues. However, according to the National Energy Board: “The challenges faced by the oil sands industry are counter-balanced by the opportunities. At a time of increasing resource nationalism around the world, Canada’s huge oil sands reserves, set in a climate of relatively stable political and economic policy, represent an attractive target for investment. The potential for technological innovation to reduce the costs of bitumen extraction and upgrading is an additional attraction. Given the outlook for continued higher oil prices, return on investment should be sufficient to drive oil sands expansion.”

Glossary of Common Terms

The terms defined in this section are used throughout this Form 10-K.
 
Bitumen or crude bitumen
 
A highly viscous oil which is too thick to flow in its native state, and which cannot be produced without altering its viscosity; a naturally occurring mixture, mainly consisting of viscous hydrocarbons heavier than pentane, that may contain sulphur compounds and that in its naturally occurring viscous state does not usually flow to a well. The density of bitumen is generally less than 10 degrees API (as that term is defined by the American Petroleum Institute).
     
CEAA
 
Canadian Environmental Assessment Agency
     
COGEH
 
Canadian Oil and Gas Evaluation Handbook
     
Core
 
Cylindrical sample of rock taken from a formation for the purpose of examination and analysis.
     
Core hole, core test well, Stratigraphic test well, or Exploration Stratigraphic test well
 
A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Ordinarily, such wells are drilled without the intention of being completed for hydrocarbon production. They include wells for the purpose of core tests and all types of expendable holes related to hydrocarbon exploration.
     
   
Stratigraphic test wells are classified as
     
   
(a) “exploratory type” if not drilled into a proved property; or
     
   
(b) “development type”, if drilled into a proved property.
     
   
Development type stratigraphic wells are also referred to as “evaluation wells”.
 
 
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Crude oil (conventional)
 
A mixture that consists mainly of pentanes and heavier hydrocarbons, which may contain sulphur and other non-hydrocarbon compounds, that is recoverable at a well from an underground reservoir and that is liquid at the conditions under which its volume is measured or estimated. It does not include solution gas or natural gas liquids.
     
Degrees API
 
A scale defining hydrocarbon density, determined by the American Petroleum Institute ("API"); the lower the number, the higher the viscosity (see “viscosity”).  Water has a API of 10.
 
Diluent
 
Lighter viscosity petroleum products that are used to dilute bitumen for transportation in pipelines.
     
Exploration costs
 
Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells.
     
Extraction
 
A process unique to the oil sands industry, in which bitumen is separated from its source (oil sands).
     
Formation
 
A bed or deposit composed throughout of substantially the same kind of rock. Each different formation is given a name, often as a result of the study of the formation outcrop at the surface and sometimes based on fossils found in the formation.
     
In situ
 
In its original place; in position. When referring to oil sands, in situ recovery refers to various methods used to recover deeply buried bitumen deposits, including steam injection, solvent injection and firefloods.
 
Kerogen
 
The hydrocarbon content of oil shale. Kerogen is also known as shale oil.
     
Lease
 
An agreement granting to the lessee rights to explore, develop and exploit a property.
     
McMurray/Dina
 
The McMurray formation is a stratigraphical unit of Cretaceous age in the Western Canadian Sedimentary Basin.  The Saskatchewan equivalent is known as the Dina formation.
     
NI 51-101
 
National Instrument 51-101
     
Oil sands
 
Sand and other rock materials containing bitumen; the crude bitumen contained in those sands and other rock materials. Bitumen is immobile at the initial reservoir conditions.
     
Oil sands deposit
 
A natural reservoir containing or appearing to contain an accumulation of oil sands separated or appearing to be separated from any other accumulation.
     
Oil shale
 
A geologic formation consisting of shale which contains hydrocarbons.
     
 Overburden
 
Thickness of material above an occurrence of bitumen. The thickness of the overburden determines the method of bitumen recovery (mining or in situ techniques). Overburden could consist of layers of sand, gravel and shale; in many places overburden underlies muskeg which is a water-soaked layer of decaying plant material one to three metres (three to ten feet) thick. Muskeg supports the growth of shallow-root trees.
     
Permeability
 
Ability of a porous rock to transmit fluid through its pore spaces. A rock may be highly porous and yet impermeable if it has no interconnecting pore network (communication).
     
Porosity
 
The proportion of a rock's total volume occupied by voids between mineral grains.
     
Reservoir
 
Porous, permeable sedimentary rock structure or trap containing oil and/or gas. A reservoir can contain more than one pool (accumulation of oil or gas).
     
 SAGD
 
Steam assisted gravity drainage is an example of an in situ process used to recover bitumen from oil sand located too deep to be profitably mined.
     
SME
 
Saskatchewan Ministry of Environment
     
SMER
 
Saskatchewan Ministry of Energy and Resources
     
Upgrading
 
The process that converts bitumen or heavy crude oil into a product with a lower density and viscosity.
     
Viscosity
 
A measure of the resistance of a liquid to flow. The viscosity of petroleum products is commonly expressed in terms of the time required for a specific volume of the liquid to flow through an orifice of a specific size.  As the temperature of a fluid increases its viscosity decrease and therefore it flows more easily.
     
Working interest
 
The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to share in the production.

Item 1A.  RISK FACTORS

Our business activities, and the oil and gas industry in general, are subject to a variety of risks. If any of the following risk factors should occur, our profitability, financial condition or liquidity could be materially impacted. As a result, holders of our securities could lose part or all of their investment in Oilsands Quest Inc.

RISKS RELATED TO OUR BUSINESS
 
Government Regulations and Retention of Permits, Leases and Licenses

The business of resource exploration and development is subject to substantial regulation under Canadian federal, provincial and local laws relating to the exploration for, and the development, upgrading, marketing, pricing, taxation, and transportation of oil sands bitumen and related products and other matters. Amendments to current laws and regulations governing operations and activities of oil sands exploration and development operations could have a material adverse impact on our business. In addition, there can be no assurance that income tax laws, royalty regulations, environmental regulations and government incentive programs related to the permits in Saskatchewan, oil sands exploration licenses in Saskatchewan, the permits in Alberta and the Eagles Nest Prospect and the oil sands industry generally, will not be changed in a manner which may adversely affect our progress and cause delays, or cause the inability to explore and develop, resulting in the abandonment of these interests.

Alberta's new Land-Use Framework, which is to be implemented under the Alberta Land Stewardship Act ("ALSA"), sets out the Government of Alberta's approach to managing Alberta's land and natural resources to achieve long-term economic, environmental and social goals.  ALSA contemplates the creation of regional plans which could amend or extinguish previously issued regulatory permits, licenses, approvals and authorizations in order to achieve or maintain an objective or policy resulting from the implementation of a regional plan.  The Government of Alberta is expected to develop a regional plan for each of seven regions in the province and has identified the Lower Athabasca Regional Plan ("LARP") as a priority.  The Company's properties in Alberta are within the LARP's boundaries.  The LARP is expected to incorporate regional thresholds for air emissions, water use and land disturbance to control cumulative effects of industrial development, and guide future resource decisions while considering social and economic impacts.  The final LARP is expected to be sent to the Alberta Cabinet for approval in mid 2011.

In Saskatchewan, a new Environmental Management and Protection Act, 2010 has been passed by the Legislature but not yet proclaimed.  The new Act will include authority for the Saskatchewan Environmental Code, which adopts a new results-based regulatory framework for managing and protecting the environment.  It is anticipated that the Act and the Code will be proclaimed in 2011.
 
It is possible that the LARP in Alberta and the new Act and Code in Saskatchewan may negatively impact our ability to conduct operations on certain properties or limit or prohibit development due to environmental limits and thresholds.  In addition, enhanced operating practices required to be undertaken by us in response to the LARP and the new Act and Code may increase operating costs and such costs may further increase in the future if there are further changes to the prescribed operating Practices.
 
 
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The Species at Risk Act, or SARA, was enacted by the Government of Canada as a means to manage species of special concern to prevent them from becoming extinct, endangered or threatened.  The woodland caribou has been designated as a species under threat in the Province of Alberta. Pursuant to the SARA, lands that fall within our oilsands leases have been designated as sensitive habitat for caribou.  We have undertaken enhanced operating practices within the designated areas with a view to protecting the threatened caribou population.
 
Permits, leases, licenses and approvals are required from a variety of regulatory authorities at various stages of exploration and development. There can be no assurance that the various government permits, leases, licenses and approvals sought will be granted in respect of our activities or, if granted, will not be cancelled or will be renewed upon expiry. There is no assurance that such permits, leases, licenses and approvals will not contain terms and provisions which may adversely affect our exploration and development activities. Our exploration permits in Saskatchewan do not give us the right to produce and will require conversion to a lease prior to the expiry of the permits.
 
On May 27, 2011, we received approval for the third and final possible one-year extensions to May 31, 2012.  We are also in discussion with the crown to convert these permits to licenses under the 1969 regulations and then to lease prior to the expiry of these permits.  Currently, the Company is working with the regulators to assess an issue relating to the re-abandonment of early exploration core holes.   It is possible that the outcome of such assessment could result in cancellation of the permits if the Company does not comply with the governing regulations.   Further, if the Company cannot remediate these core holes to industry and regulatory standards, our ability to commercially develop the Axe Lake reservoir may be limited.

Certain First Nations and Metis people have treaty and aboriginal rights, and claim aboriginal title, in relation to our permit and lease lands in Alberta and Saskatchewan and other lands that are potentially affected by our activities.   The Governments of Canada, Alberta and Saskatchewan have a duty to consult with those aboriginal people in relation to actions and decisions which may impact those rights and claims and, in certain cases, have a duty to accommodate their concerns.  These duties have the potential to adversely affect our ability to obtain permits, leases, licenses and other approvals, or the terms and conditions of those approvals, which could adversely impact our progress and ability to explore and develop our properties.
 
Abandonment and Reclamation Obligations

We are responsible for compliance with terms and conditions of environmental and regulatory approvals and all laws and regulations regarding the abandonment of a project and reclamation of its lands at the end of its economic life, which abandonment and reclamation costs may be substantial. A breach of such approvals or laws may result in the issuance of remedial orders, the suspension of approvals, the seizure of posted security or the imposition of fines and penalties, including an order for cessation of operations at the site until satisfactory remedies are made. All delineation wells are abandoned and reclaimed immediately and these costs are included with our exploration costs incurred. Our estimated abandonment and reclamation costs could change as the reclamation requirements will be a function of regulations in place at the time. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates and changes in the estimated timing of abandonment. In the future, we may determine it prudent or be required by applicable regulatory approvals or laws to establish and fund one or more reclamation funds to provide for payment of future abandonment and reclamation costs.

We record the fair value of a liability for an asset retirement obligation when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. The legal obligation to perform the asset retirement activity is unconditional even though uncertainty may exist about the timing and/or method of settlement that may be beyond the Company’s control. This uncertainty about the timing and/or method of settlement is factored into the measurement of the liability when sufficient information exists to reasonably estimate the fair value. The amount of asset retirement obligation recorded reflects the expected costs, taking into account the probability of particular scenarios. The difference between the upper end of the range of these assumptions and the lower end of the range can be significant, and consequently changes in these assumptions could have a material effect on the fair value of asset retirement obligations and future losses in a period of change. 
 
If the Company is unable to re-abandon the early exploration core holes to industry and regulatory standards, it could result in the cancellation of permits or limit our ability to develop the reservoir.
 
If we fail to maintain effective internal control over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act of 2002, the price of our common shares may be affected

We are required to maintain effective internal control over financial reporting under the Sarbanes-Oxley Act of 2002 and related regulations. Any material weakness in our internal control over financial reporting that needs to be addressed, disclosure of management’s assessment of our internal control over financial reporting, or disclosure of our public accounting firm’s report on internal control over financial reporting that reports a material weakness in our internal control over financial reporting may reduce the price of our common shares.
  
The restatement of our consolidated financial statements may result in litigation and government enforcement actions

We have restated our consolidated financial statements and other financial information for the years ended April 30, 2008 and 2007 and the interim periods from July 31, 2008 through January 31, 2009 primarily with respect to the accounting treatment of our August 2006 acquisition of a non-controlling interest (35.92%) of OQI Sask which together with our 64.08% interest resulted in a 100% interest in OQI Sask.  We have also restated our consolidated financial statements and other financial information for the interim period ended July 31, 2009 with respect to accounting for stock-based compensation.  The restatement of our prior financial statements may expose us to risks associated with litigation, regulatory proceedings and government enforcement actions, including the risk that the SEC may disagree with the manner in which we have accounted for and reported the financial impact of the restatement which could result in the Company having to further restate its prior financial statements, amend prior filings with the SEC, or take other actions not currently contemplated.

In addition, securities class action litigation has often been brought against companies who have been unable to provide current public information or who have restated previously filed financial statements.  Such litigation is complex and could result in substantial costs, divert management’s attention and resources, and harm our business, financial condition and results of operations.

Due to our history of operating losses, we are uncertain that we will be able to maintain sufficient cash to accomplish our business objectives

The consolidated financial statements have been prepared assuming that we will continue as a going concern. During the fiscal years ended April 30, 2011 and 2010 we suffered net losses of $316 million and $64 million, respectively. At April 30, 2011, there was stockholders’ equity and working capital of $140 million and $4 million, respectively. There is no assurance that we can generate net income, generate revenues or successfully explore and exploit our properties.

Significant amounts of capital will be required to explore and develop our permit lands in Saskatchewan and Alberta and our oil sands exploration licenses in Saskatchewan.  Our reservoir development and exploration activities  over the next few months will be focused on preparing to execute the SAGD pilot at Axe Lake and on designing and executing our Wallace Creek seismic program.  To secure the financing necessary for such activities, we intend to conduct the Rights Offering.  There is no assurance that the Rights Offering will generate the additional capital necessary to finance these activities.  Nor can we assure you that the sale of additional equity capital, borrowing funds or selling a portion of our interest in our assets can be successfully completed. Finally, there is no assurance that the Rights Offering or any additional equity capital or borrowing required will be obtainable on terms acceptable to us, if at all. Failure to obtain such additional financing could result in delays or indefinite postponement of further exploration and development of our projects. In particular, if the Rights Offering is not successful, our ability to conduct our operations will be significantly constrained, and we may need to cease our exploration and development activities altogether.  Equity financing, if available, may result in substantial dilution to existing stockholders.
 
As a result of these risks we have concluded there is significant doubt related to our ability to continue as a going concern.  Management anticipates that the Company will be able to fund its activities at a reduced level through January 2012 with its cash and cash equivalents as at April 30, 2011.  Our financial statements do not include any adjustments relating to the recoverability and classification of assets or the amounts and classification of liabilities that might be necessary should we become unsuccessful in implementing these plans.

The impact of disruptions in the global financial and capital markets on our ability to obtain financing
 
The market events and conditions that transpired in 2008 and 2009, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have, among other things, caused significant volatility in commodity prices.  These events and conditions caused a loss of confidence in the broader U.S. and global credit and financial markets and resulted in the collapse of, and government intervention in, numerous major banks, financial institutions and insurers, and created a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially.  These factors have negatively impacted enterprise valuations and have impacted the performance of the global economy.  Although credit markets, equity markets, commodity markets and the United States and global economies have somewhat stabilized (and in some instances experienced substantial recoveries), some prominent government officials, economists and market commentators have expressed concerns regarding the durability of the recovery over the near and medium term, particularly as the fiscal stimulus that was utilized by the world's governments to combat the global financial crises is withdrawn over time in the coming months and years.

Although we expect to meet our near term liquidity needs with our working capital on hand, we will continue to need further funding to achieve our business objectives. In the past, the issuance of equity securities has been the major source of capital and liquidity for us. The recent conditions in the global financial and capital markets have limited the availability of this funding. If the disruptions in the global financial and capital markets continue, debt or equity financing may not be available to us on acceptable terms, if at all. If we are unable to fund future operations by way of financing, including public or private offerings of equity or debt securities, our business, financial condition and results of operations will be adversely impacted.  Additionally, these factors, as well as other related factors, may cause decreases in asset values that are deemed to be other than temporary, which may result in impairment losses.
 
 
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Status and Stage of Reservoir Test Program

The reservoir test program is currently at the early stages of its planned implementation schedule. There is a risk that the program will not be completed on time or on budget or at all. Additionally, there is a risk that the program may have delays, interruption of operations or increased costs due to many factors, including, without limitation: breakdown or failure of equipment or processes; construction performance falling below expected levels of output or efficiency; design errors; challenges to, or inability to access in a timely or economic fashion; contractor or operator errors; non-performance by third-party contractors; labour disputes, disruptions or declines in productivity; increases in materials or labour costs; inability to attract sufficient numbers of workers; delays in obtaining, or conditions imposed by, regulatory approvals; changes in program scope; violation of permit requirements; disruption in the supply of energy; transportation accidents, disruption or delays in availability of transportation services or adverse weather conditions affecting transportation; unforeseen site surface or subsurface conditions; and catastrophic events such as fires, earthquakes, storms or explosions.
 
Our business plan is highly speculative and its success depends, in part, on exploration success on the permit, license and lease lands and the development of identified discoveries

Our business plan is focused primarily on the exploration for and development of oil sands deposits on our permitted, licensed and leased lands in the Provinces of Saskatchewan and Alberta.

Exploration itself is highly speculative. We are subject to all of the risks inherent in oil sands exploration and development, including identification of commercial projects, selection of optimal recovery processes for successful production, operation and revenue uncertainties, market sizes, profitability, market demand, commodity price fluctuations and the ability to raise further capital to fund activities. There can be no assurance that we will be successful in overcoming these risks.  
 
Access to Infrastructure

Production from our lease, license, and permit lands will depend upon certain infrastructure that does not currently exist in close proximity to where we currently anticipate to locate our initial projects and such infrastructure, if put in place, may be operated by others. Such infrastructure will include, without limitation, the following: pipelines for the transportation of natural gas and certain feedstock to our site and the transportation of bitumen and other petroleum products we produce to upgrading facilities and markets for sale; and electricity transmission and distribution systems for the provision of electricity. The failure to have any of this infrastructure in place on economic terms will negatively impact the operation of any potential commercial project and will adversely affect the ability to convert our resources into reserves.
 
Access to Markets

By the time we have a commercial project ready for start-up, it will likely have been preceded by other projects which began development at an earlier time and are more advanced in terms of production. As a result, preferred markets for our products may have already been taken up or upgraders or refiners may lack sufficient capacity to process our products in a timely or economic fashion.

Location of Discovery Areas

With the exception of Eagles Nest, all of Oilsands Quest’s prospective areas are located east of what has to date been considered the established bitumen resources that are exploitable by in situ production techniques in the Athabasca oil sands area.   Similar to some other bitumen accumulations within the eastern portion of Alberta, the Axe Lake, Raven Ridge and portions of the Wallace Creek areas lack a distinct overlying shale formation. The absence of this may preclude the use of certain high-pressure in situ recovery methods, but the quality of the reservoirs and high bitumen saturations present at the Axe Lake Raven Ridge and Wallace Creek areas provide the potential for extraction using a number of recovery methods, including SAGD.  However, there can be no assurances that any such recovery method will be successful in enabling us to recover significant volumes of bitumen from our reservoirs.  See "-- Status and Stage of Reservoir Test Program".

Independent Reviews

Although third parties have prepared reviews, reports and projections relating to the evaluation, viability and expected performance of our resources and plans for development thereof, no assurance can be given that these reports, reviews and projections and the assumptions on which they are based will, over time, prove to be accurate.

Personnel

The design, development and construction of the reservoir test program and any subsequent pilot and commercial projects will require experienced executive and management personnel and operational employees and contractors with expertise in a wide range of areas. No assurance can be given that all of the required personnel and contractors with the necessary expertise will be available. Should other oil sands projects or expansions proceed in the same time frame as Oilsands Quest programs and projects, we will have to compete with these other projects and expansions for qualified personnel and such competition may result in increases to compensation paid to such personnel or in a lack of qualified personnel. Any inability of Oilsands Quest to attract and retain qualified personnel may delay or interrupt the design, development and construction of, and commencement of operations at, the reservoir test program and any subsequent pilot and commercial projects. Sustained delays or interruptions could have a material adverse effect on the financial condition of Oilsands Quest.
 
Operational Hazards

Our exploration and development activities are subject to the customary hazards of operation in remote areas, such as fires, explosions, gaseous leaks, migration of harmful substances, blowouts and spills. A casualty occurrence might result in the loss of equipment or life, as well as injury, property damage or other liability. While we maintain limited insurance to cover current operations, our property and liability insurance may not be sufficient to cover any such casualty occurrences or disruptions. Equipment failures could result in damage to our facilities and liability to third parties against which we may not be able to fully insure or may elect not to insure because of high premium costs or for other reasons. Our operations could be interrupted by natural disasters such as forest fires or other events beyond our control. Losses and liabilities arising from uninsured or under-insured events could have a material adverse effect on our business, our financial condition and results of our operations.

Competitive Risks

The Canadian and international petroleum industry is highly competitive in all aspects, including the exploration for, and the development of, new sources of supply, the acquisition of oil interests and the distribution and marketing of petroleum products.

The petroleum industry also competes with other industries in supplying energy, fuel and related products to consumers.  Some of these industries benefit from lighter regulation, lower taxes and subsidies.  In addition, certain of these industries are less capital intensive.
 
A number of competing companies are engaged in the oil sands business and are actively exploring for and delineating their resource bases. Some of our competitors have announced plans to begin production of synthetic crude oil, or to expand existing operations. If these plans are effected, they could materially increase the supply of synthetic crude oil and other competing crude oil products in the marketplace and adversely affect plans for development of our lands.

The Loss of current management may make it difficult for us to operate

Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of our management and directors. The Company’s success is dependent upon its management and key personnel. We do not maintain key-man insurance for any of our employees.  The unexpected loss or departure of any of our key officers and employees could be detrimental to our future success.

Fluctuations in U.S. and Canadian dollar exchange rates may have a material adverse impact

Commodity prices and costs related to the Company’s activities, if and when applicable, will generally be based on a U.S. dollar market price. Fluctuations in the U.S. and Canadian dollar exchange rate may cause a negative impact on revenue and costs and could have a material adverse impact on the Company.
 
THE BUSINESS OF OIL SANDS EXPLORATION IS SUBJECT TO MANY RISKS

Nature of Oil Sands Exploration and Development

Oil sands exploration and development are very competitive and involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. As with any petroleum property, there can be no assurance that commercial deposits of bitumen will be produced from our permit lands in Saskatchewan and Alberta, oil sands exploration licenses in Saskatchewan, or the Eagles Nest Prospect.
 
 
12

 
 
Furthermore, the marketability of any resource will be affected by numerous factors beyond our control. These factors include, but are not limited to, market fluctuations of prices, proximity and capacity of pipelines and processing equipment, equipment and labour availability and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, land tenure, allowable production, importing and exporting of oil and gas, land use and environmental protection). The extent of these factors cannot be accurately predicted, but the combination of these factors may result in us not receiving an adequate return on invested capital.

The viability of our business plan, business operations, and future operating results and financial condition are and will be exposed to fluctuating prices for oil, natural gas, oil products and chemicals

Prices of oil, natural gas, oil products and chemicals are affected by supply and demand, which can fluctuate significantly.  Factors that influence supply and demand include operational issues, natural disasters, weather, political instability, or conflicts, economic conditions and actions by major oil-exporting countries.  Price fluctuations can have a material effect on our ability to raise capital and fund our exploration activities, our potential future earnings, and our financial condition.  For example, in a low oil and gas price environment oil sands exploration and development may not be financially viable or profitable.  Prolonged periods of low oil and gas prices, or rising costs, could result in our exploration projects being delayed or cancelled, as well as the impairment of certain assets.

Reserves and Resources

We have not yet established any reserves. There are numerous uncertainties inherent in estimating quantities of bitumen resources and reserves, including many factors beyond our control, and no assurance can be given that the recovery of bitumen will be realized. In general, estimates of resources and reserves are based upon a number of factors and assumptions made as of the date on which the resources and reserves estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from estimated results. All such estimates are, to some degree, uncertain and classifications of resources and reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of reserves and resources, the classification of such resources and reserves based on risk of recovery, prepared by different engineers or by the same engineers at different times, may vary substantially.

Investors are cautioned not to assume that all or any part of a resource is economically or legally extractable.
 
ENVIRONMENTAL AND REGULATORY COMPLIANCE MAY IMPOSE SUBSTANTIAL COSTS ON US

Our operations are or will be subject to stringent federal, provincial and local laws and regulations relating to improving or maintaining environmental quality. Environmental laws often require parties to pay for remedial action or to pay damages regardless of fault. Environmental laws also often impose liability with respect to divested or terminated operations, even if the operations were terminated or divested many years ago.

Our exploration activities and drilling programs are or will be subject to extensive laws and regulations governing prospecting, development, production, exports, taxes, labor standards, occupational health, waste disposal, land use, protection and remediation of the environment, protection of endangered and protected species, operational safety, toxic substances and other matters. Exploration and drilling is also subject to risks and liabilities associated with pollution of the environment and disposal of waste products. Compliance with these laws and regulations will impose substantial costs on us and will subject us to significant potential liabilities.  In addition, should there be changes to existing laws or regulations, our competitive position within the oil sands industry may be adversely affected, as many industry players have greater resources than we do. 

We are required to obtain various regulatory permits and approvals in order to explore and develop our properties.  The absence of a distinct overlying shale formation on portions of our leases may make it more difficult or costly to obtain regulatory approvals.  There is no assurance that regulatory approvals for exploration and development of our properties will be obtained at all or with terms and conditions acceptable to us.
 
Third Party Liability and Environmental Liability

The Company’s operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damage. We could be liable for environmental damages caused by previous owners. As a result, substantial liabilities to third parties or governmental entities may be incurred, and the payment of such liabilities could have a material adverse effect on our financial condition and results of operations. The release of harmful substances in the environment or other environmental damages caused by our activities could result in us losing our operating and environmental permits or inhibit us from obtaining new permits or renewing existing permits. We currently have a limited amount of insurance and, at such time as we commence additional operations, we expect to be able to obtain and maintain additional insurance coverage for our operations, including limited coverage for sudden environmental damages, but we do not believe that insurance coverage for environmental damage that occurs over time is available at a reasonable cost. Moreover, we do not believe that insurance coverage for the full potential liability that could be caused by environmental damage is available at a reasonable cost. Accordingly, we may be subject to liability or may lose substantial portions of our properties in the event of certain environmental damage. The Company could incur substantial costs to comply with environmental laws and regulations which could affect our ability to operate as planned.

Emissions Regulations

Development of our assets is expected to result in the emission of greenhouse gases ("GHGs") and other pollutants.

On April 26, 2007, the Government of Canada announced a Regulatory Framework for Air Emissions and Other Measures to Reduce Air Emissions, or the “Framework”, which outlined proposed new requirements governing the emission of GHGs and other industrial air pollutants, including sulphur oxides, volatile organic compounds, particulate matter and possibly additional sector-specific pollutants in accordance with the Notice. The Framework introduced further, but not full, detail on new GHG and industrial air pollutant limits and compliance mechanisms that will apply to various industrial sectors, including oil sands extraction, starting in 2010. The Framework proposed GHG emission-intensity reduction targets of six percent per year from 2007 to 2010, followed by annual reductions of two percent through 2015. On March 10, 2008, the Canadian Federal Government elaborated on the Framework with the release of its "Turning the Corner" policy document. It was contemplated that new regulations would take effect January 1, 2010. Draft regulations were expected to be available for public comment in the Fall of 2008 but have not yet been released, and it is not known when they will be released or implemented.

The proposed regulatory framework provides that existing oil sands facilities in operation by 2004 will be subject to an 18% emission intensity reduction requirement commencing in 2010, with 2% additional annual reductions thereafter until 2020. Facilities commissioned between 2004 to 2011 or facilities existing prior to 2004 which between 2004 and 2011 have had a major expansion resulting in an increase of 25% or more in physical capacity or which undergo a significant change to processes will be exempt from the 2010 emissions intensity reduction target of 18% but will have to report their emissions each year.  After their third year of operation they will be required to reduce their emissions intensity by 2% annually from a baseline emissions standard which is to be determined by reference to a sector-specific cleaner-fuel standard. For oil sands facilities, it is contemplated that there will be specific cleaner-fuel standards based on the use of natural gas for each of mining, in situ and upgrading. However, an incentive to deploy carbon capture and storage (CCS) has been included in the proposed regulatory framework. CCS is where carbon dioxide is separated from a facility’s process or exhaust gas emissions before they are emitted, transferred from the facility to a suitable storage location, and injected into deep underground geological formations and monitored to ensure they do not escape into the atmosphere. If a facility commissioned between 2004 and 2011 is built such that it is able or ready to undertake CCS, then it will be exempt from the cleaner-fuel standard until 2018 and it will only be required to reduce its emission-intensity by 2% per year from its actual emissions. In situ oil sands projects and oil sands upgraders built after 2011 must have their GHG emissions profiles by 2018 equivalent to that of facilities employing CCS technology.

The proposed regulatory framework further encourages widespread use of CCS by 2018 by crediting emitters that make use of CCS technology for investments in pre-certified CCS projects up to 100% of their regulatory obligations through 2017.
 
The proposed compliance mechanisms include an emissions credit trading system for GHGs and certain industrial air pollutants, and several options for companies to choose among to meet GHG emission intensity reduction targets and encourage the development of new emission reduction technologies, including the option of making payments into a technology fund, an emissions and offset trading system, limited credits for emission reductions created between 1992 and 2006, and international emission credits under the clean development mechanism under the Kyoto Protocol for up to 10% of each firm’s regulatory obligation.

On January 30, 2010, the Government of Canada submitted to the United Nations Framework on Climate Change a non-legally binding commitment under the Copenhagen Accord to reduce Canada’s emissions of GHGs by 17% from 2005 emission levels.  This is a significant change from previous international commitments of a 20% reduction in emissions from 2006 levels by 2020.  The Government of Canada signaled that a new proposed national emission reduction target is to be met.  It is not known whether the previously announced proposed regulatory Framework will proceed or be replaced with a new regulatory framework.  We believe that it is reasonably likely that new federal legislation requiring emissions reductions similar to the Framework will be enacted in Canada around the same time as similar legislation is enacted in the United States.  We also believe that such federal legislation could have a material effect on the development of our assets.
 
 
13

 
 
On April 20, 2007, the Government of Alberta passed the Climate Change and Emissions Management Amendment Act establishing a framework for GHG emission reductions. The Specified Gas Emitters Regulation created under the Act requires facilities that emit more than 100,000 tonnes of carbon dioxide equivalent CO2e annually to reduce their emission intensity starting July 1, 2007 by 12 percent from 2003-2005 levels. New facilities in operation less than eight years will be required to achieve these reductions over the fourth to eighth years of operation.
 
These obligations may be met by in-house reductions, the purchase of certain emission reductions or offset credits or a contribution of $15 per tonne of GHG emissions to a provincial technology fund.  We believe that the costs of complying with the Regulation could be material should our operations grow to emit more than 100,000 tonnes CO2e of annually.

On May 20, 2010, the Saskatchewan Legislature passed The Management and Reduction of Greenhouse Gases Act but has yet to proclaim it a law.  The Act sets a policy and regulatory framework for reducing GHG emissions in Saskatchewan and sets a provincial target of a 20% reduction in GHG emissions from 2006 levels by 2020.   The specific GHG emission reduction requirements, and the industries required to meet those reductions, as well as details on the methods by which reductions may be achieved, are to be set by further regulations.  It is expected that facilities which emit 50,000 tonnes of  CO2e  per year will be required to reduce GHG emissions by 2% per year over a baseline emission level from 2010 to 2019.  New facilities constructed after 2006 that have emissions in excess of 50,000 tonnes of CO2e annually will also be required to achieve emission reduction targets.

Future legislated GHG and industrial air pollutant emission reduction requirements and emission intensity requirements, or GHG and industrial air pollutant emission reduction or intensity requirements in future regulatory approvals, may require the restriction or reduction of GHG and industrial air pollutant emissions or emissions intensity from our future operations and facilities, payments to technology funds or purchase of emission reductions or offset credits. The reductions may not be technically or economically feasible for our operations and the failure to meet such emission reduction or emission intensity reduction requirements or other compliance mechanisms may materially adversely affect our business and result in fines, penalties and the suspension of operations. As well, equipment from suppliers which can meet future emission standards may not be available on an economic basis and other compliance methods of reducing emissions or emission intensity to levels required in the future may significantly increase our operating costs or reduce output. Emission reductions or offset credits may not be available for acquisition or may not be available on an economic basis. There is also the risk that provincial or federal governments, or both, could pass legislation which would tax such emissions.

American climate change legislation could negatively affect markets for crude and synthetic crude oil
 
Environmental legislation regulating carbon fuel standards in jurisdictions that import crude and synthetic crude oil in the United States could result in increased costs and/or reduced revenue.  For example, both California and the United States federal governments have passed legislation which, in some circumstances, considers the lifecycle greenhouse gas emissions of purchased fuel and which may negatively affect our business, or require the purchase of emissions credits, which may not be economically feasible.

Proposed Export Restrictions

The Government of Canada previously announced that it will review and may restrict exports from Canada of bitumen and bitumen blend products to countries with less stringent GHG emissions limits than those which apply in Canada.  Any export restrictions imposed with respect to bitumen or bitumen blend products may restrict the markets in which the Company may sell its bitumen and bitumen blend products, which may result in the Company receiving a lower price for its production, if and when applicable. 
 
 Royalty Regime

Any development of our resource assets will be directly affected by the royalty regime applicable. The economic benefit of future capital expenditures for the project is, in many cases, dependent on a satisfactory fiscal regime (royalties and taxes). The Government of Saskatchewan receives royalties on production of oil, gas and other minerals from lands in which it owns the relevant mineral rights. The Government of Saskatchewan owns the relevant mineral rights on the OQI Saskatchewan lands. The current royalty regime relating to bitumen production in Saskatchewan provides for a royalty of 1% of gross bitumen revenue and is payable until the project has recovered specified allowed costs. Once such allowed costs are recovered, a net royalty of 20% of operating income is payable.

The Government of Alberta receives royalties on production of natural resources from lands in which it owns the mineral rights. On October 25, 2007, the Government of Alberta announced a new royalty regime. The new regime introduced new royalties for conventional oil, natural gas and bitumen that became effective January 1, 2009 and are linked to commodity prices and production levels and apply to both new and existing oil sands projects and conventional oil and gas activities.

Under the new regime, the Government of Alberta increased its royalty share from oil sands production by introducing price-sensitive formulas which are applied both before and after specified allowed costs have been recovered. The gross royalty starts at one percent of gross bitumen revenue and increased, for every dollar that world oil price, as reflected by the West Texas Intermediate (“WTI”) crude oil price, is above CDN$120 per barrel or higher. The net royalty on oil sands starts at 25 percent of net bitumen revenue and increases for every dollar the WTI crude oil price is above CDN$55 per barrel to 40 percent when the WTI crude oil price is CDN$120 per barrel or higher. Prior to the payout of specified allowed costs, including certain exploration and development costs, operating costs and a return allowance, the gross royalty is payable. Once such allowed costs have been recovered, a royalty of the greater of: (a) the gross royalty and (b) the net royalty is payable. The Government of Alberta has announced that it intends to review and, if necessary, revise current rules and enforcement procedures with a view to clearly defining what expenditures will qualify as specified allowed costs.

There can be no assurance that the Governments of Alberta or Saskatchewan or the Government of Canada will not adopt a new fiscal regime or otherwise modify the existing fiscal regime (royalties and taxes) governing oil sands producers in a manner that could materially affect the financial prospects and results of operations of oil sands developers and producers in Alberta and Saskatchewan.

Title Risks

Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada, and both First Nations and Metis peoples have commenced and could in the future commence actions claiming, among other things, aboriginal title to our Alberta and Saskatchewan lands and other lands located in the vicinity of those lands.  First Nations and Metis peoples have also stated that governments have not complied with their constitutionally mandated duty to consult with and accommodate First Nations and Metis in relation to decisions that enabled us to acquire and that are required to enable us to develop our Saskatchewan and Alberta lands, and have commenced and could in the future commence actions asserting such claims.  Certain of these claims, if successful, could have a significant adverse effect on our ability to conduct our business, including impacting our ability to explore and develop by impacting our ability to obtain, retain or exercise rights under permits, leases, licenses and other approvals, and the terms of such approvals.

RISKS RELATING TO OUR COMMON STOCK

We have numerous outstanding options, warrants and commitments to issue shares, which may adversely affect the price of our common stock 
 
As of June 30, 2011, we have reserved 21,765,744 shares of our common stock for issuance upon exercise of outstanding options under plans at prices as low as $0.53 per share. The Company has also reserved 1,388,567 shares of common stock to be issued on settlement of debt of a former subsidiary. Pursuant to the Reorganization Agreement with OQI Sask dated August 14, 2006, the Company is required to issue up to 65,887,603 shares of its common stock for all of the OQI Sask Exchangeable Shares (including warrants and options to acquire OQI Sask Exchangeable Shares) issued upon the closing (the “Reorganization”). As of June 30, 2011, 46,346,867 OQI Sask Exchangeable Shares have already been exchanged for shares of our common stock and up to an additional 19,540,736 OQI Sask Exchangeable Shares may be exchanged for common stock. Any sale into the public market of our common stock purchased privately at prices below the current market price could be expected to have a depressive effect on the market price of our common stock.

Future sales of our common stock may cause our stock price to decline

Our stock price may decline due to future sales of our shares or the perception that such sales may occur.   The Board of Directors of the Company has discretion to determine the issue price and the terms of issue of shares of our common stock.  Such future issuances may be dilutive to investors.  Holders of shares of common stock have no pre-emptive rights under our articles of incorporation to participate in any future offerings of securities.
 
 
14

 
 
If we issue additional shares of common stock in private financings under an exemption from the registration requirements, then those shares will constitute “restricted shares” as defined in Rule 144 under the Securities Act of 1933 (the “1933 Act”). The restricted shares may only be sold if they are registered under the 1933 Act, or sold under Rule 144, or another exemption from registration under the 1933 Act.
 
Some of our outstanding restricted shares of common stock are either eligible for sale pursuant to Rule 144 or have been registered under the 1933 Act for resale by the holders. We are unable to estimate the amount, timing, or nature of future sales of outstanding common stock. Sales of substantial amounts of our common stock in the public market may cause the stock’s market price to decline.

Dividend Policy

The Company did not declare or pay cash or other dividends on its common stock during the past three fiscal years. Payment of dividends by the Company will depend upon the Company’s financial condition, results of operations, capital requirements and such other factors as the Board of Directors of the Company may deem relevant.
 
Our stock price can be extremely volatile

The trading price of our common stock has been and could continue to be subject to wide fluctuations in response to announcements of our business developments or those of our competitors, world commodity prices, periodic updates on our resource assessments, quarterly variations in operating results, and other events or factors. In addition, stock markets have experienced extreme price volatility in recent years. This volatility has had a substantial effect on the market prices of companies, at times for reasons unrelated to their operating performance. Such broad market fluctuations may adversely affect the price of our common stock.

Issuance of Preferred Stock and Our Anti-Takeover Provisions Could Delay or Prevent a Change in Control and May Adversely Affect our Common Stock

We are authorized to issue 10,000,000 shares of preferred stock which may be issued in series from time to time with such designations, rights, preferences and limitations as our Board of Directors may determine by resolution. The rights of the holders of our common stock will be subject to and may be adversely affected by the rights of the holders of any of our preferred stock that may be issued in the future. Issuance of a new series of preferred stock, or providing desirable flexibility in connection with possible acquisitions and other corporate purposes, could make it more difficult for a third party to acquire, or discourage a third party from acquiring our outstanding shares of common stock. On October 30, 2006, the Company’s shareholders approved staggered terms for the Board of Directors, which could make removal of the Board of Directors more difficult for a third party. The Class A directors will serve until the annual meeting in 2012, the Class B directors until the annual meeting in 2011, and the Class C directors until the annual meeting in 2010, or each until their successors are duly elected or appointed or until their earlier death, resignation or removal. Each term for directors is three years. In addition to a staggered board, our Board of Directors adopted a stockholders rights plan in March 2006 and reserved 250,000 shares of Series A Junior Participating Preferred Stock. This stockholders rights plan could have the effect of discouraging, delaying or preventing an acquisition.

Item 1B.  UNRESOLVED STAFF COMMENTS

None.

Item 2.  PROPERTIES AND STATEMENT OF OIL AND GAS INFORMATION
 
Pursuant to NI 51-101 the Company is required to include 100% of the oil and gas interests owned by OQI Sask and Township in the Company’s oil and gas disclosure. No information is provided in respect of reserves attributable to the Company as no reserves have been attributed to any of the Company’s properties to date and, accordingly, the Company has no production or related future net revenue.

Oil and Gas Properties and Wells

Oilsands Quest currently holds permits, license and lease rights for oil sands exploration and development to 405,924 acres of land in Saskatchewan and Alberta, Canada.   We also hold 489,730 acres of oil shale rights in Saskatchewan.  However, we plan to relinquish our rights to 121,306 acres in August 2011.
 
MAP 1
 
 
 
15

 
 
MAP 2
 
 Saskatchewan, Canada Oil Sands Rights

Oil Sands Permits and Licenses

Block
   
Description
   
OQI
Working
Interest
   
Gross/Net
Acres
   
Permit
Date
   
Term
Oil Sands Permit1
                             
                               
PS00208
   
Township 94, Ranges 22, 23, 24, 25 (partial), West of the 3rd Meridian
      100 %
 
 
81,012
   
Jun 1/04
   
5 yrs
PS00210
   
Township 95, Ranges 22, 23, 24, 25 (partial), West of the 3rd Meridian
      100 %
 
 
79,620
   
Jun 1/04
   
5 yrs
                               
Oil Sands Licenses2
                             
OSL00001
   
Township 91, Ranges 21 (partial), 22 (partial), West of the 3rd Meridian
    100 %
 
 
23,040
   
Aug 13/07
   
5 yrs
OSL00002
   
Township 90, Ranges 23 (partial), 24 (partial), 25 (partial), West of the 3rd Meridian
    100 %
 
 
23,040
   
Aug 13/07
   
5 yrs
OSL00003
   
Township 91, Range 23, West of the 3rd Meridian
    100 %
 
 
23,040
   
Aug 13/07
   
5 yrs
OSL00005
   
Township 90, Range 26 (partial), West of the 3rd Meridian
    100 %
 
 
21,120
   
Aug 13/07
   
5 yrs
OSL00006
   
Township 91, Range 25 (partial), West of the 3rd Meridian
    100 %
 
 
19,680
   
Aug 13/07
   
5 yrs
Total
               
 270,552
           

Oil Sands Permits

The permits were granted by the Province of Saskatchewan in 2004 under the Oil Shale Regulations, 1964 as amended, revised or substituted from time to time, for a term of five years. The permits provide for the right to explore and work the permit lands but not to remove, produce or recover, except for test purposes, oil products until a lease, pursuant to these regulations has been granted. The term of the permits may be extended for up to three one-year extensions subject to regulatory approvals, as required. The Saskatchewan permit lands comprise an area totaling 160,632 acres.

The permits are subject to annual rental payments and certain levels of expenditures annually pursuant to the terms of the permits and government regulations. On May 7, 2007, the province updated the Oil Shale Regulations, 1964 requiring an increase to annual rentals of $0.11 ($0.10 CDN) per acre for the remaining term of the permits. The required exploration expenditures to hold the permits were also increased to $0.85 ($0.81 CDN) per acre for each of the remaining years of the permits and $1.28 ($1.21 CDN) per acre for each year that the permits are extended. OQI is in compliance with the current expenditure requirements.

 

1 The Axe Lake area covers a portion of these permits (see details in "Axe Lake Area" above).  The Company applied for and received the third and final one year extension of these permits to May 31, 2012.  We intend to convert these permits to leases by May 31, 2012.
2 The Oilsands Licenses will be relinquised on August 12, 2011.
 
 
16

 
 
Axe Lake Area

The Axe Lake area covers approximately 65 sections (65 square miles) of Permits PS00208 and PS00210 (100% Oilsands Quest) located in the north half of Township 94 and the south half of Township 95, Ranges 24 and 25 West of the 3rd Meridian.
 
Oil Sands Licenses

The licenses provide for the exclusive right to search for oil sands on the lands granted and to win, recover, extract, carry off, dispose of and sell the oil sands products found on the license lands.
 
 The oil sands licenses provide the opportunity to convert up to 100% of the licenses to a production lease on the basis of one section of land for every well that intersects an oil sands zone. Licenses require annual rental payments of $0.75 ($0.71 CDN) per acre. The Company has paid all required annual rental payments for the licenses granted.

The Company intends to relinquish the five oil sands licenses described above on their expiry date of August 12, 2011 due to the fact these licenses have low prospectivity.

Alberta, Canada Oil Sands Rights
Block
   
Description
   
OQI
Working
Interest
   
Gross/Net
Acres
   
Grant
Date
   
Term
Oil Sands Permits
                             
Raven Ridge
                             
  7007030939    
North half of the Township 92, Range 1, West of the 4th Meridian
    100 %    
11,386
   
Mar 22/07
   
5 yrs
  7007030940    
East half of Township 93 and 94, Range 1, West of the 4th Meridian
    100 %    
22,773
   
Mar 22/07
   
5 yrs
  7007030941    
West half of Township 93 and 94, excluding sections 33 and 34, Range 1, West of the 4th Meridian
    100 %    
21,508
   
Mar 22/07
   
5 yrs
  70060800983    
South half of the Township 92, Range 1, West of the 4th Meridian
    100 %    
11,386
   
Aug 10/06
   
5 yrs
Wallace Creek
                             
  7008010298    
Township 96, Range 1, West of the 4th Meridian
    100 %    
22,773
   
Jan 24/08
   
5 yrs
  7008010299    
Township 96, Range 2, West of the 4th Meridian
    100 %    
22,773
   
Jan 24/08
   
5 yrs
Oil Sands Lease
                             
Eagles Nest
                             
  7405080355    
Township 101, Range 13, West of the 4th Meridian
    100 %    
22,773
   
Aug 25/05
   
15 yrs
Total
               
135,372
           

Oil Sands Permits

Raven Ridge

During the year ended April 30, 2007, the Company acquired four oil sands permits totaling 67,053 acres in a public offering of Crown Oil Sands. The permits were granted by the Province of Alberta under the terms of the Mines and Minerals Act, Alberta. The permits provide the opportunity to convert up to 100% of the permits to a production lease following the completion of specified work requirements which requires the drilling of at least one delineation core test well per section over the permit term. Permits are granted for a five-year primary term and require annual rental payments of $1.50 ($1.42 CDN) per acre. Following the evaluation of the 2007/2008 Exploration program, we announced a discovery in the Raven Ridge area. The area of the resource estimate within the Raven Ridge covers approximately ten sections located within Townships 93 and 94, Range 1W4 in Alberta, directly to the east of Axe Lake area.
 
Wallace Creek

On January 23, 2008, the Company acquired two oil sands permits totaling 45,546 acres in a public offering of Crown Oil Sands Rights. The permits were granted by the Province of Alberta under the terms of the Mines and Minerals Act, Alberta. The permits provide the opportunity to convert up to 100% of the permits to a production lease following the completion of specified work requirements which requires the drilling of at least one delineation core test well per section over the permit term. Permits are granted for a five-year primary term and require annual rental payments of $1.50 ($1.42 CDN) per acre. On June 27, 2011, the Company received approval from Alberta Energy to extend the Wallace Creek permits for an additional 67 days to March 31, 2013.  This extension will allow us to have 2 full winter exploration seasons in which to complete more exploratory seismic and drilling prior to any applications for conversion to lease.

Oil Sands Lease

Eagles Nest

Township acquired Alberta Oil Sands Lease No. 7405080355, the “Eagles Nest”, in an Alberta Crown Sale. The lease was granted by the Province of Alberta under the terms of the Mines and Minerals Act, Alberta. The lease provides the exclusive right to drill for, win, work and recover together with the right to remove oil sands from the lease lands for a term of 15 years and for so long after that term as the lease is permitted to continue under the Mines and Minerals Act, Alberta. The annual lease rental payable to the Province of Alberta for Eagles Nest is $34,004 ($32,256 CDN) per year. The Company has paid the required annual lease rentals to maintain the lease in good standing. 

Saskatchewan, Canada Oil Shale Rights
Block
   
Description
   
OQI
Working
Interest
   
Total /
Net Acres
   
Grant
Date
   
Term
Pasquia Hills Oil Shale
                             
PS00222
   
Township 45, Ranges 1-2 (partial), West of the 3rd Meridian
    100 %    
21,120
   
Sep 7/06
   
5 yrs
PS00223
   
Townships 47-48 (partial), Ranges 3-5 (partial), West of the 3rd Meridian
    100 %    
82,560
   
Sep 7/06
   
5 yrs
PS00224
   
Townships 47-49 (partial), Ranges 3-5 (partial), West of the 3rd Meridian
    100 %    
19,840
   
Sep 7/06
   
5 yrs
PS00225
   
Townships 46-47 (partial), Ranges 5-7 (partial), West of the 3rd Meridian
    100 %    
80,000
   
Sep 7/06
   
5 yrs
PS00226
   
Townships 45-46 (partial), Ranges 5-7 (partial), West of the 3rd Meridian
    100 %    
61,436
   
Sep 7/06
   
5 yrs
PS00237
   
Township 43 (partial), Ranges 1-4 (partial), West of the 3rd Meridian
    100 %    
82,709
   
Oct 16/06
   
5 yrs
PS00238
   
Township 43 (partial), Ranges 5-6 (partial), West of the 3rd Meridian
    100 %    
58,296
   
Oct 16/06
   
5 yrs
SHP0001
   
Townships 44-45 (partial), Ranges 1-3 (partial), West of the 3rd Meridian
    100 %    
83,769
   
Aug 13/07
   
5 yrs
Total
               
489,730
           

Oil Shale Permits – Pasquia Hills Oil Shale

The oil shale permits were granted by the Province of Saskatchewan under the Oil Shale Regulations, 1964, as amended, revised or substituted from time to time for a term of five years. The permits provide for the right to explore and work the permit lands but not to remove, produce or recover, except for test purposes, oil products until a lease, pursuant to these regulations has been granted. The term of the permits may be extended for up to three one-year extensions subject to regulatory approvals, as required. The annual rental payable in advance was $0.05 ($0.05 CDN) per acre for the current (first) year. On May 7, 2007, the province updated the regulations requiring annual rentals of $0.11 ($0.10 CDN) per acre for the remaining term of the permit. The required exploration expenditures to hold the permits were also increased to $0.42 ($0.40 CDN) per acre for the second year of the permits, $0.85 ($0.81 CDN) per acre for the last three years of the permits and $1.28 ($1.21 CDN) per acre for each year that the permit is extended, as required.

 

3 The Company intends to relinquish this permit in August 2011.
 
 
17

 
 
On August 13, 2007, the Company acquired one additional oil shale exploration permit granted under the Petroleum and Natural Gas Regulations, 1969 (Saskatchewan) as amended, revised or substituted from time to time for a term of five years totaling 83,769 acres in the same area near Hudson Bay, Saskatchewan. The permits provide for the right, license, privilege and authority to explore for oil shale within the permit lands. The term of the permits may be extended for up to three one-year extensions subject to regulatory approvals, if required.  This oil shale permit was acquired under a land sale work commitment bid for the first two years of the permit. The Company bid a total work commitment of $317,908 ($301,568 CDN) to be incurred during the first two years of the permit and the permit requires a further work commitment of $0.85 ($0.81 CDN) per acre for the last three years and $1.28 ($1.21 CDN) for each extension year plus annual rental payments of $0.11 ($0.10 CDN) per acre.
The Company has paid the required annual rental payments to maintain the permits in good standing.
 
Oil and Gas Wells

The Company is an exploration and development company active in the non-conventional areas of oil sands and oil shales, exploring for commercial quantities of bitumen and kerogen. The following table sets forth the number of exploration and development wells which the Company drilled on April 30, 2011. All of the Company’s wells are located onshore, in the provinces of Saskatchewan and Alberta, Canada.  
 
      2010/2011    
Drilled to Date
(Nov.22/05 to April 30/11)
 
   
Wells
Drilled
   
Wells Drilled
   
Sections Drilled
   
Wells per
Section
 
Axe Lake Exploration
   
3
     
323
     
78
     
4.1
 
Axe Lake Development/Reservoir Test
   
0
     
26
     
n/a
     
n/a
 
Axe Lake Groundwater Monitoring
   
0
     
19
     
n/a
     
n/a
 
Saskatchewan Exploration (outside Axe Lake)
   
1
     
36
     
29
     
1.2
 
Raven Ridge Exploration
   
0
     
48
     
23
     
2.1
 
Wallace Creek Exploration
   
5
     
14
     
14
     
1.0
 
Eagles Nest Exploration
   
0
     
0
     
0
     
0.0
 
Total
   
9
     
466
     
144
     
3.2
 

 For a complete description of our most important current and likely exploration and development activities, see Part 1, Item 1. “Description of Business — Activities to Date” and “Outlook”.

Properties with No Attributed Reserves

The Company’s lands described in Part I, Item 2. “Oil and Gas Properties and Wells” and “Oil and Gas Wells” have no proved or producing reserves. The Company received the third and final possible one-year extensions on its Saskatchewan oil sands permits on May 27, 2011.  We intend to convert these permits to lease prior to May 31, 2012.

Forward Contracts

There are no hedging contracts in place.

Information Concerning Abandonment and Reclamation Costs

All delineation wells are abandoned and reclaimed immediately and these costs are included with our exploration costs incurred. As at April 30, 2011, we estimate the total undiscounted inflation – adjusted amount required to settle the asset retirement obligations in respect of the Company’s wells and facilities is approximately $44.3 million. This estimate includes the costs to re-abandon a number of core holes at Axe Lake from the Company's early exploration core hole programs. This estimate also includes the costs to reclaim the air strip, camp site, access roads and reservoir test sites which are being brought into income over a period of 5 to 30 years. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to property and equipment or exploration expense. This estimate could change as the reclamation requirements will be a function of regulatory regulations in place at the time.

Tax Horizon

No income taxes will be payable until a revenue-generating project has been identified and completed. No project has been identified at this time and no taxes will be payable in the near future.

Costs Incurred

Costs incurred by the Company on its properties during the year ended April 30, 2011 are summarized as follows (in $US, in thousands):

Property acquisition costs
 
$
438
 
Exploration costs
   
21,898
 
Development costs
   
-
 
Total
 
$
22,336
 

Production

Effective April 30, 2011, we did not have any production volumes or production revenue on any of our properties.

Item 3.  LEGAL PROCEEDINGS

On February 24, 2010, a derivative action entitled Make a Difference Foundation Inc. v. Hopkins, et al., Case No.  10-CV-00408, was filed in United States District Court for the District of Colorado by plaintiff Make a Difference Foundation, Inc.  The derivative action names the following individual defendants:  Christopher H. Hopkins, T. Murray Wilson, Ronald Blakely, Paul Ching, Brian MacNeill, Ronald Phillips, John Read, Gordon Tallman, Pamela Wallin, Thomas Milne and W. Scott Thompson.  In addition, the Company is named as a nominal defendant.  Plaintiff asserts, among other things, claims for waste and breaches of the fiduciary duty of loyalty and good faith by the defendants stemming from the Company's approval of the proposed sale of the Company's Pasquia Hills assets to Canshale Corp.  The plaintiff seeks unspecified damages on behalf of the Company, restitution on behalf of the Company, and reasonable costs and expenses including counsel fees and experts' fees.   The Company believes the claims are wholly without merit and filed a motion to dismiss the Complaint on May 18, 2010.  Before the motion to dismiss was ruled upon, Plaintiff filed an amended complaint and a second amended complaint on July 15, 2010 and September 20, 2010, respectively.  Defendants moved to dismiss the second amended complaint on September 29, 2010.  On May 23, 2011, Plaintiff and Defendants filed a stipulated motion requesting stay of all case deadlines pending further negotiation of a settlement agreement that would resolve the litigation.  At this time, negotiations to reduce the settlement to written terms are ongoing.   On May 24, 2011, the court granted the stipulated motion.  On June 4, 2011, the parties reported to the Court that they have reached a settlement agreement.  On June 30, 2011, the Court granted the defendants' joint motion for extension of time to file a stipulated motion to dismiss, which is due to be submitted to the Court on or before July 21, 2011.
 
As previously disclosed, on February 24, 2011, a putative class action complaint (the "Original Complaint") was filed against the Company and certain current and former officers of the Company on behalf of investors who purchased or sold the Company's securities between August 14, 2006 and July 14, 2009, alleging claims of securities fraud under Section 10(b) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and control person liability for such fraud under Section 20(a) of the same act, arising out of the Company's accounting for its acquisition of an interest in OQI Sask in August 2006.  On May 27, 2011, the plaintiffs in that putative class action filed an amended complaint (the "Amended Complaint") alleging the same legal causes of action but making the following changes from the Original Complaint:  a) expanding the putative class period so that it runs from March 20 2006 to January 13, 2011; b) naming as additional defendants eight individuals who are current or former directors of the Company as well as two additional corporate defendants, McDaniel & Associates Consultants Ltd. and TD Securities, Inc.; and c) basing the claimed fraud on a new theory that the Company overstated the value of its mineral rights as a result of misstatements about, among other things, the potential for extracting bitumen from oil sands lands for which the Company had exploration and development permits.  The Amended Complaint seeks unspecified damages.  The Company believes the suit is without merit and intends to defend itself vigorously.  On June 6, 2011, the Company filed a motion to dismiss the Amended Complaint.  On June 20, 2011, the plaintiffs filed their opposition to the motion to dismiss.  The Company filed its reply to the plaintiffs' opposition on June 27, 2011 and on July 29, 2011, the court is expected to hear oral arguments.
 
 
18

 
 
On April 13, 2011, a derivative action entitled Proctor v. Wilson, et al., Case No 2011CV2769 was filed in District Court, Denver County, Colorado.  The derivative action names the following individual defendants:  T. Murray Wilson, Ronald Blakely, Paul Ching, Christopher H. Hopkins, Brian F. MacNeill, Ronald Philips, John Read, Gordon Tallman and Pamela Wallin.  In addition, the Company is named as a nominal defendant.  Plaintiff asserts, among other things, claims for breach of fiduciary duties, unjust enrichment, abuse of control, gross mismanagement and waste against the defendants relating to the alleged failure to properly account for the Company’s acquisition of a minority interest in Oilsands Quest Sask Inc. and the Company’s restatement of its financial statements for certain periods.  The plaintiff seeks unspecified damages on behalf of the Company, restitution on behalf of the Company, unspecified disgorgement of profits, unspecified equitable relief and reasonable costs and expenses including counsel fees and experts' fees.   The response to the complaint is due on or before July 5, 2011.   We have asked for and expect to receive an extension to file our response by July 12, 2011.  The Company believes the claims are wholly without merit and intends to vigorously defend against such claims. 
 
Item 4.  (REMOVED AND RESERVED)

None.

PART II

Item 5.  MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

The Company’s common stock commenced trading on the NYSE Amex LLC (“NYSE Amex”) on August 24, 2006 under the symbol BQI.  The following table sets forth the high and low sales prices of the Company’s common stock for each quarterly period during the last two fiscal years as reported by the NYSE Amex.
 
 
Fiscal Quarter
 
High Sales Price
   
Low Sales Price
 
Fiscal Year End April 30, 2011
4th Quarter (2/1/11 — 4/30/11)
 
$
0.65
   
$
0.41
 
 
3rd Quarter (11/1/10 — 1/31/11)
 
$
0.71
   
$
0.36
 
 
2nd Quarter (8/1/10 — 10/31/10)
 
$
0.68
   
$
0.40
 
 
1st Quarter (5/1/10 — 7/31/10)
 
$
0.95
   
$
0.51
 
Fiscal Year End April 30, 2010
4th Quarter (2/1/10 — 4/30/10)  
 
$
0.99
   
$
0.66
 
 
3rd Quarter (11/1/09 — 1/31/10)
 
$
1.28
   
$
0.81
 
 
2nd Quarter (8/1/09 — 10/31/09)
 
$
1.69
   
$
0.85
 
 
1st Quarter (5/1/09 — 7/31/09)
 
$
1.30
   
$
0.75
 

The closing sales price of the common stock as reported on June 30, 2011 was $0.32 per share.  

Holders

As of June 30, 2011 there were 179 holders of record of the Company’s common stock. This does not include persons who hold our common stock in brokerage accounts and otherwise in “street name.” 

 Dividends

The Company did not declare or pay cash or other dividends on its common stock during the past three fiscal years. Payment of dividends by the Company will depend upon the Company’s financial condition, results of operations, capital requirements and such other factors as the Board of Directors of the Company may deem relevant.

Equity Compensation Plan Information
 
The following table sets forth information as of April 30, 2011 with respect to compensation plans under which equity securities of the Company are authorized for issuance:

Plan Category
 
Number of Securities to
be Issued Upon Exercise of
Outstanding Options,
Warrants and Rights
   
Weighted Average
Exercise Price of
Outstanding Options,
Warrants and Rights
   
Number of Securities
Remaining Available for
Future Issuance
Under Equity
Compensation Plans
(Excluding Securities
Reflected in Column (a))
 
Equity Compensation Plans Approved by Stockholders
    22,883,452
(1)
 
$
3.02
     
3,586,529
(3)
Equity Compensation Plans Not Approved by Stockholders
    -
(2)
 
$
-
     
50,000
 
     
(1)
               
TOTAL
    22,883,452
(2)
 
$
3.02
     
3,636,529
 
____________

(1)
Includes: options to acquire 22,883,452 shares of common stock under the Company’s 2006 Stock Option Plan.

(2)
All outstanding options to acquire shares of common stock under the Company’s 2005b Stock Option Plan were exercised during the year ended April 30, 2008. The Company does not intend to issue any more securities under this plan.

(3)
The aggregate number of securities issuable under the 2006 Stock Option Plan is the lesser of: (A) 15% of the total outstanding shares of the Company’s common stock, or (B) 30,000,000. As of April 30, 2011, the number of securities available for issuance under the 2006 Stock Option Plan is 3,586,529 (calculated as 30,000,000 maximum less 41,297,474 granted, less 44,000 bonus shares issued plus 14,928,003 forfeited).

 
19

 
 
Performance Graph:
 
The following line graph compares cumulative total stockholder returns for the five years ended April 30, 2011 for (i) our common stock, (ii) the Standard & Poor’s 500 Stock Index and (iii) the Amex Oil Index. The graph assumes an investment of $100 on April 30, 2005. The calculation of cumulative stockholder return on our common stock does not include reinvestment of dividends because we did not pay any dividends during the measurement period. The performance shown is not necessarily indicative of future performance.

The following line graph compares cumulative total stockholder returns since August 24, 2006 (the date the Company first listed on the NYSE Amex (formerly the American Stock Exchange) for (i) our common stock, the (ii) the Standard & Poor’s 500 Stock Index and (iii) the Amex Oil Index. The graph assumes an investment of $100 on August 24, 2006. The calculation of cumulative stockholder return on our common stock does not include reinvestment of dividends because we did not pay any dividends during the measurement period. The performance shown is not necessarily indicative of future performance.
 
CHART 1
 
 
Repurchases of Equity Securities

The Company did not repurchase any equity securities during the fourth quarter of the fiscal year covered by this Annual Report on Form 10-K.

Recent Sales of Unregistered Securities

There have not been any sales by the Company of equity securities in the last fiscal year that have not been registered under the 1933 Act, except as previously reported by the Company on a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.

 
20

 
 
Item 6.  SELECTED FINANCIAL DATA
 
The following selected financial data should be read in conjunction with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and consolidated financial statements and notes thereto contained in Item 8. “Financial Statements and Supplementary Data” of this report. The selected financial data have been derived from our audited consolidated financial statements and are subject to certain reclassifications to make prior years conform to current year presentation. The historical results are not necessarily indicative of results to be expected in any future period.

   
Year Ended
(in thousands, except per share amounts)
 
April 30,
2011
   
April 30,
2010
   
April 30,
2009
   
April 30,
2008
   
April 30,
2007
 
Summary of Operations
                             
Net loss
 
$
316,239
   
$
64,481
   
$
89,134
   
$
92,747
   
$
86,193
 
Net loss attributable to common stockholders
 
$
0.91
   
0.21 
   
$
0.34
   
$
0.41
   
$
0.50
 
Total Assets
 
$
173,192
   
$
484,094
   
$
435,184
   
$
510,119
   
$
438,217
 
Long Term Obligations
 
$
4,740
   
$
6,663
   
$
5,382
   
$
8,183
   
$
3,075
 
Balance Sheet Data
                                       
Cash and cash equivalents
 
$
15,984
   
$
18,642
   
$
6,986
   
$
26,498
   
$
32,394
 
Short-term investments
 
$
-
   
$
-
   
$
25,209
   
$
19,812
   
$
2,000
 
Working capital
 
$
3,981
   
$
16,635
   
$
26,393
   
$
34,226
   
$
5,819
 
Stockholders’ equity
 
$
139,503
   
$
398,715
   
$
357,096
   
$
399,768
   
$
295,156
 
____________

Item 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Introduction

The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis relates to the following topics:

Overview of Business

Overview of 2011 Results and Outlook

Liquidity and Capital Resources

Changes in Financial Condition and Results of Operations

Share Capital

Critical Accounting Policies

Contractual Cash Obligations

Overview of Business

We are a U.S. public company based in Calgary, Alberta engaging in a variety of projects in the oil and gas sector and in particular the oil sands and oil shale sectors in Western Canada. We are exploring Canada’s largest contiguous oil sands land holding, which is located in northeast Alberta and northwest Saskatchewan where Oilsands Quest is leading the development of an oil sands industry in the Province of Saskatchewan.

Oilsands Quest, together with its subsidiaries, is in the exploration and development stage and does not currently have any income from operating activities. For a more detailed discussion of our business See Part 1, Item 1 “Description of Business”.
 
Overview of 2011 Results and Outlook

During the year ended April 30, 2011, the Company’s activities included an exploration drilling program of 9 holes on lands in the Wallace Creek area, 16 core holes across Axe Lake reservoirs to improve the understanding of the overburden characteristics, a 40 km 2-D seismic program on the permits to the north and south of Axe Lake in Saskatchewan and the advancement of its pre-commercialization evaluation studies and reservoir test program on its Axe Lake discovery. We also expanded our environmental program consisting of monitoring and baseline assessment studies in anticipation of comprehensive Environmental Impact Assessment reports as part of the application for regulatory approval for development process in Alberta and Saskatchewan.

During the year ended April 30, 2011, we raised $32.1 million, net of issuance costs, through private placement share issuances, an equity distribution agreement and proceeds of option exercises to fund these activities and future programs.

Operations Summary:

Exploration Program

During the year ended April 30, 2011, we completed a five-well winter drilling program as a follow up to our successful drilling program of early 2010. The drilling focused on the western side of the Wallace Creek permit, which is adjacent to Cenovus’ Telephone Lake and Grizzly Oil Sands’ Firebag project areas.

Two of the wells drilled encountered significant quantities of bitumen in the McMurray formation to support a 16 per cent increase in contingent resource estimates. The previously-announced 11 well winter drilling program at Wallace Creek was condensed to five wells primarily due to the limited availability of drilling rigs.

We filed for and received approval for the third of three one-year extensions of our Saskatchewan oil sands permits.
 
During the year we relinquished our two northernmost land permits in Saskatchewan (permits PS000213 and PS000215) and on May 31, 2011, we relinquished an additional three Saskatchewan permits, PS00205, PS00206 and PS00212 as we focus our exploration and development opportunities to include only those lands that recent exploration activity has demonstrated to be prospective. Relinquishing these permits does not impact our resource estimates or development plans.

Axe Lake Area – Reservoir Development Activities

In July 2010, we drilled four wells to confirm the extent of the reservoir at Axe Lake and to satisfy our permit retention work obligations on the Saskatchewan permits.  The objective of these wells was to provide additional information on the geology in the area and will not have a significant impact on our assessment of the resource in the Axe Lake area.
 
During the year ended April 30, 2011 we completed testing of the steam containment characteristics of the glacial till cap-rock layer that lies above the Axe Lake reservoir. The laboratory tests indicate that the glacial till cap likely will support the proposed SAGD pilot at Axe Lake at chamber pressures of between 1,750 to 2,500 kPa. These tests support our plan to use steam-assisted gravity drainage (SAGD), a proven oil sands recovery process, in spite of the different cap-rock characteristics at Axe Lake compared with similar projects further west.

We continued to process and interpret the 1,847 kilometres (1,149 miles) of 2-D and 3-D seismic data that we have at Axe Lake in order to correlate this information with the results of the overburden drilling program and the summer 2010 drilling program at Axe Lake. This interpretation of the seismic data and the correlation of the well information will be used to assist in the placement of the well pads for commercial development as well as mapping the glacial till overburden.
 
 
21

 
 
We filed a proposal to the Saskatchewan Ministry of Environment (SME) for approval to produce up to 30,000 barrels per day of bitumen using SAGD. Filing with the SME is the first step in a two-stage process to apply for approval of a commercial lease for oil sands development. This proposal provides the complete vision for the project, giving the regulator helpful context when approving testing activity and giving all stakeholders clarity around the long-term development plans. The second stage of the process consists of an application for commercial project approval to SMER that will be submitted following the successful completion of the SAGD pilot.

The proposed project includes components typical of SAGD operations such as multi-well production pads of horizontal well pairs, and a central processing and bitumen treatment facility that includes produced fluid separation, water recycling, steam generation and tank storage facilities. Options for site access, utility service corridors, bitumen transportation, electricity and natural gas supplies are also being evaluated.

We received approval for a SAGD pilot at Test Site 1. The proposed pilot will consist of one 100 meter long horizontal well pair, with the upper well placed five meters below the glacial till cap, or overburden, and is designed to make use of the existing surface facilities. The SAGD pilot will demonstrate the steam containment properties of the glacial till cap and provide information essential for the front-end engineering design for the commercial development. Further activity on the pilot project has been suspended pending the necessary financing.
 
Abandonment and Reclamation Costs

We are responsible for compliance with terms and conditions of environmental and regulatory approvals and all laws and regulations regarding the abandonment of a project and reclamation of its lands at the end of its economic life, which abandonment and reclamation costs may be substantial. A breach of such legislation and/or regulations may result in the issuance of remedial orders, the suspension of approvals, or the imposition of fines and penalties, including an order for cessation of operations at the site until satisfactory remedies are made. As at April 30, 2011, we estimate the total undiscounted inflation-adjusted amount required to settle the asset retirement obligations in respect of the Company’s wells and facilities is approximately $44.3 million. This estimate includes the cost to re-abandon a number of wells at Axe Lake from the Company's early exploration core hole programs. During a review of our development plans and well licenses, we determined that a number of these core holes were not abandoned to meet our thermal development requirements or in accordance with regulatory requirements. We are also evaluating the core holes that are located outside the potential commercial development area and have included a portion of these costs in the re-abandonment liability based on performing the obligation over a 5 year period.  The abandonment and reclamation estimate also includes the costs to reclaim the air strip, camp site, access roads and reservoir test sites which are being brought into income over a period of 1 to 30 years. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to property and equipment or exploration expense.
 
Currently, the Company is working with the regulators to assess an issue relating to the re-abandonment of early exploration core holes.   It is possible that the outcome of such assessment could result in cancellation of the permits if the Company does not comply with the governing regulations.   Further, if the Company cannot remediate these core holes to industry standards, our ability to commercially develop the Axe Lake reservoir may be limited.
 
Liquidity and Capital Resources
 
At April 30, 2011, the Company held cash and cash equivalents totaling $16.0 million (April 30, 2010 - $18.6 million).

On May 10, 2010, the Company issued 10.5 million flow-through shares at $1.00 CDN ($0.995 USD) and 9.2 million common shares at $0.85 USD per share for gross proceeds of $18.6 million CDN ($18.1 million USD) pursuant to a non-brokered private placement.

On November 5, 2010, the Company completed a public offering of 20.8 million common shares at a price of $0.45 USD per share and 7.1 million flow-through shares at a price of $0.51 CDN ($0.50 USD) per share for total gross proceeds of approximately $13.4 million CDN ($12.9 million USD).

As of January 17, 2011, the Company entered into an equity distribution agreement (“Agreement”) with Knight Capital Americas, L.P. (“KCA”), a subsidiary of Knight Capital Group, Inc. Under the terms of the Agreement, the Company may offer and sell shares of common stock by way of “at-the-market” (ATM) distributions on NYSE Amex, up to a maximum of US$20 million over a period of 12 months, through KCA as sales agent. The shares are distributed at market prices prevailing at the time of each sale and the timing, price and number of shares sold are at our discretion.  The number of shares sold on any given day is expected to be relatively small compared to the total volume of shares traded. As of April 30, 2011, 5,537,137 shares have been distributed under this arrangement for gross proceeds of $3.1 million.  Funds raised from the ATM program are used to finance general corporate purposes.

During the year ended April 30, 2011, the Company expended $30.4 million on operating activities and $3.0 million on property and equipment. Management anticipates that the Company will be able to fund its activities at a reduced level through January 2012 with its cash and cash equivalents as at April 30, 2011. Accordingly, there is substantial doubt about our ability to continue as a going concern and without additional funding, we may not be able to maintain operations beyond that date. Additional financing will also be required if our activities are changed in scope or if actual costs differ from estimates of current plans. To fund future operations, we intend to conduct a Rights Offering under which the shareholders would be given the right to purchase additional shares in the Company based on their pro-rata share ownership. The proceeds from a Rights Offering will be used to continue with the delineation and development of the assets (as described more fully in the Outlook section), and for general corporate purposes. Our development strategy will also consider other sources of financing, asset sales or seeking partners on a joint venture basis on our specific projects to fund the development of such projects in a timely and responsible manner.
 
There can be no assurance that a Rights Offering will result in the Company raising sufficient funds to carry out its exploration and development plans.  There is also no assurance that debt or equity financing or joint venture partner arrangements will be available to us on acceptable terms, if at all, to meet these requirements.  The Company has no revenues, and its operating results, profitability and the future rate of growth depend solely on management’s ability to successfully implement the business plans and on the ability to raise additional capital. See “Outlook” above.
 
The following discussion of liquidity and capital resources should be read in conjunction with the consolidated financial statements included in Part II, Item 8. “Financial Statements and Supplementary Data”. The consolidated financial statements have been prepared assuming that we will continue as a going concern.

Changes in Financial Condition and Results of Operations

During the year ended April 30, 2011, the primary focus of the Company was the undertaking of an exploration drilling program in the Wallace Creek area and Axe Lake reservoir to improve the understanding of the overburden characterization, the advancement of pre-commercialization evaluation studies and reservoir test program at Axe Lake and the evaluation of strategic alternatives for enhancing shareholder value.

During the year ended April 30, 2010, the primary focus of the Company was on the commissioning of the facilities at Test Site 1, the implementation of an overburden characterization study to test the potential for the overburden to act as a cap rock for steam containment capacity within the reservoir and the filing of key regulatory submissions to advance the development of its Axe Lake oil sands project.

During the year ended April 30, 2009, the primary focus of the Company was on the engineering and construction of the testing facilities at Test Sites 1 and 3, the continued delineation of the Axe Lake and Raven Ridge discoveries and completing the acquisition of all the remaining rights of the external joint venture partners to the Triple 7 Joint Venture Agreement.
 
 
22

 
 
Net loss

Year ended April 30, 2011 as compared to year ended April 30, 2010. The Company experienced a net loss of $316.2 million or $0.91 per share for the year ended April 30, 2011 as compared to a net loss of $64.5 million or $0.21 per share for the year ended April 30, 2010. The increase in the net loss in the current period as compared to the prior period is primarily due to the recording of a valuation allowance for impairment on the Company’s undeveloped properties for $339.2 million and partially offset by a reduction in exploration activity, a reduction in stock-based compensation expense and decreased corporate expenses resulting from downsizing activities. The net loss was also increased by higher depreciation and accretion charge due to the recognition of a re-abandonment obligation on April 30, 2010, a reduction in the deferred income tax benefit and foreign exchange gain.

Year ended April 30, 2010 as compared to year ended April 30, 2009. The Company experienced a net loss of $64.5 million or $0.21 per share for the year ended April 30, 2010 as compared to a net loss of $89.1 million or $0.34 per share for the year ended April 30, 2009. The decline in the net loss in the current year as compared to the prior year is due to the reduction in exploration activity, a reduction in stock-based compensation expense and a foreign exchange gain resulting from holding Canadian funds with an appreciation of the Canadian dollar versus the U.S. dollar which were offset by increased asset retirement obligations due to the re-abandonment liability identified during the current year. The Company expects to continue to incur operating losses and will continue to be dependent on additional equity or debt sales and/or property joint ventures to fund its activities in the future.

Exploration costs

Year ended April 30, 2011 as compared to year ended April 30, 2010. Exploration costs for the year ended April 30, 2011 were $21.9 million (2010 — $50.2 million). Exploration costs in the current year relate to exploration drilling at Wallace Creek and Axe Lake, a seismic program at Axe Lake and additional environmental work and pre-commercialization evaluation studies to advance the reservoir test program at Axe Lake.  Exploration costs also include $10.2 million of cost revisions related to asset retirement obligations of which the majority relates to the re-abandonment of a certain number of core holes at Axe Lake.  The Operations Summary above provides a summary of the exploration activities conducted in the year ended April 30, 2011.

Year ended April 30, 2010 as compared to year ended April 30, 2009. Exploration costs for the year ended April 30, 2010 were $50.2 million (2009 — $72.0 million). Exploration costs in the current year relate to drilling, seismic, environmental, engineering and construction costs associated with Test Sites 1 and 3 on our Saskatchewan and Alberta permits. Exploration costs also include $13.8 million of additional asset retirement obligations identified during the current year in relation to the re-abandonment of a certain number of core holes at Axe Lake. The Operations Summary above provides a summary of the exploration activities conducted in the year ended April 30, 2010. 

General and administrative

Corporate

Year ended April 30, 2011 as compared to year ended April 30, 2010.  General and administrative expenses settled with cash for the year ended April 30, 2011 were $17.3 million (2010 — $17.0 million).  Expenditures for the year ended April 30, 2011 consist of salaries ($8.3 million), legal and other professional fees ($4.7 million) and general office costs ($4.3 million). Expenditures for the year ended April 30, 2010 consist of salaries ($9.4 million), legal and other professional fees ($2.6 million) and general office costs ($5.0 million). The decrease in salaries and wages is due to a reduction in salary expenses resulting from downsizing activities partially offset by the recognition of costs for employee benefit arrangements related to a termination plan in connection with the review of strategic alternatives.  The increase in professional fees during the year is related to additional costs incurred as part of the strategic alternatives review process.  The decrease in general office costs during the year ended April 30, 2011 is mainly caused by downsizing activities. At April 30, 2011, there were 17 employees compared to 46 employees at April 30, 2010.

Year ended April 30, 2010 as compared to year ended April 30, 2009. General and administrative expenses settled with cash for the year ended April 30, 2010 were $17.0 million (2009 — $12.6 million).  General and administrative expenses in the year ended April 30, 2010 consist of salaries ($9.4 million), legal and other professional fees ($2.6 million) and general office costs ($5.0 million). General and administrative expenses in the year ended April 30, 2009 consist of salaries ($5.7 million), legal and other professional fees ($2.7 million) and general office costs ($4.2 million). Increases in costs in year ended April 30, 2010 as compared to the prior year are mainly associated with severance payments.

Stock-based compensation

Year ended April 30, 2011 as compared to year ended April 30, 2010. Stock-based compensation expense for the year ended April 30, 2011 was $1.3 million (2010 - $5.6 million) and consists of stock-based compensation related to the issuance of options to directors, officers and employees.  The decrease during the year ended April 30, 2011 is due to fewer options remaining to vest including options forfeited caused by a reduction in the number of employees.  A total of 6.0 million options were forfeited during the year ended April 30, 2011.  As at April 30, 2011, the Company has unrecognized stock-based compensation costs of $0.4 million related to unvested options which will be recognized in future periods as the options vest. The average fair value of the stock options using either the Black-Scholes valuation model or the trinomial valuation model that were issued during the year ended April 30, 2011 was $0.51 (2010 - $0.43)

Year ended April 30, 2010 as compared to year ended April 30, 2009. Stock-based compensation for the year ended April 30, 2010 was $5.6 million (2009 — $17.5 million). Stock-based compensation expense for the year ended April 30, 2010 consists of stock-based compensation related to the issuance of options to directors, officers and employees. The decrease during the year ended April 30, 2010 compared to the prior year is the result of 6.9 million options forfeited due to a reduction in the number of employees that was greater than the anticipated forfeiture rate. As at April 30, 2010, the Company has unrecognized stock-based compensation costs of $1.7 million related to unvested options which will be recognized in future periods as the options vest. The average fair value of the stock options using either the Black-Scholes valuation model or the trinomial valuation model that were issued during the year ended April 30, 2010 was $0.43 (2009 - $1.93).

Foreign exchange loss (gain)

Year ended April 30, 2011 as compared to year ended April 30, 2010. Foreign exchange loss of $0.4 million (2010 — gain of $5.1 million) resulted from holding less Canadian funds in the parent company during the current year compared to the same period last year with increased volatility of the Canadian dollar against the U.S. dollar.

Year ended April 30, 2010 as compared to year ended April 30, 2009.  Foreign exchange gain of $5.1 million (2009 — loss of $4.8 million) resulted primarily from holding Canadian dollar cash and cash equivalents funds in the parent company with a US dollar functional currency when the value of the Canadian dollar increased compared to the U.S. dollar.

Depreciation and accretion

Year ended April 30, 2011 as compared to year ended April 30, 2010. Depreciation and accretion expense of $4.5 million (2010 — $2.5 million) relates to camp facilities, equipment and corporate assets which are being depreciated over their useful lives of 3 to 5 years. Accretion expense relates to the asset retirement obligation recognized on the re-abandonment of a certain number of core holes at Axe Lake and on the airstrip, camp site, access roads, and reservoir test sites which are being brought into income over a period of 1 to 30 years. The increase during the year ended April 30, 2011 is mainly due to the additional accretion on asset retirement obligation resulting from the re-abandonment of a certain number of wells at Axe Lake that was identified in the previous fiscal year.

Year ended April 30, 2010 as compared to year ended April 30, 2009. Depreciation and accretion expense of $2.5 million (2009 — $1.6 million) relates to camp facilities, equipment and corporate assets which are being depreciated over their useful lives of 3 to 5 years. Accretion expense relates to the asset retirement obligation recognized on the airstrip, camp site, access road, and the reservoir test sites which are being brought into income over a period of 1 to 30 years. The change from the year ended April 30 2009 to the year ended April 30, 2010 relates to the increase in assets held during the period.  Additions to the property and equipment for the year ended April 30, 2010 totaled $1.8 million. 

Impairment of property and equipment

Year ended April 30, 2011 as compared to year ended April 30, 2010.  The impairment of $340.3 million (2010- $6.4 million) is comprised of a $296.2 million impairment on the Saskatchewan Oil Sands permits for Axe Lake, a $27.2 million impairment and an $8.4 million impairment on the Alberta Oil Sands permits at Raven Ridge and leases at Eagles Nest which were recorded during the three months ended April 30, 2011.  We did not receive any firm proposals during the formal phase of the strategic alternative review process indicating impairment in the value of these properties at April 30, 2011.  We estimated the fair value of each property by obtaining, when available, information about recent market transactions and calculating the property’s risk adjusted net present value.  The Company determined that the carrying value of these properties exceeded their fair value and recorded a valuation allowance. The impairment provision also includes a $2.5 million loss on the Saskatchewan Oil Sands licenses at Axe Lake due to their low prospectivity and their expected relinquishment on August 12, 2011 and a $4.9 million provision on the Pasquia Hills property. Since the Company has no plan to explore and develop the Pasquia Hills property considering the considerable time, effort and resources required, a full impairment of the oil shale property was recognized and the remaining carrying value was written down to zero during the current fiscal year.  Impairment is also comprised of a provision of $1.1 million on leasehold improvements and office equipment related to our Calgary office following an assessment of their carrying value which was deemed to be not recoverable at April 30, 2011.

Year ended April 30, 2010 as compared to year ended April 30, 2009.  The impairment of $6.4 million (2010- $nil) related to the Pasquia Hills property after considering the expected proceeds from their disposal following the announcement of the sale of the oil shale assets in January 2010.

 
23

 
 
Interest income

Year ended April 30, 2011 as compared to year ended April 30, 2010. Interest income for the year ended April 30, 2011 amounted to $0.1 million (2010 — $0.1 million). Interest income is earned because the Company pre-funds its activities and the resulting cash and cash equivalents on hand are invested in high interest savings accounts. Interest income during the current fiscal year is comparable to the previous year reflecting the decrease in cash and cash equivalents offset by an increase in market rates over the intervening period.

Year ended April 30, 2010 as compared to year ended April 30, 2009. Interest income for the year ended April 30, 2010 amounted to $0.1 million (2009 — $1.1 million). The decrease in interest income for the year ended April 30, 2010 as compared to the prior year reflects the decrease in short term investments and the decrease in market interest rates over the intervening year.

Income tax benefit

Year ended April 30, 2011 as compared to year ended April 30, 2010. The deferred income tax benefit for year ended April 30, 2011 was $69.2 million (2010 — $12.0 million). The increase in the deferred tax benefit for the year ended April 30, 2011 compared to the prior year is mainly due to the tax benefit associated with the impairment on undeveloped properties amounting to $65.9 million.  The deferred tax benefit otherwise reported is reduced by the impact of renouncing $14.2 million of flow-through expenditures corresponding to a reduction of $1.9 million in tax benefit, and the recording of $4.6 million of asset retirement liabilities settled during the year which resulted in the reversal of $1.2 million of tax benefits previously recognized on asset retirement obligations. This decrease in the deferred tax benefit is partially offset by $2.6 million of tax benefits related to $10.2 million of additional asset retirement obligations that were recorded during the year.

Year ended April 30, 2010 as compared to year ended April 30, 2009. The deferred income tax benefit for year ended April 30, 2010 was $12.0 million (2009 — $18.2 million). The decrease in the deferred tax benefit for the year ended April 30, 2010 compared to the prior year is mainly due to a reduction in exploration costs incurred. The deferred tax benefit otherwise reported is reduced by the impact of flow through expenditures. The net impact for the year ended April 30, 2010 was a reduction of the deferred tax benefit in the amount of $3.5 million (2009 — $4.7 million).

Share Capital
 
At June 30, 2011, the Company had 348,495,556 shares of common stock issued and outstanding and 21,765,744 options to acquire shares of common stock. The options have a weighted average exercise price of $2.85 per share.
 
At June 30, 2011, OQI’s diluted shares of common stock outstanding was 348,495,556 shares issued and outstanding plus 21,765,744 options, plus Exchangeable Shares and options to acquire exchangeable shares which can be exchanged into 19,540,736 shares, plus 1,388,567 shares reserved for settlement with creditors of a former subsidiary.  
 
An Exchangeable Share provides the holder with economic terms and voting rights which are, as nearly as practicable, equivalent to those of a share of OQI common stock. The Exchangeable Shares are represented for voting purposes in the aggregate by one Preferred Share. The one Preferred Share represents a number of votes equal to the total outstanding Exchangeable Shares on the applicable record date for the vote submitted to OQI shareholders.

Critical Accounting Policies

The preparation of financial statements, in conformity with generally accepted accounting principles in the United States of America, requires companies to establish accounting policies and to make estimates that affect both the amount and timing of the recording of assets, liabilities, revenues and expenses. Some of these estimates require judgments about matters that are inherently uncertain and therefore actual results may differ from those estimates.

A detailed summary of all of the Company’s significant accountings policies and the estimates derived therefrom is included in Note 2 to the Consolidated Financial Statements for the year ended April 30, 2011. While all of the significant accounting policies are important to the Company’s consolidated financial statements, the following accounting policies and the estimates derived therefrom have been identified as being critical:

Properties and equipment;
 
Income taxes;

Stock-based compensation;

Flow-through shares;

Foreign currency translation; and

Asset retirement obligations.

Properties and equipment

Property represents the capitalized costs of acquisition of natural resource properties, principally the rights to explore for in-situ oil sands deposits in the provinces of Alberta and Saskatchewan, Canada and oil shale deposits in the province of Saskatchewan, Canada.

The Company follows the successful efforts method of accounting for its in situ oil sands and oil shale exploration activities. Under the successful efforts method, acquisition costs of proved and unproved properties are capitalized. Costs of unproved properties are transferred to proved properties when proved reserves are confirmed. Exploration costs, including geological and geophysical costs, are expensed as incurred. Exploratory drilling costs are initially capitalized. If it is determined that a specific well does not contain proved reserves, the related capitalized exploratory drilling costs are charged to expense. To date all exploration costs have been expensed.

Development costs, which include the costs of wellhead equipment, development drilling costs and handling facilities, applicable geological and geophysical costs and the costs of acquiring or constructing support facilities and equipment, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and gas to the surface will be expensed as operating costs.

If and when the Company achieves production, acquisition costs of proved properties will be depleted using the unit-of-production method based on proved reserves. Capitalized exploratory drilling and development costs will be depleted on the basis of proved developed reserves by area. Support facilities and equipment will be depreciated on a straight-line basis over their useful lives.

Significant undeveloped properties are assessed periodically for impairment individually, and are dependent upon the Company’s current exploration plans and the ability to obtain necessary financing to complete the development of the properties. If an impairment is indicated, a valuation allowance is provided.
 
The Company has not yet converted any of its exploration permits or licenses in Saskatchewan and Alberta to development leases. In the event that the Company does not meet the regulated requirements or development conditions to convert its permits or licenses to leases or obtain an extension of such development requirements, its right to explore for bitumen or oil shale, as applicable, may be lost resulting in an impairment being recorded. The Company is satisfied that it has good and proper right, title and interest in and to the permits and licenses.

Equipment is recorded at cost less accumulated depreciation and include corporate assets, camp facilities and field equipment. Depreciation of these assets is provided using the straight-line method based on estimated useful lives ranging from two to five years.

Income taxes

The Company files United States federal and Canadian federal and provincial tax returns.  Deferred federal and provincial income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases.  The Company recognizes a tax benefit from an uncertain position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position and will record the largest amount of tax benefit that is greater than 50 percent likely of being realized upon settlement with a taxing authority. The Company has no uncertain tax positions as of April 30, 2011. Presently, the Company has taken a full valuation allowance on all non-capital losses.
 
 
24

 
 
Stock-based compensation

The Company’s share-based payments take the form of stock options granted to employees and non-employees all of which are equity classified. The Company estimates the fair value of share-based payment awards on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as expense in the Company’s financial statements over the requisite service period. The Company estimates the fair value of stock options using the Black-Scholes valuation model. The Black-Scholes valuation model requires the input of highly subjective assumptions, including the option’s expected life, the expected price volatility of the Company’s common stock and forfeitures.  For the Company’s performance options containing market conditions, fair value is estimated using the Hull-White Trinomial model.  This model also contains highly subjective assumptions, including expected price volatility of the Company’s common stock, forfeitures, employee exit rates and suboptimal exercise factor.  The expected stock price volatility assumption was determined using historical volatility of the Company’s common stock.

Flow-through Shares

Periodically, the Company finances a portion of its exploration and development activities through the issuance of flow-through shares.  The resource expenditure deductions for income tax purposes related to exploratory development activities are renounced to investors in accordance with the applicable Canadian income tax legislation.  Flow-through shares issued are recorded in share capital at the fair value of common shares on the date of issue.  The premium received on issuing flow-though shares is initially recorded as a deferred liability.  As qualifying expenditures are renounced, the premium is reversed and a deferred income tax liability is recorded.  The net amount is then recognized as a reduction of deferred income tax benefit.

Foreign currency translation

The U.S. dollar is the functional and reporting currency for OQI (the parent company).  The Canadian dollar (CDN) is the functional currency for OQI’s Canadian subsidiaries.  The assets and liabilities of OQI’s Canadian subsidiaries are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates.  Canadian income and expenses are translated at weighted average rates for the periods in which those elements are recognized.  Foreign currency translation adjustments have no effect on net loss and are included in accumulated other comprehensive loss in stockholders’ equity.  The only component of accumulated other comprehensive loss is foreign currency translation adjustments. Deferred income taxes are not provided on cumulative foreign currency translation gains and losses where OQI expects undistributed earnings of a foreign operation to be indefinitely reinvested.

Gains and losses arising from transactions denominated in currencies other than the functional currency are included in the results of operations of the period in which they occur.    Monetary assets and liabilities denominated in foreign currencies at the balance sheet date are translated to the reporting currency using the rate in effect on that date.  Non-monetary assets and liabilities are translated at the rates of exchange prevailing at the time the asset was acquired or the liability was incurred.

Asset retirement obligations
 
An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset or a charge to exploration expense. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate.  The asset retirement obligation is recorded as a liability with an offsetting asset retirement cost recorded as an increase to property and equipment or exploration expense. The capitalized asset retirement cost is amortized on the same basis as the remaining property and equipment, while the liability is increased as an accretion expense until it is settled or sold.  Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset or exploration expense. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates and changes in the estimated timing of abandonment. 

The Company records the fair value of a liability for an asset retirement obligation when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. The legal obligation to perform the asset retirement activity is unconditional even though uncertainty may exist about the timing and/or method of settlement that may be beyond the Company’s control. This uncertainty about the timing and/or method of settlement is factored into the measurement of the liability when sufficient information exists to reasonably estimate the fair value. The amount of asset retirement obligation recorded reflects the expected costs, taking into account the probability of particular scenarios. The difference between the upper end of the range of these assumptions and the lower end of the range can be significant, and consequently changes in these assumptions could have a material effect on the fair value of asset retirement obligations and future losses in a period of change. 

Contractual Cash Obligations

The following summarizes our contractual cash obligations and commercial commitments at April 30, 2011 and the effect such obligations are expected to have on liquidity and cash flows in future periods. Included in the table below are purchase obligations under which we have contractual obligations for payments in specific years.
 
   
Payments Due by Period (in thousands)
 
   
Total
   
Less than
1 Year
   
2-3 Years
   
4-5 Years
   
After 5 Years
 
Operating lease obligations (a)
 
$
4,740
   
$
1,122
   
$
1,925
   
$
1,062
   
$
631
 

The Company is subject to annual lease rentals, minimum exploration expenditures and work commitments related to its exploration permits, licenses and lease assets. These required expenditures have not been included in the above schedule. For details of these required expenditures see note 4 to the Consolidated Financial Statements.

(a)
See Note 15 to the Consolidated Financial Statements, “Contingencies and Commitments”.

Recent accounting pronouncements

There have been no recent accounting pronouncements that are of significance, or of potential significance, to the Company as of April 30, 2011.

Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on its financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
 
Item 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
 
Market risk is the potential loss arising from changes in market rates and prices. We are exposed to the impact of market fluctuations associated with the following:

Interest Rate Risk
 
We consider our exposure to interest rate risk to be immaterial.  Interest rate exposures relate entirely to our investment portfolio, as we do not have short-term or long-term debt. Our investment objectives are focused on preservation of principal and liquidity. We manage our exposure to market risks by limiting investments to high quality bank issuers at overnight rates, or government securities of the United States or Canadian federal governments such as Guaranteed Investment Certificates or Treasury Bills.  We do not hold any of these investments for trading purposes.  We do not expect any material loss from cash equivalents and therefore we believe our interest rate exposure on invested funds is not material.  
 
 
25

 
 
Foreign Exchange Risk
 
Our exposure to foreign exchange risk is primarily related to fluctuations between the Canadian dollar and the U.S. dollar.  We are exposed to foreign exchange fluctuations when we translate our Canadian operating results into U.S. dollars for reporting purposes.  These fluctuations can affect the comparability between quarters and year-to-year.  As at April 30, 2011, we had not entered into any market risk sensitive instruments relating to our foreign currency exchange risk.
 
Commodity Risk
 
Oil and natural gas prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global demand for petroleum products, international supply of oil and gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both international and domestic. We cannot predict future oil and gas prices with any degree of certainty. Sustained weakness in oil and gas prices may adversely affect our ability to obtain capital to fund our activities and could in the future require a reduction in the carrying value of our oil and gas properties. Similarly, an improvement in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources. As at April 30, 2011, we had not entered into any market risk sensitive instruments relating to oil and natural gas.
 
Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See Financial Statements and Supplementary Data following the signature page of this Annual Report on Form 10-K.

Item 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not applicable.

Item 9A.  CONTROL AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of April 30, 2011, management has conducted, with the participation of our Chief Executive Officer and Chief Financial Officer, an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Our disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of April 30, 2011, our disclosure controls and procedures were effective.

Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act).  Internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP.  Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not provide absolute assurance that a misstatement of our financial statements would be prevented or detected.

Further, the evaluation of the effectiveness of internal control over financial reporting was made as of a specific date, and continued effectiveness in future periods is subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has conducted, with the participation of our Chief Executive Officer and Principal Accounting Officer, an evaluation of the effectiveness of our internal control over financial reporting as of April 30, 2011 in accordance with the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in  Internal Control — Integrated Framework.  Based on this assessment, management concluded that as of April 30, 2011, the Company’s internal control over financial reporting was effective.

KPMG LLP, our independent registered public accounting firm that audited the financial statements included in the annual report containing the disclosure required by this Item, has performed an audit of internal control over financial reporting.  Their report is included in this annual report on Form 10-K.


Item 9B.  Other Information

None.

PART III
 
Item 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information called for by Item 10 pertaining to directors and corporate governance will be set forth in our definitive proxy statement relating to our 2011 Annual Meeting of Stockholders (the “Proxy Statement”) to be filed within 120 days of the Company’s fiscal year end of April 30, 2011 and is incorporated herein by reference.

Section 16(a) of the Exchange Act requires our directors, executive officers and persons who beneficially own more than ten percent (10%) or more of our voting securities (“Insiders”) to file with the SEC reports showing their ownership and changes in ownership of our securities, and to send copies of these filings to us. To our knowledge, based upon review of copies of such reports furnished to us [and upon written representations that we have received to the effect that no other reports were required during the year ended April 30, 2011], the Insiders complied with all Section 16(a) filing requirements applicable to them with the following exceptions.

Each of Mr. Simon Raven and Ms. Annie Lamoureux failed to timely report their holdings of stock options to purchase our common shares upon becoming Insiders in the year ended April 30, 2011. Mr. Raven’s report was filed approximately one month late. Ms. Lamoureux’s report was filed approximately one week late, and was subsequently amended to disclose additional stock options held by Ms. Lamoureux.

Item 11.  EXECUTIVE COMPENSATION

The information called for by Item 11 pertaining to executive and director compensation will be set forth in the Proxy Statement and is incorporated herein by reference.

Item 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDERS' MATTERS

The information called for by Item 12 pertaining to security ownership of certain beneficial owners and management will be set forth in the Proxy Statement and is incorporated herein by reference.  The information regarding compensation plans under which the Company’s equity securities are authorized for issuance is set forth in Part II, Item 5. “Market for Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities — Equity Compensation Plan Information” and is incorporated herein by reference.
 
 
26

 
 
Item 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information called for by Item 13 pertaining to certain relationships and related transactions and director independence will be set forth in the Proxy Statement and is incorporated herein by reference.

Item 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES
 
The information called for by Item 14 pertaining to principal accounting fees and services will be set forth in the Proxy Statement and is incorporated herein by reference.
 
PART IV

Item 15.  
 
EXHIBITS

3.1
 
Articles of Incorporation. (1),(4),(6),(10), (14)
     
3.2
 
Bylaws. (15)
     
4.1
 
2005b Stock Option Plan. (2)
     
4.2
 
2006 Stock Option Plan. (11)
     
4.3
 
Rights Agreement, dated as of March 9, 2006, between the Company and Computershare Investor Services, Inc., as Rights Agent. (5)
     
4.4
 
Warrant indenture between Oilsands Quest Inc. and Computershare Trust Company of Canada dated December 5, 2007. (12)
     
 4.5
 
 Form of Warrant, dated December 12, 2005. (3)
     
 4.6
 
Warrant Indenture dated May 12, 2009. (18)
     
 4.7
 
Form of Registration Rights Agreement between the Company and certain investors, dated December 22, 2009. (20)
     
10.1
 
Financing Agreement with Oilsands Quest Sask, Inc., dated November 25, 2005. (3)
     
10.2
 
Subscription Agreement with Dynamic Power Hedge Fund, dated December 12, 2005. (3)
     
10.3
 
Executive Employment Agreement (Amended and Restated) with T. Murray Wilson, dated September 22, 2006 and as amended effective August 1, 2007. (11)
     
10.4
 
Reorganization Agreement, dated June 9, 2006. (7)
     
10.5
 
Voting Exchange and Trust Agreement dated August 14, 2006. (8)
     
10.6
 
Exchangeable Share Provisions. (8)
     
10.7
 
Support Agreement dated August 14, 2006. (8)
     
10.8
 
Executive Employment Agreement with Christopher Hopkins dated August 14, 2006. (8)
     
10.9
 
Form of Indemnity Agreement. (9)
     
10.10
 
Subscription Agreement for Flow-Through Shares, dated March 6, 2007. (11)
     
10.11
 
Amending Agreement to Subscription Agreement for Flow-Through Shares, dated May 3, 2007. (11)
     
10.12
 
Subscription Agreement between the Company and Subscribers, dated May 3, 2007. (11)
     
10.13
 
Underwriting Agreement. (13)
     
10.14
 
Consulting Services Agreement with Karim Hirji. (16)
     
10.15
 
Executive Employment Agreement with Garth Wong. (19)
     
10.16
 
Agency Agreement dated April 30, 2009. (17)
     
10.17
 
Form of Subscription Agreement between certain investors and the Company, dated December 16, 2009 and December 21, 2009. (20)
     
 10.18
 
Transition Agreement between the Company and Christopher Hopkins, dated January 15, 2010. (21)
     
10.19
 
Agency Agreement between the Company and TD Securities Inc. dated October 28, 2010. (22)
     
10.20
 
Form of Retention Agreement. (23)
     
10.21   Executive Employment Agreement with Simon Raven. (24)
     
10.22
 
Equity Distribution Agreement with Knight Capital Americas, L.P. (25)
     
10.23
 
Revised Executive Employment Agreement with Garth Wong. (26)
     
10.24
 
Executive Employment Agreement with Annie Lamoureux. (26)
     
10.25   Release with Leigh Peters dated July 5, 2011. (26)
 
 
27

 
 
23.1
 
Consent of Smythe Ratcliffe LLP, filed herewith.
     
23.2
 
Consent of KPMG LLP, filed herewith.
     
31.1
 
Certification of CEO Pursuant to Exchange Act Rules 13a-14 and 15d-14 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
     
31.2
 
Certification of Vice President and Controller, Principal Accounting Officer Pursuant to Exchange Act Rules 13a-14 and 15d-14 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
     
32.1
 
Certification of CEO Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.
     
32.2
 
Certification of Vice President and Controller, Principal Accounting Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.
____________
(1)
Incorporated by reference from Form 10-SB, filed October 14, 1999; and Form 8-K, filed November 29, 2004.
(2)
Incorporated by reference from Form SB-2 dated December 29, 2005.
(3)
Incorporated by reference from Form 10-QSB dated March 22, 2006.
(4)
Incorporated by reference from Form 10-QSB dated December 14, 2005.
(5)
Incorporated by reference from Form 8-A dated March 13, 2006.
(6)
Incorporated by reference from Form 8-K dated March 13, 2006.
(7)
Incorporated by reference from Form 8-K dated June 14, 2006.
(8)
Incorporated by reference from Form 8-K dated August 17, 2006.
(9)
Incorporated by reference herein from Form 10-QSB filed March 15, 2007
(10)
Incorporated by reference herein from Form 10-QSB filed December 15, 2006.
(11)
Incorporated by reference herein from Form 10-KSB filed July 30, 2007.
(12)
Incorporated by reference herein from Form 8-K filed December 5, 2007.
(13)
Incorporated by reference herein from Form 8-K filed November 23, 2007.
(14)
Incorporated by reference herein from Form 8-K filed October 21, 2008.
(15)
Incorporated by reference herein from 10-K filed June 27, 2008.
(16)
Incorporated by reference herein from 10-Q filed March 12, 2009.
(17)
Incorporated by reference herein from Form 8-K filed May 1, 2009.
(18)
Incorporated by reference herein from Form 8-A filed May 12, 2009.
(19)
Incorporated by reference herein from Form 10-K filed July 30, 2009.
(20)
Incorporated by reference herein from Amendment No. 4 to Form S-1 filed January 22, 2010.
(21)
Incorporated by reference herein from Form 8-K filed January 22, 2010.
(22)
Incorporated by reference herein from Form 8-K filed on November 3, 2010
(23)
Incorporated by reference herein from Form 8-K filed November 30, 2010
(24)
Incorporated by reference herein from Form 8-K filed January 18, 2011
(25)
Incorporated by reference herein from Form 8-K filed January 21, 2011
(26)
Incorporated by reference herein from Form 10-K filed July 6, 2011
 
 
 
28

 
 
SIGNATURES
 
In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 
OILSANDS QUEST INC.
     
Date: July 8, 2011
By:
/s/ Garth Wong
   
Garth Wong,
President and Chief Executive Officer
(Principal Executive Officer)
     
     
Date: July 8, 2011
By:
/s/ Annie Lamoureux
   
Annie Lamoureux
Vice President and Controller
(Principal Accounting Officer)

 
 Pursuant to the requirement of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:

 
 
 
 
Director
 July 8, 2011
Ronald Blakely
     
       
/s/ Paul Ching
 
Director
 July 8, 2011
Paul Ching
     
       
/s/ Christopher H. Hopkins
 
Director
July 8, 2011
Christopher H. Hopkins
     
       
/s/ Brian MacNeill
 
Director
 July 8, 2011
Brian MacNeill
     
       
/s/ Ronald Phillips
 
Director
 July 8, 2011
Ronald Phillips
     
       
 
 
Director
 July 8, 2011
John Read
     
       
 
 
Director
 July 8, 2011
Gordon Tallman
     
       
/s/ Pamela Wallin
 
Director
 July 8, 2011
Pamela Wallin
     
       
 
 
Director
 July 8, 2011
T. Murray Wilson
     
 
 
29

 

OILSANDS QUEST INC.
YEAR ENDED APRIL 30, 2011
CONSOLIDATED FINANCIAL STATEMENTS

Item 8. Financial Statements and Supplementary Data


INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Reports of Independent Registered Public Accounting Firms
 
   
Consolidated Balance Sheets, April 30, 2011 and 2010
 
   
Consolidated Statements of Operations, Three Years Ended April 30, 2011 and Period from Inception on April 3, 1998 to April 30, 2011
 
   
Consolidated Statements of Stockholders’ Equity, Three Years Ended April 30, 2011 and Period from Inception on April 3, 1998 to April 30, 2011
 
   
Consolidated Statements of Comprehensive Loss, Three Years Ended April 30, 2011 and Period from Inception on April 3, 1998 to April 30, 2011
 
   
Consolidated Statements of Cash Flows, Three Years Ended April 30, 2011 and Period from Inception on April 3, 1998 to April 30, 2011
 
   
Notes to Consolidated Financial Statements
 
   
Supplemental Quarterly Information (Unaudited)
 
   
Supplemental Information on Oil and Gas Exploration and Producing Activities (Unaudited)
 
 
 
30

 
Report of Independent Registered Public Accounting Firm
 
 
TO THE STOCKHOLDERS AND DIRECTORS OF OILSANDS QUEST INC.
(A Development Stage Company)
 
We have audited the accompanying consolidated statements of operations, stockholders’ equity, comprehensive loss and cash flows of Oilsands Quest Inc. (a development stage company) for the period from inception on April 3, 1998 through to April 30, 2007 (not separately presented herein). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, these consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of Oilsands Quest Inc. (a development stage company) for the period from inception on April 3, 1998 through to April 30, 2007 (not separately presented herein) in conformity with accounting principles generally accepted in the United States of America.
 
/s/ Smythe Ratcliffe LLP
 
 
Chartered Accountants
Vancouver, Canada
July 29, 2009

 
31

 
 
INDEPENDENT AUDITORS’ REPORT
 

 

The Board of Directors and Stockholders
Oilsands Quest Inc.
 
 
 
We have audited the accompanying consolidated balance sheets of Oilsands Quest Inc. and subsidiaries (a development stage company) as of April 30, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity, comprehensive loss and cash flows for each of the years in the three-year period ended April 30, 2011 and for the period from inception on April 3, 1998 to April 30, 2011. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. The cumulative statements of operations, stockholders’ equity, comprehensive loss and cash flows for the period from inception on April 3, 1998 to April 30, 2011 include amounts for the period from inception on April 3, 1998 to April 30, 2007, which were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for the period from inception on April 3, 1998 to April 30, 2007 is based solely on the report of other auditors.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, based on our audits and the report of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Oilsands Quest Inc. and subsidiaries (a development stage company) as of April 30, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended April 30, 2011 and for the period from April 3, 1998 to April 30, 2011, in conformity with U.S. generally accepted accounting principles.
 
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in note 1 to the consolidated financial statements, the Company does not presently have adequate cash and cash equivalents to fund activities for the foreseeable future and will require additional funding to maintain operations, which raises substantial doubt about its ability to continue as a going concern.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of April 30, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated July 5, 2011, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
 
 
/s/ KPMG LLP
 
 
Calgary, Canada
July 5, 2011

 
32

 


 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 

The Board of Directors and Stockholders
Oilsands Quest Inc.
 
We have audited Oilsands Quest Inc.’s (the “Company”) (a development stage company) internal control over financial reporting as of April 30, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting under Item 9A of the April 30, 2011 Annual Report on Form 10-K. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of April 30, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Oilsands Quest Inc. and subsidiaries (a development stage company) as of April 30, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity, comprehensive loss and cash flows for each of the years in the three-year period ended April 30, 2011 and for the period from inception on April 3, 1998 to April 30, 2011, and our report dated July 5, 2011 expressed an unqualified opinion on those consolidated financial statements.

 
/s/ KPMG LLP
 
 
Calgary, Canada
July 5, 2011

 
33

 
OILSANDS QUEST INC.
(A Development Stage Company)
Consolidated Balance Sheets
(in thousands, except share data)

     
April 30, 2011
 
April 30, 2010
 
       
ASSETS
 
Current Assets:
   
Cash and cash equivalents
 
$
15,984
   
$
18,642
 
Restricted cash (note 2(e))
   
1,862
     
-
 
Accounts receivable
   
921
     
1,421
 
Prepaid expenses
   
630
     
804
 
Total Current Assets
   
19,397
     
20,867 
 
                 
Property and Equipment (notes 4 and 5)
   
153,795
     
458,168
 
Assets held for sale (note 3)
   
-
     
5,059
 
Total Assets
 
$
173,192
   
$
484,094
 
                 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
Current Liabilities:
             
Accounts payable (note 15)
 
$
561
   
$
1,606
 
Accrued liabilities
   
5,696
   
2,626
 
Current portion of asset retirement obligation (note 6)
   
7,297
   
-
 
Total Current Liabilities
   
13,554
   
4,232
 
               
Obligation under sublease contract
   
550
   
-
 
Deferred Taxes (note 7)
   
-
   
62,516
 
Asset Retirement Obligation (note 6)
   
19,585
   
17,485
 
Liabilities related to assets held for sale (note 3)
   
-
   
1,146
 
               
Stockholders’ Equity:
 
Capital Stock
             
Preferred Stock, par value of $0.001 each, 10,000,000 shares authorized, 1 Series B Preferred share outstanding (note 10)
   
-
   
-
 
Common Stock, par value of $0.001 each, 750,000,000 shares authorized, 348,495,556 and 292,491,188 shares outstanding at April 30, 2011 and 2010 respectively (note 11)
   
348
   
292
 
Additional Paid-in Capital
   
789,738
   
758,007
 
Deficit Accumulated During Development Stage
   
(711,435)
   
(395,196)
 
Accumulated Other Comprehensive Income
   
60,852
   
35,612
 
Total Stockholders’ Equity
   
139,503
   
398,715
 
Total Liabilities and Stockholders’ Equity
 
$
173,192
   
$
484,094
 
 
Going concern (note 1)
Contingencies and commitments (note 15)
Subsequent events (notes 4(a) and 16)

See Notes to Consolidated Financial Statements


 
 
 
 
 
 
 
34

 
 
 
 

OILSANDS QUEST INC.
(A Development Stage Company)
Consolidated Statements of Operations
(in thousands, except share data and per share amounts)

   
 
 
 
 
 
For the Years Ended April 30,
   
From
Inception on
April 3, 1998
through to
April 30, 2011
 
2011
   
2010
   
2009
Expenses
                       
Exploration
 
$
21,898
   
$
50,169
   
$
71,987
   
$
278,325
 
General and administrative
                               
Corporate
   
17,269
     
16,979
     
12,567
     
76,089
 
Stock-based compensation (notes 9, 11 and 12)
   
1,292
     
5,584
     
17,481
     
148,119
 
Foreign exchange loss (gain)
   
360
     
(5,088)
     
4,780
     
(188)
 
Depreciation and accretion
   
4,543
     
2,528
     
1,564
     
10,075
 
Impairment of property and equipment (notes 3, 4 and 5)    
340,260
     
6,403
      -      
346,663
 
     
385,622
     
76,575
     
108,379
     
859,083
 
Other Items
                               
Interest income
   
(136)
     
(134)
     
(1,089)
     
(6,568)
 
Loss before income tax
   
385,486
     
76,441
     
107,290
     
852,515
 
Deferred income tax benefit (note 7)
   
(69,247)
     
(11,960)
     
(18,156)
     
(133,386)
 
Net loss
   
316,239
     
64,481
     
89,134
     
719,129
 
Net loss attributable to non-controlling interest (note 8)
   
-
     
-
     
-
     
(7,694)
 
Net loss attributable to common stockholders
 
$
316,239
   
$
64,481
   
$
89,134
   
$
711,435
 
                                 
Net loss attributable to common stockholders per share –
Basic and Diluted
 
$
0.91
   
$
0.21
   
$
0.34
         
                                 
Weighted Average Number of Common Shares Outstanding – Basic and Diluted (note 11)
   
348,082,145
     
305,327,827
     
261,510,084
         

See Notes to Consolidated Financial Statements
 


 
 
 
 
 
 
 
35

 
 
 
 

OILSANDS QUEST INC.
(A Development Stage Company)
Consolidated Statements of Stockholders' Equity
(in thousands, except shares)

               
Additional Paid in Capital
   
Accumulated Other Comprehensive Income
   
Deficit Accumulated During the Development Stage
   
Total Stockholders’ Equity
 
   
Common Stock
   
Preferred Stock
                 
   
Shares
   
Par Value
   
Shares
   
Par Value
                 
                                                 
Balance, April 30, 2010
   
292,491,188
   
$
292
     
1
   
$
-
   
$
758,007
   
$
35,612
   
$
(395,196)
   
$
398,715
 
Common stock issued for:
                                                               
Cash
   
53,126,995
     
53
     
-
     
-
     
34,155
     
-
     
-
     
34,208
 
Premium on flow-through shares
   
-
     
-
     
-
     
-
     
(1,851)
     
-
     
-
     
(1,851)
 
Exchange of OQI Sask Exchangeable shares
   
2,877,373
     
3
     
-
     
-
     
(3)
     
-
     
-
     
-
 
Stock-based compensation cost
   
-
     
-
             
-
     
1,292
     
-
     
-
     
1,292
 
Share issue costs
   
-
     
-
     
-
     
-
     
(2,074)