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

For the fiscal year ended February 28, 2010

For the transition period from ______ to _______

COMMISSION FILE NO. 000-52782

(Exact name of registrant as specified in its charter)

Securities registered pursuant to Section 12(b) of the Act: NONE

Indicate by check mark if the registration is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.     [   ] Yes    [ X] No

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     [ X] No

Indicate by check mark whether the registrant has (i) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (ii) has been subject to such filing requirements for the past 90 days.    [ X] Yes     [   ] No

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained in this form, 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.      [   X  ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated file, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    [   ] Yes     [ X] No

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was sold, or the average bid and asked price of such common equity, as of the last business of the registrant's most recently completed second fiscal quarter: August 31, 2009 - $75,343,821

APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PRECEDING FIVE YEARS

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.     [   ] Yes     [    ] No

(APPLICABLE ONLY TO CORPORATE REGISTRANTS)

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date:

DOCUMENTS INCORPORATED BY REFERENCE
N/A

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Statements made in this Form 10-K that are not historical or current facts are "forward-looking statements" made pursuant to the safe harbour provisions of Section 27A of the Securities Act of 1933, as amended (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). These statements often can be identified by the use of terms such as "may," "will," "expect," "believe," "anticipate," "estimate," "approximate" or "continue," or the negative thereof. We intend that such forward-looking statements be subject to the safe harbours for such statements. We wish to caution readers not to place undue reliance on any such forward-looking statements, which speak only as of the date made. Any forward-looking statements represent management's best judgment as to what may occur in the future. However, forward-looking statements are subject to risks, uncertainties and important factors beyond our control that could cause actual results and events to differ materially from historical results of operations and events and those presently anticipated or projected. We disclaim any obligation subsequently to revise any forward-looking statements to reflect events or circumstances after the date of such statement or to reflect the occurrence of anticipated or unanticipated events.

This Annual Report is being amended primarily to provide additional disclosure required for non-smaller reporting companies, to revise disclosure regarding reserves estimates, statements of cash flows and discontinued operations, and disclosure regarding disclosure controls and procedures.

Mainland Resources, Inc. was incorporated under the laws of the State of Nevada on May 12, 2006 and has been engaged in the business of acquisition, exploration and development of mineral properties in the United States since its inception.

On March 11, 2008 Mainland completed a forward stock split of twenty for one (20:1) basis. On May 29, 2008 Mainland completed a forward stock split on a 1.5 for one (1.5:1) basis. On August 3, 2009 Mainland completed a forward stock split on a two for 1 (2:1) basis.

Mainland's shares of common stock trade on the OTC Bulletin Board under the symbol "MNLU:OB."

We have entered into a Merger Agreement and Plan of Merger with American Exploration Corporation ("American Exploration") dated as of March 22, 2010 (the "Merger Agreement"), pursuant to which American Exploration will be merged with and into our Company (the "Merger"), with our Company as the surviving company of the Merger.  By way of background, we have entered into a joint area development agreement with American Exploration to jointly develop contiguous acreage comprising the Buena Vista Prospect, an oil and gas exploration project located in Jackson County, Mississippi, U.S.A. As operator on the Buena Vista Prospect, we recently issued an Authority for Expenditure (AFE) for the Burkley-Phillips No. 1 Well to be drilled on the Prospect for the purpose of evaluating the Haynesville Shale formation. American Exploration was unable to fund its 20% share of the estimated total well costs of the Burkley-Phillips No. 1 Well. As a result, American Exploration has forfeited its right to a 29% working interest in the well and in the Buena Vista Prospect in otall of our Company. American Exploration will continue to be entitled to receive a 20% working interest in the well and the Prospect after completion (subject to compliance by American Exploration with all other terms and conditions of the Letter Agreement and the related Joint Operating Agreement).

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We were previously required to pay 72% of the total cost to drill and complete the Burkley-Phillips No. 1 Well, for a 45.9% working interest. Due to American Exploration's inability to make its contribution in response to the cash call, we will now pay 90% of the total cost of the well to earn a 72% interest, and Guggenheim Energy Opportunities, LLC ("Guggenheim") will pay 10% of the total cost to earn an 8% interest. Accordingly, the respective working interests of the parties after completion are anticipated to be as follows: Mainland - 72%, American Exploration - 20%, and Guggenheim - 8%. This working interest breakdown will apply to the remainder of the leasehold and project area. We currently hold interests in excess of 17,000 acres in the Buena Vista Prospect.

The Merger Agreement represents our agreement with American Exploration to combine our businesses and ownership of the Buena Vista Prospect.

If the Merger is completed, each share of American Exploration's common stock at the effective time of the Merger will be exchanged for 0.25 common shares of Mainland. Based on the estimated number of shares of Mainland issued and outstanding on the record date, Mainland expects to issue approximately 14,929,500 common shares to American Exploration stockholders in the Merger. We estimate that immediately after the effective time of the Merger, former stockholders of American Exploration will hold common shares of Mainland representing approximately 15.6% of the then-outstanding common shares of Mainland.

In addition: (a) all outstanding common stock options of American Exploration will be disposed of by the holders thereof in consideration for the issue by Mainland of non-transferable stock options; and (b) all of the outstanding common stock purchase warrants of American Exploration will be disposed of by the holders thereof in consideration for the issue by Mainland of non-transferable common stock purchase warrants. The number of Mainland options and warrants issuable will be determined with reference to the exchange ratio which determines the number of shares of Mainland common stock that are to be issued on completion of the Merger for all of the shares of American Exploration common stock.

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We are a natural resource exploration company engaged in the exploration, acquisition and development of oil and gas properties in North America. We are currently focused on our interests in oil and gas prospects located in Louisiana and Mississippi.

Until recently, acting primarily through our joint venture with Petrohawk Energy Corporation, we have been concentrating on exploring and developing certain natural gas leases covering approximately 2,904 net acres in the East Holly Field of De Soto Parish, in the State of Louisiana.

Our joint venture agreement with Petrohawk contemplated the development of the Haynesville Shale on the East Holly Field leases, with Petrohawk as operator. We transferred 60% of our interest in the De Soto Parish leases to Petrohawk, but only with respect to the Haynesville Shale below the Cotton Valley formation - in other words, Petrohawk acquired 60% of our Company's interest in the leases at all depths below the base of the Cotton Valley formation (which has been defined to be 100 feet below the stratigraphic equivalent of the Cotton Valley formation). In return, Petrohawk agreed to, among other things, pay 100% of the costs of development associated with the first well drilled below the Cotton Valley formation, as well as costs up to and including pipeline connection. The first well, the Griffiths 11-1, began drilling in October 2008 and commenced production at the end of January 2009. One additional producing well has since been drilled and completed under our joint venture with Petrohawk. Two additional wells have been drilled and are being completed, and the fifth is currently being drilled.

In early 2010, we entered into a purchase and sale agreement for the sale to EXCO Operating Company, LP, a wholly owned subsidiary of Exco Resources (NYSE - XCO), of our remaining 40% interest in the Haynesville Shale portion of the East Holly Field leases, for $28,159,604. This agreement, which closed on April 22, 2010 with an effective date of January 1, 2010, provided for the sale of all of our Company's right, title and interest 100 feet below the base of the Cotton Valley formation in the East Holly Field. As noted above, the base of the Cotton Valley formation has been defined to be 100 feet below the stratigraphic equivalent of the Cotton Valley formation.

We have retained all of the rights in all formations above the base of the Cotton Valley formation in the East Holly Field, encompassing 2,745 net acres with an estimated 65 net potential drilling locations. The four recent wells drilled by the original operator through the Hosston and Cotton Valley zones to the Haynesville formation calculate as productive.

Based on the available data and economics, we plan to drill three wells as operator in the Hosston/Cotton Valley formations in 2010, and also to evaluate the shale gas production value of the Upper Bossier formation on the DeSoto Parish leases. We expect that these formations will provide continual solid pay with little risk and predictable development costs.

Our Buena Vista Prospect is located along the Gulf Coast Salt Basin in the Buena Vista area of Jackson County, Mississippi. Based on proprietary information gained from previous drilling, we believe an extension of the Haynesville Shale similar to the discovery region in Louisiana may exist there.

Our Company has entered into a joint area development agreement with American Exploration to jointly develop contiguous acreage comprising the Buena Vista Prospect. As operator on the Buena Vista Prospect, we recently issued an Authority for Expenditure (AFE) for the Burkley-Phillips No. 1 Well to be drilled on the Prospect. We intend to drill the well to a depth sufficient to evaluate the Haynesville Shale formation, currently expected to total 22,000 feet. The AFE estimates the drilling cost to be approximately $8,650,000 and completion cost to be approximately $4,900,000 for a total completed well cost of approximately US$13,550,000. Drilling is expected to commence in the latter part of the second quarter of 2010.

American Exploration was unable to fund its 20% share of the estimated total well costs of the Burkley-Phillips No. 1 Well. As a result, American Exploration has forfeited its right to a 29% working interest in the well and in the Buena Vista Prospect in otall of our Company. American Exploration will continue to be entitled to receive a 20% working interest in the well and the Prospect after completion (subject to compliance by American Exploration with all other terms and conditions of our letter agreement and related joint operating agreement with American Exploration).

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We were previously required to pay 72% of the total cost to drill and complete the Burkley-Phillips No. 1 Well, for a 45.9% working interest. Due to American Exploration's inability to make its contribution in response to the cash call, we will now pay 90% of the total cost of the well to earn a 72% interest, and Guggenheim Energy Opportunities, LLC ("Guggenheim") will pay 10% of the total cost to earn an 8% interest.

Our East Holly Field leases cover a central area in the fairway of what is now widely recognized as the Haynesville Shale discovery in northwest Louisiana (see Figure 1 - Location Map). The Haynesville Shale has become one of the most active natural gas plays in the United States. The Haynesville formation is located approximately 1,500 feet below the base of the Cotton Valley formation at depths ranging from approximately 10,500 feet to 13,000 feet. The formation is as much as 300 feet thick and is composed of a rich organic black shale. It is located across northwest Louisiana (primarily in Caddo, Bossier, Red River, DeSoto, Webster and Bienville Parishes), east Texas (primarily in Harrison, Panola, Shelby and Nacogdoches Counties), and extends into Arkansas.

On February 27, 2008, we entered into an option agreement with Kingsley Resources, Inc., a Nevada corporation, pursuant to which we acquired all the right, title and interest Kingsley had in and to certain leasehold estates located in East Holly Field of De Soto Parish. The East Holly Field leases create a contiguous block of acreage on the southeast flank of the East Holly Field, otalling approximately 2,551 net acres. The leases were the subject of a leasehold purchase agreement dated December 11, 2007, and modified February 1, 2008, between Kingsley and Permian Basin Acquisition Fund, pursuant to which Kingsley acquired the sub-surface rights covered by the East Holly Field leases.

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In accordance with the terms and provisions of our option agreement with Kingsley, we were required to pay $100,000 to Kingsley (which represented reimbursement to Kingsley of a deposit paid by it to Permian under their leasehold purchase agreement) and assume all of Kingsley's obligations under its leasehold purchase agreement with Permian. We completed the acquisition of the East Holly Field leases by way of assignment on March 14, 2008 at a total cost of $687,596, comprised of the $100,000 payment to Kingsley (which was subsequently made on April 2, 2008), and payments to Permian totalling $587,596. The East Holly Field leases remain subject to a residual royalty payment and other rights reserved under the leasehold purchase agreement with Permian.

In accordance with the area of mutual interest provision contained in our joint operating agreement with Petrohawk, we and Petrohawk leased an additional 353.77 net acres, and the acreage and costs were split as to 60% for Petrohawk, and as to 40% for our Company. We have a 100% working interest and a 75% net revenue interest in the Cotton Valley/Haynesville leases.

Our Buena Vista leasehold and project is located in the Gulf Coast Salt Basin trend, outside of the core area initially exploited for the Haynesville Shale. Management believes that over-thickened Haynesville Shale deposits can be isolated which are rich in organic carbon, possess superior rock properties and are gas-charged. A deep well drilled on the leases in 1981 confirmed the presence of highly pressured natural gas within an over-thickened Haynesville shale section. The well was drilled to a depth of 22,000 feet, reaching total depth while still within the Haynesville Shale. A poor understanding of shale gas 28 years ago combined with a casing problem in the wellbore, encouraged the operator to plug and abandon the well.

We have been able to secure a full suite of data from that well/project area which included all geophysical seismic data, well logs, drill cuttings, drilling reports, and related technical information. This information was critical in determining the quality of the gas within the reservoir, the propensity of the Haynesville Shale to produce gas on the leases, as well as the gas in place per section.

A geophysical assessment of the property was commissioned. Seismic lines crossing the property were reprocessed and a detailed interpretation was made by a geophysicist with strong knowledge of the play. A well-defined turtle structure was mapped and the leased acreage which sits squarely on the crest is ideally positioned for gas accumulation. A series of maps were produced which image the reservoir surface as well as other potentially prospective horizons on the property. These maps also assist in better evaluating surrounding acreage.

Rock data (cuttings samples) were viewed and sampled and sent to a rock evaluation lab for testing. Parameters such as mineralogy and geochemistry were measured using x-ray diffraction and rock evaluation pyrolysis. Thin section (microscope slide) work was also conducted to better evaluate rock type, mineral characteristics and porosity styles. This data was then provided to a leading petrophysical group who has experience with the Haynesville Shale to complete a petrophysical analysis (log analysis) of the entire prospective section, which included all of the penetrated Haynesville formation.

The results of these extensive studies suggested that the leases of interest contain significant hydrocarbons. Since the Haynesville is so thick in this locale, vertical wells can be used to develop the property, reducing costs and many of the drilling challenges associated with horizontal wellbores.

Effective July 14, 2008, we entered into a binding letter agreement with Petrohawk Energy Corporation relating to the joint development of acreage of our Company's leases in DeSoto Parish, Louisiana, including those in East Holly Field and Cotton Valley/Haynesville.

Under the letter agreement: (i) Petrohawk agreed to pay 100% of the development costs of the first well drilled below the base of the Cotton Valley formation (which, as noted above, has been defined to be 100 feet below the stratigraphic equivalent of the Cotton Valley formation), including those related to drilling, completion and fracture stimulation, as well as costs up to and including pipeline connection; (ii) Petrohawk agreed to pay 80%, and we agreed to pay 20%, of all costs of the second well drilled below the base of the Cotton Valley formation; (iii) Petrohawk agreed to pay 60%, and we agreed to pay 40%, of all costs of the third well and all additional wells drilled below the base of the Cotton Valley formation; and (iv) we agreed to transfer a 60% working interest in our leases in DeSoto Parish to Petrohawk at closing, but only as such leases related to all depths below the base of the Cotton Valley formation, and specifically the Haynesville Shale. Petrohawk further agreed to gather and market our production from above the base of the Cotton Valley formation pursuant to a mutually acceptable agreement. The letter agreement was expressly made subject to completion of due diligence investigation by the parties, and execution and delivery of a definitive agreement by both parties.

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We entered into a definitive agreement with Petrohawk effective August 4, 2008, pursuant to which we effectively transferred and conveyed to Petrohawk 60% of our right, title and interest in and to the leases in the DeSoto Parish. Petrohawk was designated as the operator on all development relating to these leases.

The initial well under our agreement with Petrohawk, the Griffith 11-1 Well, was spudded on October 20, 2008, and commenced production at the end of January 2009. The approximate reading for total gas produced from the Griffith 11-1 Well and shipped to market through April 5, 2010 was 2.5 billion cubic feet (Bcf).

Drilling began on the second well under our agreement with Petrohawk, the Stevenson Douglas LLC 16-1 Well, in April 2009. The Stephenson Douglas LLC 16-1 Well has spudded, and surface casing was cemented at about 1800 feet. The Stephenson Douglas LLC 16-1 Well has been successfully drilled to a depth of 10,700 feet and 7 5/8 inch intermediate casing was run on the well to this depth. Petrohawk scheduled a larger rig capable of whip stocking the well and drilling the lateral portion of the wellbore. The well was completed and commenced production in March 2010.

The third well to be drilled, the Dehan 15-1 Well, was drilled in May 2009 and commenced production in August 2009. The well had an initial production rate (IP) of 7.643 million on a 14/64^th choke. The approximate reading for total gas produced from the Dehan 15-1 Well and shipped to market through April 5, 2010 was 1.7 billion cubic feet (Bcf).

The fourth well has been drilled and awaiting completion. The fifth well is being drilled and is close to total depth.

On March 12, 2010, we entered into a purchase and sale agreement for the sale to EXCO Operating Company, LP, a wholly owned subsidiary of Exco Resources, of our remaining 40% interest in the Haynesville Shale portion of the East Holly Field leases, for $28,159,604. This agreement, which closed on April 22, 2010 with an effective date of January 1, 2010, provided for the sale of all of our right, title and interest below the base of the Cotton Valley formation in the East Holly Field.

Under the purchase and sale agreement: (i) our Company sold its remaining 40% working interest in the Haynesville Shale, covering 2,903 acres or 1,161 net acres; and (ii) the purchaser paid to our Company $17,500 per net acre, totalling $20,321,525, subject to certain adjustments. The purchaser also agreed to be responsible for ad valorem, property or similar taxes, and to reimburse our Company for any and all out-of-pocket operating costs and capital expenditures costs incurred by us prior to closing (which otallin $7,838,079).

We intend to apply the net proceeds to: (a) provide initial funding for the drilling of up to three wells in the Hosston/Cotton Valley formations of the East Holly Prospect in 2010; (b) fund the drilling of the Burkley-Phillips No. 1 well on the Buena Vista prospect in Mississippi; and (c) to retire our debt to Guggenheim. Additional funding will be required to complete our 2010-2011 operations program. We anticipate that we will receive this funding from a variety of methods, including private placements, equity funding, entering into joint venture transactions with third parties, mezzanine financing and cash flows from successful wells.

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As indicated above, we continue to retain all rights to all formations above the base of the Cotton Valley formation, encompassing the 2,745 net acres (including the Hosston and Cotton Valley zones) with an estimated 65 net potential drilling locations. Detailed analysis of the Cotton Valley/Hosston and Upper Bossier formations on the East Holly Field has been facilitated by review of the drill logs obtained from our previous Haynesville Shale joint venture partner, Petrohawk Energy. The four recent wells drilled by Petrohawk on the leases calculate as productive from all three formations.

Our Company and Brammer Engineering, Inc., of Shreveport, Louisiana, have entered into a Contract Operating Agreement dated April 1, 2010 relating to the first of three wells that we are planning to drill in the Cotton Valley/Hosston and Upper Bossier formations of the East Holly Field. The initial well is to be drilled in Section 11, T 13N-R14W, DeSoto Parish, Louisiana, to test these formations. Brammer Engineering will act as contract operator for our Company, the operator of the Prospect. Brammer Engineering is a highly qualified contract operator that has been active in the Louisiana and Gulf Coast Region for 40 years. It has drilled over 130 wells and acted as operator on more than 300 wells.

We have initiated the drilling and site preparation necessary to spud the well in the latter part of the second quarter or early third quarter of 2010.

Depending on results of the Upper Bossier formation, the total completed well cost is estimated at between US$2 million and $2.25 million dollars. We will fund 100% of the costs of this initial well.

We entered into a letter agreement with American Exploration effective September 17, 2009, to jointly develop contiguous acreage known as the Buena Vista area located in Jefferson County, Mississippi (see Figure 2 - Location Map). Under our agreement with American Exploration: (i) we and American Exploration each agreed to commit at least 5,000 net acres to the joint development project; (ii) we will be the operator of project; (iii) we agreed to pay 80% of the initial well drilling and completion costs, to earn a 51% working interest in the well and the total joint development project; and (iv) American Exploration agreed to pay 20% of the initial well drilling and completion costs to earn a 49% working interest in the well and the total joint development project. The agreement also contemplates that the future costs of the joint development project, including drilling and completions, will be split in accordance with the respective working interests of the parties.

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Prior to entering into our joint area development agreement with American Exploration, we entered into an option agreement with Westrock Land Corp. on June 22, 2009, to acquire approximately 8,000 net acres in mineral oil and gas leases located in the Buena Vista area. Under our option agreement with Westrock, we agreed to acquire a 100% working interest and a minimum 75% net revenue interest in the leases upon payment of certain acquisition costs per net mineral acres by August 31, 2009. On September 28, 2009, the option agreement was amended to expand the acreage to include an additional 225 acres, thereby increasing coverage under the option agreement to 8,225 net acres, and to extend the time for closing. At that time, we agreed to advance a payment of $300,000 towards the total purchase price on August 31, 2009. We paid an additional $900,000 towards the purchase price on October 13, 2009, and the final instalment of $2,090,060 on November 3, 2009, for a total purchase price of $3,290,060.

We satisfied our obligation under our joint area development agreement with American Exploration to contribute at least 5,000 net acres to the joint development project using the leases we acquired from Westrock. We and American Exploration have contributed 8,225.3 net acres and 5,000 net acres, respectively, of contiguous lands (for a total of approximately 13,225.3 net acres).

In early April, 2010, we, as operator, issued an Authority for Expenditure (AFE) for the Burkley-Phillips No. 1 Well to be drilled on the Buena Vista Prospect, in Jefferson County. We intend to drill the well to a depth sufficient to evaluate the Haynesville Shale formation, currently expected to total 22,000 feet. The AFE estimates the drilling cost to be approximately $8,650,000 and completion cost to be approximately $4,900,000 for a total completed well cost of approximately US$13,550,000.

American Exploration was unable to fund its 20% share of the estimated total well costs ($2,710,000) of the Burkley-Phillips No. 1 Well within the 30 day period provided for in the joint development agreement, which expired on April 23, 2010. As a result, American Exploration forfeited its 29% working interest in the well and the Prospect in otall of our Company. We currently hold interests in excess of 17,000 acres in the Buena Vista Prospect. American Exploration will continue to be entitled to receive a 20% working interest in the well and the Prospect after completion (subject to compliance by American Exploration with all other terms and conditions of the Letter Agreement and the related Joint Operating Agreement).

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Our Company was previously paying 72% of the total cost to drill and complete the Burkley-Phillips No. 1 Well, for a 45.9% working interest. Due to the fact American Exploration did not make its contribution in response to the cash call, Mainland will now pay 90% of the total cost of the well and Guggenheim Energy Opportunities, LLC ("Guggenheim") will pay 10%. Accordingly, the respective working interests of the parties after completion are anticipated to be as follows: Mainland - 72%, American Exploration -20%, and Guggenheim - 8%. This working interest breakdown will apply to the remainder of the leasehold and project area.

Extensive historic and proprietary data from a previous well drilled on the Buena Vista, combined with petrochemical analysis reviewed by Mainland's land and geological teams provide the basis for drilling the Burkley-Phillips No. 1 well to the deeper Haynesville formation. Additionally, it will be the only well drilled in the Buena Vista area testing the Haynesville shale formation since shale gas has emerged as a major production resource.

We have deposited an aggregate total of $8.65 million into escrow to be used to drill the Burkley-Phillips No. 1 well. The escrow funds are comprised of $7.785 million contributed by our Company and $865,000 contributed by Guggenheim. We, as operator, will drill the Burkley-Phillips No. 1 well using RAPAD Drilling & Well Service, Inc., of Jackson, Mississippi.

We have commenced road construction and drill site preparations for the Burkley-Phillips No. 1 Well, and we are currently planning to spud the well June 15, 2010 or thereabouts. The permitting for the well is now complete.

We had previously entered into an option agreement with Westrock effective September 3, 2008, to acquire 5,000 net acres in certain other mineral oil and gas leases located in the State of Mississippi. Under the option agreement: (i) our Company was to acquire a 100% working interest and a minimum 75% net revenue interest in the leases; (ii) we paid a $500,000 deposit on September 3, 2008 to secure the option, and agreed to pay certain acquisition costs per net mineral acres by August 31, 2009; and (iii) the balance of the acquisition costs, otalling $2,275,000, were due and payable upon completion, no later than October 15, 2008, of our due diligence investigation of the underlying properties. The option period was ultimately extended to January 20, 2010, pursuant to successive amending agreements executed on each of October 15, 2008, November 30, 2008, April 16, 2009 and June 1, 2009. We paid additional deposits of $250,000, $100,000, $250,000, $100,000 and $100,000, respectively, on October 17, 2008, December 1, 2008, December 29, 2009, April 27, 2009, May 6, 2009 and June 5, 2009, for an aggregate deposit of $1,300,000.

Our Company's Board of Directors determined that, based on the results of our due diligence investigation of the underlying properties, it was not in the best interests of our Company and its stockholders to proceed with the acquisition and development of the leases covered by our option agreement with Westrock dated September 3, 2008. Therefore, we and Westrock agreed to the termination of the option agreement without any further obligation on the part of either party. In accordance with the terms of our option agreement with Westrock, we forfeited our deposit of $1,300,000.

RESERVES

On January 14, 2009, the SEC published the final rules for "Modernization of Oil and Gas Reporting" in the Federal Register, which apply to oil and gas reserves estimates disclosed in registration statements and annual reports containing financial statements for fiscal years ending on or after December 31, 2009. The new disclosure requirements supersede SEC Industry Guide 2 and are consolidated in new Subpart 1200 of Regulation S-K, and include certain revisions and additions to the definition section of Rule 4-10 of Regulation S-X. In addition, the amendments concurrently align the full cost accounting rules with the revised disclosures.

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Generally, the new disclosure rules require reporting of oil and gas reserves using a price based on a 12-month unweighted average of the first-day-of-the-month prices rather than year-end prices, and permit the use of new technologies to determine proved reserves if they are demonstrated to result in reliable conclusions about reserve volumes. The new rules also permit disclosure of probable and possible reserves meeting new SEC definitions in SEC filed documents, as well as additional reserve cases showing pricing and cost sensitivities. In addition, an oil and gas company is required to report the independence and qualifications of its reserves preparer or auditor, and to file reports when a third party is relied upon to prepare reserves estimates or engaged to conduct a reserves audit.

As noted above, the modernization disclosure requirements apply to oil and gas reserves estimates disclosed in registration statements and annual reports containing financial statements for fiscal years ending on or after December 31, 2009. This may make comparisons to prior periods difficult.

Our Company's senior management, under the supervision of our Board of Directors, is responsible for the preparation of our estimates of proved reserves at February 28, 2010 and 2009. Our proved reserves are estimated at the property level and compiled for reporting purposes by our external engineers with input from our senior management. Reserves are reviewed and approved internally by our senior management and audit committee. As of our fiscal year ended February 28, 2010, Michael J. Newport, our President and Chief Executive Officer, was the person at our Company primarily responsible for overseeing the preparation or our reserves estimates and was also the person who received the report of our external engineers, Ryder Scott Company, L.P.

Our management works closely with our external engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. We provide our external engineers with pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel and consultants, to the external engineers as part of their evaluation of our reserves. Reserve database security is provided by our external engineers, who maintain these databases for us.

As part of the Company's internal control process, we performed a year-to-year reconciliation. The Company's senior management determined that there was no need for a look-back analysis due to the Company's decision to sell the Haynesville Shale asset. At the time the Company negotiated the sale of the asset, we used estimates of remaining reserves to determine a fair value.

Qualifications of responsible technical persons

Michael J. Newport, our Company's President and Chief Executive Officer, has been actively involved in petroleum land management for nearly thirty years, with experience in all phases of oil and gas land management and expertise in acquisitions, operations, divestitures, agreement preparation, negotiations, CAD mapping and broker supervision.

Mr. Newport started his career with Amoco in its New Orleans office in May 1979 where he spent two years. He was actively involved in supervising brokers and writing all forms of land contracts for North and South Louisiana, Mississippi, Alabama and Florida.

In 1981, Mr. Newport became a district landman for Harkins & Company in its Jackson, Mississippi office where he spent four years assembling drilling prospects and all land activities associated with operations in Mississippi, Alabama, Florida and Louisiana. From 1985 to 1989, Mr. Newport was posted to Harkins & Company's Oklahoma City office where he had the same responsibilities for Oklahoma and Arkansas as well as Mississippi, Alabama, Florida and Louisiana.

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Mr. Newport joined Greenhill Petroleum in 1989 in Houston, Texas, where he was the land manager for six years in the Permian Basin Region. In addition to land management activities, Mr. Newport was responsible for acquisitions and divestitures.

After leaving Greenhill, Mr. Newport has spent the last thirteen years managing brokers for West Texas, South Texas, East Texas, Oklahoma and North Louisiana as well as performing all landman management activities for various operators actively drilling and completing wells in these areas.

Mr. Newport received a Bachelor of Business Administration (Finance) degree in June of 1977, a Master of Business Administration degree in August of 1978, and also completed the required hours for a Petroleum Land Management degree in May, 1979.

Simeon King Horton, one of our Company's directors, is a Petroleum Geologist with over thirty years' experience, and provides geological consulting services to Mainland from time to time on a per diem basis. Ms. Horton has an extensive background in exploration and development of major oil and gas projects working as a consultant for oil and gas companies.

Ms. Horton worked for Mr. Dudley Hughes, an independent geologist, in Jackson, Mississippi, from 1977 to 1986. During that time, she gained broad experience in the Mississippi/Alabama Salt Basin, Black Warrior Basin in North Mississippi and Northwest Alabama, and South Florida. The main targets of exploration were the

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Smackover/Norphlet Formations (located in the Salt Basin), the Paleozoics (located in the Black Warrior Basin), and the Sunniland Lime (located in South Florida). Ms. Horton was also exposed to the Perth Basin in Australia. As District Geologist, she was extensively involved in the exploration and development of a very aggressive drilling program and all facets of the industry.

In 1986, Ms. Horton moved to Shreveport, Louisiana where she was a consultant for various oil and gas investors until 1989.

From 1989 to 1996, Ms. Horton worked with Grigsby Petroleum in Shreveport, Louisiana, a company owned by Mr. Jack Grigsby, an independent geologist. Grigsby Petroleum is very active in North Louisiana and East Texas with numerous properties. Among these are Hosston and Cotton Valley production. Ms. Horton was responsible for all the producing properties, the development of the properties, and the drilling of new wells for Grigsby Petroleum.

From 1996 to present, Ms. Horton has been a consulting petroleum geologist. She has been very active in the Hosston/Cotton Valley trends in North Louisiana and East Texas. She has generated drilling prospects in the area, and has successfully been responsible for the drilling of the Hosston/Cotton Valley in an area where there are sixteen to twenty wells per section.

Simeon King Horton received a Bachelor of Science degree with a Major in Geology and a Minor in Mathematics from the University of Southern Mississippi, Hattiesburg, Mississippi in 1977. She graduated with honors and was selected Outstanding Graduating Senior in Geology for the academic year of 1976-1977. She attended geology field camp thru the Rolla School of Mines, University of Missouri, which was conducted in the state of Utah.

Ms. Horton is an active member of the American Association of Petroleum Geologist and the Shreveport Geological Society, Shreveport, Louisiana.

The reserves estimates as of February 28, 2010 disclosed herein have been independently prepared by Ryder Scott Company, L.P., a petroleum consulting engineering firm with offices in Houston, Texas, Calgary, Alberta, and Denver, Colorado. Within Ryder Scott, the technical person primarily responsible for overseeing the estimation and evaluation process with respect to the preparation of Ryder Scott's report dated May 11, 2010, filed as an exhibit hereto, was Mr. Joseph E. Blankenship. Mr. Blankenship, an employee of Ryder Scott since 1982, is a Senior Vice President and also serves as chief technical advisor for unconventional reserves evaluation.

Mr. Blankenship is responsible for coordinating and supervising Ryder Scott's staff and consulting engineers in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Blankenship served in a number of engineering positions with Exxon Company USA.

Mr. Blankenship earned a Bachelor of Science degree in Mechanical Engineering from the University of Alabama in 1977. He is a member of the Honorary Engineering Society Pi Tau Sigma and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers (SPE) and the Society of Petroleum Evaluation Engineers (SPEE).

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Blankenship fulfills. As part of his 2009 continuing education hours, Mr. Blankenship attended an internally presented 17 hours of formalized training as well as Ryder Scott's day long 2009 Reserves Conference, and a presentation by Dr. John Lee, on the new SEC regulations relating to the "Modernization of Oil and Gas Reporting," published in the Federal Register on January 14, 2009. Mr. Blankenship attended an additional 2 hours of formalized in-house training as well as 15 hours of formalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. Mr. Blankenship was class instructor in Ryder Scott's 2009 in-house course on unconventional reserves evaluation.

Based on his educational background, professional training and more than 32 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Blankenship has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the Society of Petroleum Engineers as of February 19, 2007.

Our Oil And Natural Gas Reserves

The following tables set forth our estimated net proved oil and natural gas reserves at February 28, 2010. The subject properties are the Griffith 11-1 well and the Dehan et al. 15H-1 well, both of which are located in the East Holly Field, Desoto Parish, Louisiana. The reserves and income data were estimated based on the definitions and disclosure guidelines of the SEC contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule, released January 14, 2009 in the Federal Register.

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Note:

Notes:

1.   On March 12, 2010, we entered into a purchase and sale agreement for the sale to EXCO Operating Company, LP, a wholly owned subsidiary of Exco Resources, of its remaining 40% interest in the Haynesville Shale portion of the East Holly Field leases, for $28,159,604. This agreement, which closed on April 22, 2010 with an effective date of January 1, 2010, provided for the sale of all of our right, title and interest below the base of the Cotton Valley formation in the East Holly Field.

2.   All gas volumes are reported on an "as sold" basis expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of Louisiana, which are 60 degrees Fahrenheit and 15.025 psi. No attempt has been made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The gas volumes included herein do not attribute gas consumed in operations as reserves.

3.   The future gross revenue is after the deduction of production taxes.

4.   The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, gathering and treating fees and certain abandonment costs net of salvage.

5.   The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

6.   Gas hydrocarbon reserves account for 100 percent of total future gross revenue from proved reserves.

Reserve engineering is a subjective process of estimating underground accumulations of natural gas that cannot be measured in an exact manner. More specifically, reserves are those estimated remaining quantities of petroleum which are anticipated to be economically producible, as of a given date, from known accumulations under defined conditions. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Furthermore, estimated reserves may or may not be actually recovered, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

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Furthermore, the estimated reserves and future net income amounts disclosed in this proxy statement/prospectus as of February 28, 2010, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of Ryder Scott's report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented.

All reserve estimates involve some degree of uncertainty. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Mainland's request, Ryder Scott's report addresses only the proved reserves attributable to the properties evaluated therein.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The reserves included in this annual report were estimated using deterministic methods.

The reserves disclosed in this annual report are limited to the period prior to expiration of current contracts providing the legal rights to produce or a revenue interest in such production unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Mainland for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with our Company the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither Ryder Scott's review of such contractual information nor their acceptance of our Company's representations regarding such contractual information should be construed as a legal opinion on this matter.

Our Company's operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include matters relating to land tenure, drilling, production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which we own an interest; however, Ryder Scott did not make any field examination of the properties. Further, no consideration was given in Ryder Scott's report to potential environmental liabilities that may exist, nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

As disclosed above, subsequent to our financial year end, we entered into a purchase and sale agreement dated March 12, 2010, for the sale to EXCO Operating Company, LP, a wholly owned subsidiary of Exco Resources, of our remaining 40% interest in the Haynesville Shale portion of the East Holly Field leases, for $28,159,604. This agreement, which closed on April 22, 2010 with an effective date of January 1, 2010, provided for the sale of all of our right, title and interest below the base of the Cotton Valley formation in the East Holly Field. Accordingly, we no longer hold any reserves.

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Our Company is an "OTC Reporting Issuer" as defined in BC Instrument 51-509, Issuers Quoted in the U.S. Over-the-Counter Markets, adopted by the British Columbia Securities Commission, and is therefore subject to National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (NI 51-101), adopted by the Canadian Securities Administrators, which prescribes the standards for the preparation and disclosure of reserves and related information for companies subject to continuous disclosure requirements under Canadian provincial securities legislation.

As required by NI 51-101, we have disclosed reserves estimates at February 28, 2010 and 2009 in certain filings we have made with the British Columbia Securities Commission which have been evaluated by Ryder Scott Company, LP. Such evaluation of our estimates of proved reserves under NI 51-101 at February 28, 2010 and 2009 was carried out in accordance with the standards set out in the Canadian Oil and Gas Evaluation (COGE) Handbook, prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society). Those standards require that the evaluator plan and perform an evaluation to obtain reasonable assurance as to whether the reserves are free of material misstatement. An evaluation must also include an assessment as to whether the reserves data are in accordance with the principles and definitions presented in the COGE Handbook.

As indicated above, Petrohawk acquired 60% of our Company's right, title and interest in and to the leases in the DeSoto Parish in August 2008. Petrohawk has been designated as the operator on all development relating to these leases, and carried out all drilling and extractive operations during the fiscal years ended February 28, 2010 and 2009. Petrohawk has reported that its current horizontal drilling and completion methodology focuses on completing wells with longer laterals and maximizing the number of fracture stages, spaced approximately 325 feet apart. The objective of this technique is to minimize the total number of wells required to effectively drain the reservoir, resulting in lower overall development costs. Petrohawk also reports that it is currently targeting lateral lengths between 4,300 feet and 4,800 feet with up to 15 fracture stages.

The initial well under our agreement with Petrohawk, the Griffiths 11-1 Well, was spudded on October 20, 2008, and commenced production at the end of January 2009.

Drilling began on the second well under our agreement with Petrohawk, the Stevenson Douglas LLC 16-1 Well, in April 2009. The Stephenson Douglas LLC 16-1 Well has spudded, and surface casing was cemented at about 1800 feet. The Stephenson Douglas LLC 16-1 Well has been successfully drilled to a depth of 10,700 feet and 7 5/8 inch intermediate casing was run on the well to this depth. Petrohawk scheduled a larger rig capable of whip stocking the well and drilling the lateral portion of the wellbore. The well was completed and commenced production in March 2010.

The third well to be drilled, the Dehan 15-1 Well, was drilled in May 2009 and commenced production in August 2009. The well had an initial production rate (IP) of 7.643 million on a 14/64^th choke. The approximate reading for total gas produced from the Dehan 15-1 Well and shipped to market through April 5, 2010 was 1.7 billion cubic feet (Bcf).

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The fourth well has been drilled and awaiting completion. The fifth well is being drilled and is close to total depth.

The table below sets forth the results of drilling activities undertaken by Petrohawk, as operator, the De Soto Parish leases during the periods indicated:

Note:

1.   Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history.

The table below sets forth the net quantities of gas production (net of all royalties, overriding royalties and production due to others) attributable to us for fiscal years ended February 28, 2010 and 2009, and the average sales prices, average costs per unit of production.

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Notes:

1.   On March 12, 2010, we entered into a purchase and sale agreement for the sale to EXCO Operating Company, LP, a wholly owned subsidiary of Exco Resources, of its remaining 40% interest in the Haynesville Shale portion of the East Holly Field leases, for $28,159,604. This agreement, which closed on April 22, 2010 with an effective date of January 1, 2010, provided for the sale of all of our right, title and interest below the base of the Cotton Valley formation in the East Holly Field.

2.   A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.

3.   Net wells represent our working interest share of each well. The term "net" as used in "net production" throughout this document refers to amounts that include only acreage or production that we own and produce to our interest, less royalties and production due to others.

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Notes:

1.   Consists of acres spaced or assignable to productive wells.

2.   On March 12, 2010, we entered into a purchase and sale agreement for the sale to EXCO Operating Company, LP, a wholly owned subsidiary of Exco Resources, of its remaining 40% interest in the Haynesville Shale portion of the East Holly Field leases, for $28,159,604. This agreement, which closed on April 22, 2010 with an effective date of January 1, 2010, provided for the sale of all of our right, title and interest below the base of the Cotton Valley formation in the East Holly Field.

As of February 28, 2010, we had 355, 5,347 and 2,868 net acres scheduled to expire by February 28, 2011, 2012 and 2013 , respectively, if production is not established or we take no other action to extend the terms. We plan to continue the terms of these licences through operational or administrative actions and do not expect a significant portion of our net acreage position to expire before such actions occur.

As of February 28, 2010, 2,290 net undeveloped acres were held by production.

We have no gas delivery commitments.

As of our fiscal year ended February 28, 2010, we hade no proved undeveloped reserves ("PUD").

The estimates of quantities of proved reserves above were made in accordance with the definitions contained in SEC Release No. 33-8995, Modernization of Oil and Gas Reporting.

We account for our oil and natural gas producing activities using the full cost method of accounting in accordance with SEC regulations. Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The net capitalized costs of evaluated oil and natural gas properties are subject to a quarterly full cost ceiling test.

The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization.

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We operate in a highly competitive industry, competing with major oil and gas companies, independent producers and institutional and individual investors, which are actively seeking oil and gas properties throughout the world together with the equipment, labour and materials required to operate properties. Most of our competitors have financial resources, staff and facilities substantially greater than ours. The principal area of competition is encountered in the financial ability to acquire good acreage positions and drill wells to explore for oil and gas, then, if warranted, drill production wells and install production equipment. Competition for the acquisition of oil and gas wells is intense with many oil and gas properties and/or leases or concessions available in a competitive bidding process in which we may lack technological information or expertise available to other bidders. Therefore, we may not be successful in acquiring and developing profitable properties in the face of this competition. No assurance can be given that a sufficient number of suitable oil and gas wells will be available for acquisition and development.

The production and sale of oil and gas are subject to various federal, state and local governmental regulations, which may be changed from time to time in response to economic or political conditions and can have a significant impact upon overall operations. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation, abandonment and restoration and environmental protection. These laws and regulations are under constant review for amendment or expansion. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. Changes in these regulations could require us to expend significant resources to comply with new laws or regulations or changes to current requirements and could have a material adverse effect on our business operations.

Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local authorities and agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.

Many states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells.

The Federal Energy Regulatory Commission ("FERC") regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by us, as well as the revenues received by us for sales of such production. Since the mid-1980's, FERC has issued a series of orders that have significantly altered the marketing and transportation of natural gas. These orders mandate a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services such pipelines previously performed. One of FERC's purposes in issuing the orders was to increase competition within all phases of the natural gas industry. Certain aspects of these orders may be modified as a result of various appeals and related proceedings and it is difficult to predict the ultimate impact of the orders on us and others. Generally, the orders eliminate or substantially reduce the interstate pipelines' traditional role as wholesalers of natural gas in favour of providing only storage and transportation service, and have substantially increased competition and volatility in natural gas markets.

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The price, which we may receive for the sale of oil and natural gas liquids, would be affected by the cost of transporting products to markets. FERC has implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. We are not able to predict with certainty the effect, if any, of these regulations on any future operations. However, the regulations may increase transportation costs or reduce wellhead prices for oil and natural gas liquids.

Our operations and properties will be subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may (i) require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; (ii) limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and (iii) impose substantial liabilities for pollution resulting from our operations. The permits required for several of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our business operations, as well as the oil and natural gas industry in general.

The Comprehensive Environmental, Response, Compensation, and Liability Act ("CERCL") and comparable state statutes impose strict, joint and several liabilities on owners and operators of sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. It is not uncommon for the neighbouring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of "hazardous substance," state laws affecting our operations impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as "non-hazardous," such exploration and production wastes could be reclassified as a hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements.

We intend to acquire leasehold interests in properties that for many years have produced oil and natural gas. Although the previous owners of these interests may have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties. In addition, some of our properties may be operated in the future by third parties over which we have no control. Notwithstanding our lack of control over properties operated by others, the failure of the operator to comply with applicable environmental regulations may, in certain circumstances, adversely impact our business operations.

The National Environmental Policy Act ("NEPA") is applicable to many of our planned activities and operations. NEPA is a broad procedural statute intended to ensure that federal agencies consider the environmental impact of their actions by requiring such agencies to prepare environmental impact statements ("EIS") in connection with all federal activities that significantly affect the environment. Although NEPA is a procedural statute only applicable to the federal government, a portion of our properties may be acreage located on federal land. The Bureau of Land Management's issuance of drilling permits and the Secretary of the Interior's approval of plans of operation and lease agreements all constitute federal action within the scope of NEPA. Consequently, unless the responsible agency determines that our drilling activities will not materially impact the environment, the responsible agency will be required to prepare an EIS in conjunction with the issuance of any permit or approval.

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The Endangered Species Act ("ESA") seeks to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species. Under ESA, exploration and production operation, as well as actions by federal agencies, may not significantly impair or jeopardize the species or their habitat. ESA provides for criminal penalties for wilful violations of the Act. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations are in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject us to significant expense to modify our operations or could force to discontinue certain operations altogether.

Management believes that we are in substantial compliance with current applicable environmental laws and regulations.

No research and development expenditures have been incurred, either on our account or sponsored by customers, to the date of our inception.

We do not employ any persons on a full-time or on a part-time basis. Michael J. Newport is our President and Chief Executive Officer and William D. Thomas is our Chief Financial Officer and Treasurer. These individuals are primarily responsible for all of our day-to-day operations. Our executive officers are retained and compensated in accordance with the terms and provisions of certain verbal consultant agreements. Other services are provided by outsourcing and consultant and special purpose contracts.

An investment in our common stock involves a number of very significant risks. You should carefully consider the following risks and uncertainties in addition to other information in evaluating our company and its business before purchasing shares of our common stock. Our business, operating results and financial condition could be seriously harmed due to any of the following risks. The risks described below are all of the material risks that we are currently aware of that are facing our company. Additional risks not presently known to us may also impair our business operations. You could lose all or part of your investment due to any of these risks.

We are an exploration stage oil and gas company with a history of operating losses. We expect to continue to incur losses in the foreseeable future, and may never be profitable. Although our Company has realized revenues, as of February 28, 2010, we have an accumulated deficit during the exploration stage of $17,948,946. Further, we sold our remaining 40% interest in the Haynesville Shale portion of the East Holly Field leases on April 22, 2010, with an effective date of January 1, 2010, and we no longer have interests in any producing oil and gas properties. Accordingly, we do not expect positive cash flow from operations in the foreseeable future.

Our Company's continuation as a going concern is dependent upon our ability to fund ongoing operations, carry out our business plan and ultimately to attain profitable operations, all of which is uncertain. Our audited financial statements for the year ended February 28, 2010 contain additional note disclosures to this effect, and the audited financial statements do not include any adjustments that might result from the outcome of this uncertainty. In addition, the report of our Company's independent registered accounting firm accompanying our audited financial statements contains an explanatory paragraph expressing substantial doubt about our ability to continue as a going concern.

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There can be no assurance that we will be able to raise sufficient additional capital or eventually have positive cash flow from operations to address all of our cash flow needs. If we are not able to find alternative sources of cash or generate positive cash flow from operations, our business and shareholders will be materially and adversely affected.

We sold our remaining 40% interest in the Haynesville Shale portion of the East Holly Field leases for $28,159,604 on April 22, 2010, with an effective date of January 1, 2010. We initially intended to apply the net proceeds to: (a) provide initial funding for the drilling of up to three wells in the Hosston/Cotton Valley formations of the East Holly Prospect in 2010; (b) fund the drilling of the Burkley-Phillips No. 1 well on the Buena Vista prospect in Mississippi; and (c) to retire our debt to Guggenheim. Additional funding will be required to complete our 2010-2011 operations program. We anticipate that we will receive this funding from a variety of methods, including private placements, equity funding, entering into joint venture transactions with third parties, mezzanine financing and cash flows from successful wells.

Furthermore, if the results of our initial exploratory drilling activities on the East Holly Prospect and/or the Buena Vista Prospect justify further work on the properties, we will require significant additional financing in order to continue our exploration activities and, if warranted, to undertake any development activities. Our exploration and development of, and participation in, what could evolve into an increasing number of oil and gas prospects may require substantial capital expenditures.

There can be no assurance that we will be successful in our efforts to raise these required funds, or on terms satisfactory to us. The continued exploration of our oil and gas properties, and the development of our business, will depend upon our ability to establish the commercial viability of our oil and gas properties, to develop cash flow from operations, and ultimately to achieve profitability, none of which can be assured.

We presently believe that debt financing (including project financing) will not be available to us as all of our properties are in the early exploration stage. Accordingly, we will have to continue to rely on equity financing, the availability of which cannot be assured or, if available, may result in substantial dilution to our existing stockholders. If equity financing is not available on terms that are satisfactory to us, we may be required to finance additional exploration work and, if merited, future development work on our oil and gas properties by offering interests in such properties to one or more third parties, on an earn-in basis.

If we are unable to obtain additional financing when it is required, we will not be able to continue our exploration activities and our assessment of the commercial viability of our oil and gas properties. Further, if we are able to establish that development of our oil and gas properties is commercially viable, our inability to raise additional financing at that stage would result in our inability to place our oil and gas properties into production and recover our investment.

There is no assurance that actual cash requirements will not exceed our estimates. In particular, additional capital may be required in the event that: (i) drilling and completion costs for the three wells that we are planning to drill in the Hosston/Cotton Valley formations of the East Holly Prospect and the Burkley-Phillips No. 1 well on the Buena Vista Prospect increase beyond our expectations; or (ii) we encounter greater costs associated with general and administrative expenses or securities offering costs.

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Our existing properties do not contain reserves in accordance with the definitions adopted by the SEC and there is no assurance that any exploration program that we carry out will establish reserves. There is a substantial risk that our exploration activities will not result in discoveries of commercially recoverable reserves of oil or gas. Any determination that our property contains commercially recoverable quantities of oil or gas may not be reached until such time that final comprehensive feasibility studies have been concluded establishing that a potential reserve is likely to be economic. There is a substantial risk that any preliminary or final feasibility studies carried out by us will not result in a positive determination that any of our oil and gas properties can be commercially developed.

Our long-term success depends on our ability to establish commercially recoverable quantities of oil and natural gas on our properties that can then be developed into commercially viable operations. Oil and gas exploration is highly speculative in nature, involves many risks and is frequently non-productive. These risks include unusual or unexpected geologic formations, and the inability to obtain suitable or adequate machinery, equipment or labour. The success of oil and gas exploration is determined in part by the following factors:

• identification of potential oil and natural gas reserves based on superficial analysis;
• availability of government-granted exploration permits;
• the quality of management and geological and technical expertise; and
• the capital available for exploration.

Substantial expenditures are required to establish proven and probable reserves through drilling and analysis, to develop processes to extract oil and gas, and to develop the drilling and processing facilities and infrastructure at any chosen site. Whether an oil and gas reserve will be commercially viable depends on a number of factors, which include, without limitation, the particular attributes of the reserve; oil and natural gas prices, which fluctuate widely; and government regulations, including, without limitation, regulations relating to prices, taxes, royalties, land tenure, land use, importing and exporting of oil and gas and environmental protection. We may invest significant capital and resources in exploration activities and abandon such investments if we are unable to identify commercially exploitable reserves. The decision to abandon a project may reduce the trading price of our common stock and impair our ability to raise future financing. We cannot provide any assurance to investors that we will discover or acquire any oil or gas reserves in sufficient quantities on any of our properties to justify commercial operations. Further, we will not be able to recover the funds that we spend on exploration if we are not able to establish commercially recoverable reserves of oil or natural gas on our property.

Prospects that we decide to drill may not yield natural gas or oil in commercially viable quantities. Our prospects were in the stage of preliminary evaluation and assessment and we have decided to drill on the property. However, the use of seismic data, historical drilling logs, offsetting well information, and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling and testing whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in sufficient quantities or quality to recover drilling or completion costs or to be economically viable.

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Although extensive historic and proprietary data from a previous well drilled on the Buena Vista, combined with petrochemical analysis reviewed by our Company's land and geological teams have provided the basis for drilling the Burkley-Phillips No. 1 well to the deeper Haynesville formation, it will be the only well drilled in the Buena Vista area testing the Haynesville shale formation since shale gas has emerged as a major production resource. Similarly, although four recent wells drilled by the original operator through the Hosston and Cotton Valley zones to the Haynesville formation on the East Holly Prospect calculate as productive, the three wells that we are planning to drill in the Hosston and Cotton Valley formations are exploratory in nature and intended to evaluate the shale gas production value of these formations.

There can be no assurance that our current drilling activities will be successful, and we may not recover all or any portion of our capital investment in the wells or the underlying leaseholds. Unsuccessful drilling activities would have a material adverse effect upon our results of operations and financial condition. The cost of drilling, completing, and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations including: (i) unexpected drilling conditions; (ii) pressure or irregularities in geological formations; (iii) equipment failures or accidents; (iv) adverse weather conditions; and (iv) shortages or delays in availability of drilling rigs and delivery of equipment.

The properties from which we intend to produce natural gas frequently contain water, which may hamper our ability to produce gas in commercial quantities. The amount of natural gas that can be commercially produced depends upon the coal quality, the original gas content of the coal seam, the thickness of the seam, the reservoir pressure, the rate at which gas is released from the coal, and the existence of any natural fractures through which the gas can flow to the well bore. However, coal beds frequently contain water that must be removed in order for the gas to detach from the coal and flow to the well bore. The average life of a coal bed well is only five to six years. Our ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce coal bed methane in commercial quantities.

In considering whether to invest in our common stock, you should consider that there is only limited historical financial and operating information available on which to base your evaluation of our performance. Our inception was May 12, 2006 and, as a result, we have a limited operating history.

Initially, our activities were limited to organizational efforts, obtaining working capital and acquiring and developing a very limited number of mineral properties. Subsequently, we changed our business strategy from mineral exploration to oil and gas exploration. As a result, there is limited information regarding our oil and gas property related production potential or revenue generation potential.

The business of oil and gas exploration and development is subject to many risks and if oil and natural gas is found in economic production quantities, the potential profitability of future possible oil and gas ventures depends upon factors beyond our control. The potential profitability of oil and natural gas properties if economic quantities are found is dependent upon many factors and risks beyond our control, including, but not limited to: (i) unanticipated ground conditions; (ii) geological problems; (iii) drilling and other processing problems; (iv) the occurrence of unusual weather or operating conditions and other force majeure events; (v) lower than expected reserve quantities; (vi) accidents; (vii) delays in the receipt of or failure to receive necessary government permits; (viii) delays in transportation; (ix) labour disputes; (x) government permit restrictions and regulation restrictions; (xi) unavailability of materials and equipment; and (xii) the failure of equipment or drilling to operate in accordance with specifications or expectations.

As part of our growth strategy, we intend to acquire additional oil and gas production properties. Current and subsequent acquisitions may pose substantial risks to our business, financial condition, and results of operations. In pursuing acquisitions, we will compete with other companies, many of which have greater financial and other resources to acquire attractive properties. Even if we are successful in acquiring additional properties, some of the properties may not produce revenues at anticipated levels or failure to conduct drilling on prospects within specified time periods may cause the forfeiture of the lease in that prospect. There can be no assurance that we will be able to successfully integrate acquired properties, which could result in substantial costs and delays or other operational, technical, or financial problems. Further, acquisitions could disrupt ongoing business operations. If any of these events occur, it would have a material adverse effect upon our operations and results from operations.

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One of our growth strategies is to capitalize on opportunistic acquisitions of oil and natural gas reserves. However, our review of our current acquired property is inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. A detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Further, environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. We may not be able to obtain indemnification or other protections from the sellers against such potential liabilities, which would have a material adverse effect upon our results of operations.

World prices and markets for oil and gas are unpredictable, highly volatile, potentially subject to governmental fixing, pegging, controls, or any combination of these and other factors, and respond to changes in domestic, international, political, social, and economic environments. Additionally, due to worldwide economic uncertainty, the availability and cost of funds for production and other expenses have become increasingly difficult, if not impossible, to project. The potential profitability of oil and gas properties is dependent on these and other factors beyond our control. These factors may materially affect our financial performance if we are successful in our exploration activities and ultimately place any oil or gas wells into production, and, in the near term, may impact on our ability to raise financing for our exploration activities.

If we are successful in our exploration activities and ultimately place any oil or gas wells into production, the production area specifics will affect profitability. Adverse weather conditions can hinder drilling operations and ongoing production work. A productive well may become uneconomic in the event water or other deleterious substances are encountered which impair or prevent the production of oil and/or gas from the well. Production and treatments on other wells in the area can have either a positive or negative effect on our production and wells. In addition, production from any well may be unmarketable if it is impregnated with water or other deleterious substances. The content of hydrocarbons is subject to change over the life of producing wells. The marketability of oil and gas from any specific reserve which may be acquired or discovered will be affected by numerous factors beyond our control. These factors include, but are not limited to, the proximity and capacity of oil and gas pipelines, availability of room in the pipelines to accommodate additional production, processing and production equipment operating costs and equipment efficiency, market fluctuations of prices and oil and gas marketing relationships, local and state taxes, mineral owner and other royalties, land tenure, lease bonus costs and lease damage costs, allowable production, and environmental protection. These factors cannot be accurately predicted and the combination of these factors may result in us not receiving an adequate return on our invested capital.

If we are successful in our exploration activities and ultimately place any oil or gas wells into production, we will be dependent on the transportation and storage services offered by various interstate and intrastate pipeline companies for the delivery and sale of our gas supplies. Both the performance of transportation and storage services by interstate pipelines and the rates charged for such services are subject to the jurisdiction of the Federal Energy Regulatory Commission or state regulatory agencies. An inability to obtain transportation and/or storage services at competitive rates could hinder our processing and marketing operations and/or affect our sales margins.

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If we are successful in our exploration activities and ultimately place any oil or gas wells into production, the production area specifics will affect profitability, our revenue, profitability, and cash flow will depend upon the prices and demand for oil and natural gas. The markets for these commodities are very volatile and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Prices received also will affect the amount of future cash flow available for capital expenditures and may affect our ability to raise additional capital. Lower prices may also affect the amount of natural gas and oil that can be economically produced from reserves either discovered or acquired. Factors that can cause price fluctuations include: (i) the level of consumer product demand; (ii) domestic and foreign governmental regulations; (iii) the price and availability of alternative fuels; (iv) technical advances affecting energy consumption; (v) proximity and capacity of oil and gas pipelines and other transportation facilities; (vi) political conditions in natural gas and oil producing regions; (vii) the domestic and foreign supply of natural gas and oil; (viii) the ability of members of Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; (ix) the price of foreign imports; and (x) overall domestic and global economic conditions.

The availability of a ready market for our oil and gas, if any, will depend upon numerous factors beyond our control, including the extent of domestic production and importation of oil and gas, the relative status of the domestic and international economies, the proximity of our properties to gas gathering systems, the capacity of those systems, the marketing of other competitive fuels, fluctuations in seasonal demand and governmental regulation of production, refining, transportation and pricing of oil, natural gas and other fuels.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenues to return a profit. In addition, our drilling and producing operations may be curtailed, delayed or cancelled as a result of other drilling and production, weather and natural disaster, equipment and service failure, environmental and regulatory, and site specific related factors, including but not limited to: (i) fires; (ii) explosions; (iii) blow-outs and surface cratering; (iv) uncontrollable flows of underground natural gas, oil, or formation water; (v) natural disasters; (vi) facility and equipment failures; (vii) title problems; (viii) shortages or delivery delays of equipment and services; (ix) abnormal pressure formations; and (x) environmental hazards such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

If any of these events occur, we could incur substantial losses as a result of: (i) injury or loss of life; (ii) severe damage to and destruction of property, natural resources or equipment; (iii) pollution and other environmental damage; (iv) clean-up responsibilities; (v) regulatory investigation and penalties; (vi) suspension of our operations; or (vii) repairs necessary to resume operations.

If we were to experience any of these problems, it could affect well bores, gathering systems and processing facilities, any one of which could adversely affect our ability to conduct operations. We may be affected by any of these events more than larger companies, since we have limited working capital.

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The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Oil and gas operations are subject to federal, state, and local laws relating to the protection of the environment, including laws regulating removal of natural resources from the ground and the discharge of materials into the environment. Oil and gas operations are also subject to federal, state, and local laws and regulations which seek to maintain health and safety standards by regulating the design and use of drilling methods and equipment. Various permits from government bodies are required for drilling operations to be conducted; no assurance can be given that such permits will be received. Environmental standards imposed by federal, provincial, or local authorities may be changed and any such changes may have material adverse effects on our activities. Moreover, compliance with such laws may cause substantial delays or require capital outlays in excess of those anticipated, thus causing an adverse effect on us. Additionally, we may be subject to liability for pollution or other environmental damages which we may elect not to insure against due to prohibitive premium costs and other reasons. To date we have not been required to spend material amounts on compliance with environmental regulations. However, we may be required to do so in the future and this may affect our ability to expand or maintain our operations.

In general, our exploration activities are, and any future production activities will be, subject to certain federal, state and local laws and regulations relating to environmental quality and pollution control. Such laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Compliance with these laws and regulations has not had a material effect on our operations or financial condition to date. Specifically, we are subject to legislation regarding emissions into the environment, water discharges and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. However, such laws and regulations are frequently changed and we are unable to predict the ultimate cost of compliance. Generally, environmental requirements do not appear to affect us any differently or to any greater or lesser extent than other companies in the industry.

We believe that our operations comply, in all material respects, with all applicable environmental regulations.

Our insurance will not cover all the potential risks associated with the operations of a exploration stage oil and gas company. We may also be unable to obtain or maintain insurance to cover these risks at economically feasible premiums. Insurance coverage may not continue to be available or may not be adequate to cover any resulting liability. Moreover, we expect that insurance against risks such as environmental pollution or other hazards as a result of exploration and production may be prohibitively expensive to obtain for a company of our size and financial means. We might also become subject to liability for pollution or other hazards for which insurance may not be available or for which we may elect not to insure against because of premium costs or other reasons. Losses from these events may cause us to incur significant costs that could have a material adverse effect upon our financial condition and results of operations.

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The laws, regulations, policies or current administrative practices of any government body, organization or regulatory agency in the United States or any other jurisdiction, may be changed, applied or interpreted in a manner which will fundamentally alter our ability to carry on business. The actions, policies or regulations, or changes thereto, of any government body or regulatory agency, or other special interest groups, may have a detrimental effect on us. Any or all of these situations may have a negative impact on our ability to operate and/or our profitability.

Our extremely limited personnel means that we would be required to spend significant sums of money to locate and train new employees in the event any of our employees resign or terminate their employment with us for any reason. Due to our limited operating history and financial resources, we are entirely dependent on the continued service of Michael J. Newport, our Chief Executive Officer, and William D. Thomas, our Chief Financial Officer. Further, we do not have key man life insurance on either of these individuals. We may not have the financial resources to hire a replacement if one or both of our officers were to die. The loss of service of either of these employees could therefore significantly and adversely affect our operations.

Our officers and directors serve only part time and are subject to conflicts of interest. Each devotes part of his working time to other business endeavours, including consulting relationships with other entities, and has responsibilities to these other entities. Such conflicts include deciding how much time to devote to our affairs, as well as what business opportunities should be presented to us. Because of these relationships, our officers and directors will be subject to conflicts of interest. Currently, we have a policy in place to address such conflicts of interest.

Nevada law provides that our officers and directors will not be liable to us or our stockholders for monetary damages for all but certain types of conduct as officers and directors. Our Bylaws permit us broad indemnification powers to all persons against all damages incurred in connection with our business to the fullest extent provided or allowed by law. The exculpation provisions may have the effect of preventing stockholders from recovering damages against our officers and directors caused by their negligence, poor judgment or other circumstances. The indemnification provisions may require us to use our limited assets to defend our officers and directors against claims, including claims arising out of their negligence, poor judgment, or other circumstances.

The Company received a comment letter from the SEC, dated April 15, 2010, providing comments to the Company's Annual Report on Form 10-K/A (Amendment No. 1) for the Company's fiscal year ended February 28, 2009, as filed with the SEC on March 16, 2010. The Company is in the process of providing responses to such comments and anticipates that such comments will be resolved in the near future.

We lease our principal office space located at 21 Waterway Avenue, Suite 300, The Woodlands, Texas 77380., at a rental cost of approximately $4,200 monthly. The lease may be cancelled at any time with a thirty day notice.

The oil and gas properties in which we have an interest are described above under "Item 1. Business".

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Except as disclosed below, management is not aware of any legal proceedings contemplated by any governmental authority or any other party involving us or our properties. As of the date of this Annual Report, no director, officer or affiliate is (i) a party adverse to us in any legal proceeding, or (ii) has an adverse interest to us in any legal proceedings. Management is not aware of any other legal proceedings pending or that have been threatened against us or our properties.

During August 2009, we were included in a third party lawsuit filed by Abigail Investments LLC against David Urquhart, a former director of our Company, in the United States District Court for the State of Nevada, Case No. 09-CV-1174. The lawsuit includes a counter-claim by David Urquhart and his personal holding company, Westhampton, Ltd., (together "Urquhart") against the Company and others. The Company's management is of the view that Urquhart has made certain allegations against it including, but not limited to, neglect in the issuance of shares of common stock and granting of stock options. On April 15, 2010 the Company's litigation attorney together with other defendant's litigation attorneys made applications to dismiss the claims of Urquhart. In granting in part and denying in part the various motions to dismiss, Mahan J., held that among other things Urquhart's claims against non-resident defendants by counterclaim should be dismissed, since Urquhart had failed to plead facts sufficient to establish that the court had specific or general jurisdiction over them. The court granted Company's application to dismiss Urquhart's claims for fraud, conspiracy and aiding and abetting, for lack of sufficient particularity. The remainder of the Company's application to dismiss was itself dismissed, but without prejudice to the Company's right to reapply in the future, preferably after completion of discovery. Urquhart's application to amend his pleadings was withdrawn, but without prejudice to his application to reapply for leave to amend. Although we refute these allegations and believe that we should not be included in this action and that the claims contained within the complaint are without merit, it is possible that we may be exposed to a loss contingency. However, the amount of such loss, if any, cannot be reasonably estimated at this time and accordingly, no amount has been recorded to date.

A complaint was filed in the second judicial district court in Washoe County, Nevada by Avasha Group, Ltd. ("Avasha") on November 18, 2009 (such complaint as amended November 23, 2009) against the Company and certain other unnamed defendants. Avasha alleges that on or about April 21, 2008, Avasha entered into private placement subscription agreement with the Company to purchase 500,000 units from the Company (with each unit consisting of one share of the Company's common stock and one-half of one stock purchase warrant, together, the "Securities") for a total purchase price of $500,000. Avasha alleges that it paid such purchase price to the Company but the Securities were not delivered to Avasha. Avasha alleges that it is entitled to delivery of such Securities, as adjusted to take into account subsequent stock split(s) by the Company. The Company believes that this claim is without merit and intends to vigorously defend this matter.

Not applicable.

Shares of our common stock commenced trading on the OTC Bulletin Board under the symbol "MNLU:OB" on approximately May 24, 2006. The market for our common stock is limited, and can be volatile. The following table sets forth the high and low bid prices relating to our common stock on a quarterly basis for the periods indicated as quoted by the NASDAQ stock market, adjusted to give retroactive effect to stock splits. These quotations reflect inter-dealer prices without retail mark-up, mark-down, or commissions, and may not reflect actual transactions.

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As of May 28, 2010, we had 27 shareholders of record, which does not include shareholders whose shares are held in street or nominee names.

No dividends have ever been declared by the Board of Directors on our common stock. Our losses do not currently indicate the ability to pay any cash dividends, and we do not indicate the intention of paying cash dividends either on our common stock in the foreseeable future.

On February 25, 2008, our Board of Directors, pursuant to minutes of written consent in lieu of a special meeting, authorized and approved a twenty for one (20:1) forward stock split. This forward split was effectuated on March 11, 2008 upon filing the appropriate documentation with NASDAQ. This forward split increased the issued and outstanding shares of common stock from 1,120,500 to 22,410,000 shares of common stock. Pursuant to Nevada corporate law, at the time of the forward split of our issued and outstanding stock, our authorized share capital was also increased on a 20:1 basis from 10,000,000 shares of common stock to 200,000,000 shares of common stock, with a par value remaining unchanged at $0.0001 per share.

On May 12, 2008, our Board of Directors, pursuant to minutes of written consent in lieu of a special meeting, authorized and approved a one-and-one-half for one (1.5:1) forward stock split. This forward split was effectuated on May 29, 2008 upon filing the appropriate documentation with NASDAQ. This forward split increased our issued and outstanding shares of common stock from 26,410,000 to 39,615,000 shares of common stock. At the time the Company effected this forward split, due to an administrative oversight, a Certificate of Change to effect a simultaneous 1.5:1 increase of the Company's authorized common stock was not filed with the Nevada Secretary of State. The Company has rectified this administrative oversight by filing a Certificate of Change with the Nevada Secretary of State to effect, as of May 26, 2010, the 1.5:1 increase of the Company's authorized common stock.

On June 12, 2009, our Board of Directors, pursuant to minutes of written consent in lieu of a special meeting, authorized and approved a two for one (2:1) forward stock split. This forward split was effectuated on July 13, 2009 upon filing the appropriate documentation with NASDAQ. This forward split increased the issued and outstanding shares of common stock from 40,484,751 to 80,969,502 shares of common stock. Pursuant to Nevada corporate law, at the time of the forward split of our issued and outstanding stock, our authorized share capital was also increased on a 2:1 basis.

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As a result of these forward splits and increases of our authorized share capital, as of the date of this Annual Report, our authorized share capital it 600,000,000 shares of common stock, with a par value of $0.0001 per share.

We have one equity compensation plan, the Mainland Resources Inc. 2008 Stock Option Plan (the "2008 Plan"). The table set forth below presents information relating to our equity compensation plans as of February 28, 2010:

The purpose of the 2008 Plan is to enhance our long-term stockholder value by offering opportunities to our directors, officers, employees and eligible consultants to acquire and maintain stock ownership in order to give these persons the opportunity to participate in our growth and success, and to encourage them to remain in our service.

The 2008 Plan is to be administered by our Board of Directors or a committee appointed by and consisting of one or more members of the Board of Directors, which shall determine (i) the persons to be granted Stock Options under the 2008 Plan; (ii) the number of shares subject to each option, the exercise price of each Stock Option; and (iii) whether the Stock Option shall be exercisable at any time during the option period up to ten (10) years or whether the Stock Option shall be exercisable in instalments or by vesting only. At the time a Stock Option is granted under the 2008 Plan, the Board of Directors shall fix and determine the exercise price at which shares of our common stock may be acquired.

In the event an optionee ceases to be employed by or to provide services to us for reasons other than cause, retirement, disability or death, any Stock Option that is vested and held by such optionee generally may be exercisable within up to ninety (90) calendar days after the effective date that his position ceases, and after such 90-day period any unexercised Stock Option shall expire. In the event an optionee ceases to be employed by or to provide services to us for reasons of retirement, disability or death, any Stock Option that is vested and held by such optionee generally may be exercisable within up to one-year after the effective date that his position ceases, and after such one-year period any unexercised Stock Option shall expire.

No Stock Options granted under the Stock Option Plan will be transferable by the optionee, and each Stock Option will be exercisable during the lifetime of the optionee subject to the option period up to ten (10) years or limitations described above. Any Stock Option held by an optionee at the time of his death may be exercised by his estate within one (1) year of his death or such longer period as the Board of Directors may determine.

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The exercise price of a Stock Option granted pursuant to the 2008 Plan shall be paid in full to us by delivery of consideration equal to the product of the Stock Option in accordance with the requirements of the Nevada Revised Statutes. Any Stock Option settlement, including payment deferrals or payments deemed made by way of settlement of pre-existing indebtedness may be subject to such conditions, restrictions and contingencies as may be determined.

The 2008 Plan further provides that, subject to the provisions of the Stock Option Plan and prior shareholder approval, the Board of Directors may grant to any key individuals who are our employees eligible to receive options, one or more incentive stock options to purchase the number of shares of common stock allotted by the Board of Directors (the "Incentive Stock Options"). The option price per share of common stock deliverable upon the exercise of an Incentive Stock Option shall be at least 100% of the fair market value of the common shares of the Company, and in the case of an Incentive Stock Option granted to an optionee who owns more than 10% of the total combined voting power of all classes of our stock, shall not be less than 100% of the fair market value of our common shares. The option term of each Incentive Stock Option shall be determined by the Board of Directors, which shall not commence sooner than from the date of grant and shall terminate no later than ten (10) years from the date of grant of the Incentive Stock Option, subject to possible early termination as described above.

As of the date of this Annual Report, no Stock Options have been exercised.

Our shares of common stock were first quoted on the OTC Bulletin Board on May 24, 2006; however, no trades occurred until March 12, 2008. The graph below compares the cumulative total stockholder return on our common stock for the period from March 12, 2008 to February 28, 2009 and for the year ended February 28, 2010, with the cumulative total return of the S&P 500 and the cumulative total return of the S&P Small Cap 600 over the same periods (assuming an investment of $100 in our common stock, the S&P 500 and the S&P Small Cap 600 on March 12, 2008, and the reinvestment of all dividends, if any). The cumulative returns of the S&P 500 and the S&P Small Cap 600 from March 12, 2008 through February 28, 2010 were closely aligned, which is why the lines tracking the their performance in the chart below are closely correlated.

As of the date of this Annual Report and during fiscal year ended February 28, 2010, to provide capital, we issued stock in exchange for our debts or pursuant to contractual agreements as set forth below.

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Effective on March 17, 2009, we issued 5,000 shares of our restricted common stock at a deemed per share price of $1.78 per share in accordance with the terms and provisions of a consulting services agreement. The shares of common stock were issued in reliance on Regulation S promulgated under the Securities Act.

Effective on June 15, 2009, we issued 5,000 shares of our restricted common stock at a deemed per share price of $1.45 per share in accordance with the terms and provisions of a consulting services agreement. The shares of common stock were issued in reliance on Regulation S promulgated under the Securities Act.

During our fiscal year ended February 28, 2010, we issued an aggregate of 1,729,500 shares upon exercise of warrants at an exercise price of $0.67 per share with net proceeds to us of $1,153,000. The shares of common stock were issued in reliance on Rule 506 and Regulation S promulgated under the Securities Act. These warrants were originally issued by us between May 1, 2008 and July 22, 2008 pursuant to a private placement of units.

The following selected financial information is qualified by reference to, and should be read in conjunction with our financial statements and the notes thereto, and "Management's Discussion and Analysis of Financial Condition and Results of Operation" contained elsewhere herein. The selected income statement data for fiscal years ended February 28, 2010, February 28, 2009 and February 29, 2008 and the selected balance sheet data as of February 28, 2010 and February 28, 2009 are derived from our audited financial statements which are included elsewhere herein.

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The following discussion should be read in conjunction with our audited financial statements and the related notes that appear elsewhere in this Annual Report. The following discussion contains forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in the forward looking statements. Factors that could cause or contribute to such differences include, but are not limited to those discussed below and elsewhere in this Annual Report, particularly in the section entitled "Risk Factors". Our audited financial statements are stated in United States Dollars and are prepared in accordance with United States Generally Accepted Accounting Principles.

We are an exploration stage company and have generated limited revenue to date. The table set forth in Item 6 above presents selected financial information for the periods indicated. We have incurred recurring losses to date. Our financial statements have been prepared assuming that we will continue as a going concern and, accordingly, do not include adjustments relating to the recoverability and realization of assets and classification of liabilities that might be necessary should we be unable to continue in operation.

We expect we will require additional capital to meet our long term operating requirements. We expect to raise additional capital through, among other things, the sale of equity or debt securities.

We did not generate any revenue during our fiscal year ended February 28, 2010 or our fiscal year ended February 28, 2009.

During our fiscal year ended February 28, 2010, we incurred general and administrative expenses of $2,883,482 compared to $13,972,074 incurred during our fiscal year ended February 28, 2009. These general and administrative expenses included the following:

• consulting fees of $311,334 during our fiscal year ended February 28, 2010 (2009 - $595,374), which decreased in 2010 due to higher services required in 2009 during preparation for our drilling program;
• management and rent fees of $250,164 during our fiscal year ended February 28, 2010 (2009 - $126,400), which increased in 2010 due to our expanded program in Mississippi;
• marketing expenses of $560,025 during our fiscal year ended February 28, 2010 (2009 - $921,107), which decreased in 2010 due to our greater emphasis on asset divestiture and building acreage position in Mississippi;
• office and general expenses of $123,101 during our fiscal year ended February 28, 2010 (2009 - $82,798), which increased in 2010 due to our expanded program in Mississippi;
• professional fees of $490,858 during our fiscal year ended February 28, 2010 (2009 - $243,710), which increased in 2010 due to our expanded program in Mississippi, asset divestiture, setting up mezzanine financing program and the proposed merger with American Exploration;
• salary expenses of $1,148,000 during our fiscal year ended February 28, 2010 (2009 - $12,002,685), which decreased in 2010 due to lower stock option grants in 2010 versus 2009.

Our general and administrative expenses incurred during our fiscal year ended February 28, 2010 compared to our fiscal year ended February 28, 2009 decreased primarily due to a decrease in salary expenses from $12,002,685 in 2009 to $1,148,000 in 2010. Our salary expenses were considerably higher in 2009 due to the valuation of stock based compensation consisting of the grant of 4,000,000 stock options during 2009, based on an expected volatility of 260%. We arrived at the 260% volatility by a comparison of other small oil and gas reporting companies regarding valuation of stock options since we have a lack of liquidity and trading history for our shares of common stock. We thus determined that the 260% volatility was appropriate for calculation of the employee stock option compensation using the Black-Sholes method.

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As a result, our net operating loss during our fiscal year ended February 28, 2010 was $2,883,482 compared to a net operating loss of $13,972,074 during our fiscal year ended February 28, 2009.

During our fiscal year ended February 28, 2010, we recorded other income in the amount of $1,070, consisting of interest income (2009 - $40,638, consisting of $7,399 in interest income and a $33,239 gain on the settlement of debt). During our fiscal year ended February 28, 2010, we recorded a $1,300,000 loss on the abandonment of an option deposit (2009 - $Nil). In addition, during our fiscal year ended February 28, 2010, we recorded a $34,575 loss from discontinued operations (2009 - $355,256 income from discontinued operations). As a result, our net loss for our fiscal year ended February 28, 2010 was $4,216,987 (2009 - $13,576,180). We had no foreign currency translation adjustment in 2010 (2009 - $422), as result of which our comprehensive loss for fiscal year ended February 28, 2010 was $4,216,987, compared to a comprehensive loss of $13,575,758 during fiscal year ended February 28, 2009.

Our comprehensive loss for fiscal year ended February 28, 2009 was ($13,575,758) compared to a comprehensive loss of ($145,140) during fiscal year ended February 29, 2008 (an increase of $13,430,618). During fiscal year ended February 28, 2009, we generated $516,579 in oil and gas revenue compared to $-0- generated during fiscal year ended February 29, 2008.

During fiscal year ended February 28, 2009, we incurred general and administrative expenses of $14,133,397 compared to $144,523 incurred during fiscal year ended February 29, 2008 (an increase of $13,988,874). These general and administrative expenses incurred during fiscal year ended February 28, 2009 consisted of: (i) operating costs and taxes of $149,323 (2008: $-0-); (ii) depletion allowance of $12,000 (2008: $-0-); (iii) consulting fees of $595,374 (2008: $-0-); (iv) management and rent fees-related party of $126,400 (2008: $8,627); (v) marketing expenses of $921,107 (2008: $-0-); (vi) mineral property costs of $-0- (2008: $10,070); (vii) office and general of $82,798 (2008: $58,657); (viii) professional fees of $243,710 (2008: $67,169); and (ix) salary expense of $12,002,685 (2008: $-0-).

Of the $14,133,397 incurred as general and administrative expenses during fiscal year ended February 28, 2009, we incurred management fees of $126,400 payable to our officers and directors. See "Item 11. Executive Compensation".

General and administrative expenses incurred during fiscal year ended February 28, 2009 compared to fiscal year ended February 29, 2008 increased primarily due to the increase in salary expense of $12,002,685 relating to the valuation of stock based compensation consisting of the grant of 4,000,000 additional stock options during the period, and the increase in consulting fees of $595,374, marketing expenses of $921,107 and professional fees of $243,710 relating to the increased scale and scope of our business operations. The valuation $12,002,685 relating to the stock options was based on an expected volatility of 260%. We arrived at the 260% volatility by a comparison of other small oil and gas reporting companies regarding valuation of stock options since we have a lack of liquidity and trading history for our shares of common stock. We thus determined that the 260% volatility was appropriate for calculation of the employee stock option compensation using the Black-Sholes method. General and administrative expenses also generally include corporate overhead, financial and administrative contracted services, marketing, and consulting costs.

Our net operating loss during fiscal year ended February 28, 2009 was ($13,616,818) compared to a net operating loss of ($144,523) during fiscal year ended February 29, 2008 (an increase of $13,472,295).

During fiscal year ended February 28, 2009, we recorded other income in the amount of $33,239 (2008: $-0-) in gain on settlement of debt and $7,399 (2008: $-0-) in interest income. This resulted in a net loss of ($13,576,180) for fiscal year ended February 28, 2009 compared to a net loss of ($144,523) for fiscal year ended February 29, 2008.

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Our net loss of (13,576,180) for fiscal year ended February 28, 2009 was offset for foreign currency translation adjustment of $422 (2008: ($617). This resulted in a comprehensive loss of ($13,575,758) for fiscal year ended February 28, 2009 as compared to a comprehensive loss of ($145,140) for fiscal year ended February 29, 2008. The weighted average number of shares outstanding was 38,527,911 for fiscal year ended February 28, 2009 (as increased in accordance with the February 2008 Forward Stock Split and the May 2008 Forward Stock Split) compared to 26,106,803 for fiscal year ended February 29, 2008.

As at February 28, 2010, our current assets were $642,042 (2009 - $1,623,321) and our current liabilities were $711,044 (2009 - $70,230), which resulted in a working capital deficit of $69,002 (2009 - working capital surplus of $1,553,091). As at February 28, 2010, our current assets were comprised of $610,124 in cash and $31,918 in prepaid expenses. As at February 28, 2010, current liabilities were comprised of accounts payable and accrued liabilities.

As at February 28, 2010, our total assets were $12,348,940 (2009 - $2,398,332), comprised of: (i) current assets in the amount of $642,042 (2009 - $1,623,321), (ii) oil and gas properties, net of accumulated depletion, in the amount of $3,534,436 (2009 - $775,011), and (iii) $8,172,462 in assets held for sale (2009 - $Nil).

As at February 28, 2010, we had $711,044 in current liabilities (2009 - $70,230) and $11,209,656 in liabilities held for sale (2009 - $Nil).

Stockholders' equity decreased from $2,398,102 as at February 28, 2009 to $428,240 as at February 28, 2010.

As at fiscal year ended February 28, 2009, our current assets were $1,623,321 and our current liabilities were $70,230, which resulted in a working capital surplus of $1,553,091. As at fiscal year ended February 28, 2009, current assets were comprised of: (i) $150,276 in cash; (ii) $373,045 in accounts receivable; and (iii) $1,100,000 in deposit on properties. As at fiscal year ended February 28, 2009, current liabilities were comprised of $70,230 in accounts payable and accrued liabilities.

As at fiscal year ended February 28, 2009, our total assets were $2,398,332, comprised of current assets in the amount of $1,623,321 and valuation of proved oil and gas properties, net of accumulated depletion of $775,011. The increase in total assets during fiscal year ended February 28, 2009 from fiscal year ended February 29, 2008 was primarily due to the substantial increase in current assets, including the $1,100,000 deposit, and the valuation of the proved oil and gas properties of $775,011.

As at fiscal year ended February 28, 2009, our total liabilities were $70,230 comprised entirely of current liabilities. The decrease in liabilities during fiscal year ended February 28, 2008 from fiscal year ended February 29, 2008 was primarily due to the decrease in accounts payable and accrued liabilities and related party advance by way of settlement of debt by issuance of shares of our common stock in the 2008 Private Placement Offering.

Stockholders' equity (deficit) increased from ($98,825) for fiscal year ended February 29, 2008 to $2,328,102 for fiscal year ended February 28, 2009.

For our fiscal year ended February 28, 2010, net cash from operating activities was $2,919,284. Our net loss from continuing operations was ($4,182,412). Net cash flows used in operating activities was adjusted by $1,300,000 in non-cash mineral property losses, $1,148,000 in stock-based compensation and $16,125 in non-cash consulting fees. Net cash flows related to operating activities was further changed by ($31,918) in changes to prepaid expenses and $640,814 in changes to accounts payable and accrued liabilities. As a result, net cash used in continuing operations was ($1,109,391), which was offset by cash from discontinued operations of $4,028,675.

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For our fiscal year ended February 28, 2009, net cash used in operating activities was ($2,649,341). Our net loss from continuing operations was ($13,931,436). Net cash flows used in operating activities was adjusted by ($33,239) in non-cash mineral property recoveries and $12,002,685 in stock-based compensation. Net cash flows related to operating activities was further changed by ($6,138) in changed to related party accounts payable and $32,111 in changes to accounts payable and accrued liabilities. As a result, net cash used in continuing operations was ($1,936,017), which was further adjusted by ($713,324) in net cash used in discontinued operations.

For fiscal year ended February 28, 2009, net cash flows used in operating activities was ($1,941,806) consisting primarily of a net loss of ($13,576,180). Net cash flows used in operating activities was adjusted by $12,002,685 in stock based compensation, $12,000 in depletion and ($33,239) in non-cash mineral property expenditures (recoveries). Net cash flows used in operating activities was further changed by $32,111 in accounts payable and accrued liabilities, ($373,045) in accounts receivable, and ($6,138) in accounts payable - related parties.

For our fiscal year ended February 28, 2010, net cash flows used in investing activities was ($3,612,436), consisting of investment in oil and gas property of ($3,412,436) and deposit on properties of ($200,000).

For our fiscal year ended February 28, 2009, net cash flows used in investing activities was ($1,170,300), consisting of investment in oil and gas property of ($70,300) and deposit on properties of ($1,100,000).

For fiscal year ended February 28, 2009, net cash flows used in investing activities was ($1,877,835) consisting of investment in oil and gas property, compared to net cash flows used in investing activities during fiscal year ended February 29, 2008 of ($9,176) consisting of investment in oil and gas property.

We have financed our operations primarily from either advancements or the issuance of equity and debt instruments.

For our fiscal year ended February 28, 2010, net cash provided by financing activities was $1,153,000 compared to $3,950,000 for our fiscal year ended February 28, 2009. Cash flows provided by financing activities in 2010 consisted of proceeds from the exercise of warrants, while cash flows provided by financing activities in 2009 consisted of proceeds on the sale of common stock.

For fiscal year ended February 28, 2009, net cash flows provided from financing activities was $3,950,000 compared to $103,691 for fiscal year ended February 29, 2008. Cash flows from financing activities for fiscal year ended February 28, 2009 consisted primarily of $3,950,000 in proceeds on sale of common stock. Cash flows from financing activities for fiscal year ended February 29, 2008 consisted of $20,452 in proceeds on sale of common stock and $83,239 in advances from related parties.

We expect that working capital requirements will continue to be funded through a combination of our existing funds and further issuances of securities. Our working capital requirements are expected to increase in line with the growth of our business.

As indicated above, as of February 28, 2010, we had current assets of $642,042 and current liabilities of $711,044, resulting in a working capital deficit of $69,002. Subsequent to our February 28, 2010 year end, we sold our remaining 40% interest in the Haynesville Shale portion of the East Holly Field leases for $28,159,604 on April 22, 2010, with an effective date of January 1, 2010. We intend to apply the net proceeds to: (a) provide initial funding for the drilling of up to three wells in the Hosston/Cotton Valley formations of the East Holly Prospect in 2010; (b) fund the drilling of the Burkley-Phillips No. 1 well on the Buena Vista prospect in Mississippi; and (c) to retire our debt to Guggenheim. Additional funding will be required to complete our 2010-2011 operations program and to complete the merger with American Exploration. We anticipate that we will receive this funding from a variety of methods, including private placements, equity funding, entering into joint venture transactions with third parties, mezzanine financing and cash flows from successful wells.

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We have no lines of credit or other bank financing arrangements. Generally, we have financed operations to date through the proceeds of the private placement of equity and debt instruments. In connection with our business plan, management anticipates additional increases in operating expenses and capital expenditures relating to: (i) oil and gas operating properties; (ii) possible drilling initiatives on current properties and future properties; and (iii) future property acquisitions. We intend to finance these expenses with further issuances of securities, and debt issuances. Thereafter, we expect we will need to raise additional capital and generate revenues to meet long-term operating requirements. Additional issuances of equity or convertible debt securities will result in dilution to our current shareholders. Further, such securities might have rights, preferences or privileges senior to our common stock. Additional financing may not be available upon acceptable terms, or at all. If adequate funds are not available or are not available on acceptable terms, we may not be able to take advantage of prospective new business endeavours or opportunities, which could significantly and materially restrict our business operations.

As of February 28, 2010, Guggenheim held a promissory note totalling $10,277,485 payable by us. As a result of our sale of our remaining 40% interest in the Haynesville Shale portion of the East Holly Field leases for $28,159,604 on April 22, 2010, we retired this debt to Guggenheim.

As described above under Item 1 of this Annual Report, our Company has entered into a joint area development agreement with American Exploration to jointly develop contiguous acreage comprising the Buena Vista Prospect. As operator on the Buena Vista Prospect, we recently issued an Authority for Expenditure (AFE) for the Burkley-Phillips No. 1 Well to be drilled on the Prospect. We intend to drill the well to a depth sufficient to evaluate the Haynesville Shale formation, currently expected to total 22,000 feet. The AFE estimates the drilling cost to be approximately $8,650,000 and completion cost to be approximately $4,900,000 for a total completed well cost of approximately US$13,550,000. Drilling is expected to commence in the latter part of the second quarter of 2010.

American Exploration was unable to fund its 20% share of the estimated total well costs of the Burkley-Phillips No. 1 Well. As a result, American Exploration has forfeited its right to a 29% working interest in the well and in the Buena Vista Prospect in favor of our Company. American Exploration will continue to be entitled to receive a 20% working interest in the well and the Prospect after completion (subject to compliance by American Exploration with all other terms and conditions of our letter agreement and related joint operating agreement with American Exploration).

We were previously required to pay 72% of the total cost to drill and complete the Burkley-Phillips No. 1 Well, for a 45.9% working interest. Due to American Exploration's inability to make its contribution in response to the cash call, we will now pay 90% of the total cost of the well to earn a 72% interest, and Guggenheim Energy Opportunities, LLC ("Guggenheim") will pay 10% of the total cost to earn an 8% interest.

Other than our debt outstanding to Guggenheim as of February 28, 2010 (subsequently retired) and our obligations under our joint operating agreement with American Exploration as described immediately above and under Item 1, we did not have any material commitments for capital expenditures as of February 28, 2010.

The following table provides information regarding our known contractual oblations as of February 28, 2010:

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The independent auditors' report accompanying our February 28, 2010, February 28, 2009 and February 29, 2008 financial statements contains an explanatory paragraph expressing substantial doubt about our ability to continue as a going concern. The financial statements have been prepared "assuming that we will continue as a going concern," which contemplates that we will realize our assets and satisfy our liabilities and commitments in the ordinary course of business.

In June 2009, the FASB issued FASB ASC 860-10, "Transfers and Servicing", FASB ASC 860-10 eliminates the concept of a "qualifying special-purpose entity," changes the requirements for derecognizing financial assets, and requires additional disclosures in order to enhance information reported to users of financial statements by providing greater transparency about transfers of financial assets, including securitization transactions, and an entity's continuing involvement in and exposure to the risks related to transferred financial assets. FASB ASC 860-10 is effective for fiscal years beginning after November 15, 2009. The Company will adopt FASB ASC 860-10 in fiscal 2010. The Company does not expect that the adoption of FASB ASC 860-10 will have a material impact on its financial position, cash flows or results of operations.

In June 2009, the FASB issued FASB ASC 810-10, "Consolidation", which included the following: (1) the elimination of the exemption for qualifying special purpose entities, (2) a new approach for determining who should consolidate a variable-interest entity, and (3) changes to when it is necessary to reassess who should consolidate a variable-interest entity. FASB ASC 810-10 is effective for the first annual reporting period beginning after November 15, 2009 and for interim periods within that first annual reporting period. The Company will adopt FASB ASC 810-10 in fiscal 2010. The Company does not expect that the adoption of FASB ASC 810-10 will have a material impact on its financial position, cash flows or results of operations.

In June 2009, the FASB issued FASB ASC 105-10, "Generally Accepted Accounting Principles replaces SFAS No. 162, which establishes the FASB Accounting Standards Codification ("Codification") as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. Rules and interpretive releases of the Securities and Exchange Commission ("SEC") under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The FASB will no longer issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts; instead the FASB will issue Accounting Standards Updates. Accounting Standards Updates will not be authoritative in their own right as they will only serve to update the Codification. The issuance of FASB ASC 105-10 and the Codification does not change GAAP. FASB ASC 105-10 becomes effective for interim and annual periods ending after September 15, 2009. The adoption of this statement did not have a material impact on the Company's financial position, cash flows and results of operations.

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In August 2009, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2009-05, "Fair Value Measurements and Disclosures (Topic 820): Measuring Liabilities at Fair Value". The guidance provided in this update is effective for the first reporting period beginning after issuance. The adoption of this statement has had no material effect on the Company's financial position, cash flows or results of operations.

In September 2009, the Financial Accounting Standards Board (FASB) issued ASU 2009-12, "Fair Value Measurements and Disclosures" (Topic 820): Investments in Certain Entities That Calculate Net Asset Value Per Share (or Its Equivalent). This update provides amendments to subtopic 820-10, Fair Value Measurements and Disclosures - Overall, for the fair value measurement of investments in certain entities that calculate net asset value per share (or its equivalent). The amendments in this update are effective for interim and annual periods ending after December 15, 2009. Early application is permitted in financial statements for earlier interim and annual periods that have not been issued. The adoption of this statement did not have a material impact on the Company's financial position, cash flows and results of operations.

In January 2010, the FASB issued Accounting Standards Update (ASU) 2010-01, "Equity (Topic 505-10): Accounting for Distributions to Shareholders with Components of Stock and Cash (A Consensus of the FASB Emerging Issues Task Force)". This amendment to Topic 505 clarifies the stock portion of a distribution to shareholders that allows them to elect to receive cash or stock with a limit on the amount of cash that will be distributed is not a stock dividend for purposes of applying Topics 505 and 260. This standard is effective for interim and annual periods ending on or after December 15, 2009, and would be applied on a retrospective basis. The adoption of this statement did not have a material impact on the Company's financial position, cash flows and results of operations.

In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2010-02, "Consolidation (Topic 810): Accounting and Reporting for Decreases in Ownership of a Subsidiary". This amendment to Topic 810 clarifies, but does not change, the scope of current US GAAP. It clarifies the decrease in ownership provisions of Subtopic 810-10 and removes the potential conflict between guidance in that Subtopic and asset derecognition and gain or loss recognition guidance that may exist in other US GAAP. An entity will be required to follow the amended guidance beginning in the period that it first adopts FAS 160 (now included in Subtopic 810-10). For those entities that have already adopted FAS 160, the amendments are effective at the beginning of the first interim or annual reporting period ending on or after December 15, 2009. The amendments should be applied retrospectively to the first period that an entity adopted FAS 160. The Company does not expect the provisions of ASU 2010-02 to have a material effect on the financial position, results of operations or cash flows of the Company.

In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2010-6, "Improving Disclosures about Fair Value Measurements." This update requires additional disclosure within the roll forward of activity for assets and liabilities measured at fair value on a recurring basis, including transfers of assets and liabilities between Level 1 and Level 2 of the fair value hierarchy and the separate presentation of purchases, sales, issuances and settlements of assets and liabilities within Level 3 of the fair value hierarchy. In addition, the update requires enhanced disclosures of the valuation techniques and inputs used in the fair value measurements within Levels 2 and 3. The new disclosure requirements are effective for interim and annual periods beginning after December 15, 2009, except for the disclosure of purchases, sales, issuances and settlements of Level 3 measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010. As ASU 2010-6 only requires enhanced disclosures, the Company does not expect that the adoption of this update will have a material effect on its financial position, cash flows and results of operations.

We are subject to risks related to foreign currency exchange rate fluctuations. However, they have not had a material impact on our results of operations to date.

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Our functional currency is the United States dollar. However, a portion of our business is transacted in other currencies (the Canadian dollar). As a result, we are subject to exposure from movements in foreign currency exchange rates. We do not use derivative financial instruments for speculative trading purposes, nor do we hedge our foreign currency exposure to manage our foreign currency fluctuation risk.

Reports of Independent Registered Public Accounting Firm dated May 27, 2010 and May 12, 2009.

Report of Independent Registered Public Accounting Firm (ICOFR) dated May 27, 2010.

Balance Sheets as at February 28, 2010 and February 28, 2009

Statements of Operations for Fiscal Years Ended February 28, 2010, February 28, 2009 and February 29, 2008 and from Inception (May 12, 2006) to February 28, 2010.

Statement of Stockholders' Equity for the Period from Inception (May 12, 2006) to February 28, 2010.

Statements of Cash Flows for the Fiscal Years Ended February 28, 2010, February 28, 2009 and February 29, 2008 and from Inception (May 12, 2006) to February 28, 2010.

Notes to Financial Statements.

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To The Board of Directors and Stockholders
Mainland Resources, Inc.
Las Vegas, Nevada

We have audited the accompanying balance sheets of Mainland Resources, Inc. (An Exploration Stage Company) as of February 28, 2010 and 2009, and the related statements of operations, stockholders' equity, and cash flows for the years then ended and from inception (May 12, 2006) to February 28, 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audit.

We conducted our audit in accordance with 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 audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Mainland Resources, Inc. as of February 28, 2010 and 2009, and the results of its operations and cash flows for the years then ended and from inception (May 12, 2006) to February 28, 2010, in conformity with accounting principles generally accepted in the United States.

The accompanying financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has suffered recurring losses from operations, which raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Mainland Resources, Inc.'s internal control over financial reporting as of February 28, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated May 27, 2010 expressed an unqualified opinion thereon.

De Joya Griffith & Company, LLC

/s/ De Joya Griffith & Company, LLC
Henderson, NV
May 27, 2010

2580 Anthem Village Drive, Henderson, NV 89052
Telephone (702) 563-1600 Ÿ Facsimile (702) 920-8049

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We have audited the accompanying balance sheets of Mainland Resources, Inc. (An Exploration Stage Company) as of February 28, 2009 and 2008, and the related statements of operations, stockholders' deficit, and cash flows for the years then ended and from inception (May 12, 2006) to February 28, 2009. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audit.

We conducted our audit in accordance with 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 audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Mainland Resources, Inc. as of February 28, 2009 and 2008, and the results of its operations and cash flows for the years then ended and from inception (May 12, 2006) to February 28, 2009, in conformity with accounting principles generally accepted in the United States.

The accompanying financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has suffered recurring losses from operations, which raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Mainland Resources, Inc.'s internal control over financial reporting as of February 28, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated May 12, 2009 expressed an unqualified opinion thereon.

/s/ De Joya Griffith & Company, LLC
Henderson, NV
May 12, 2009

2580 Anthem Village Drive, Henderson, NV 89052 Telephone (702) 563-1600 / Facsimile (702) 920-8049

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To The Board of Directors and Stockholders
Mainland Resources, Inc.
Las Vegas, Nevada

We have audited Mainland Resources, Inc.'s internal control over financial reporting as of February 28, 2010, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Mainland Resources, Inc.'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 which is contained in Part I, Item 9A of this Annual Report on Form 10-K under the heading "Management's Report on Internal Control Over Financial Reporting". 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 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. An audit includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and 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, Mainland Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of February 28, 2010, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets as of February 28, 2010 and 2009, and the related statements of operations, stockholders' equity, and cash flows for the years then ended and from inception (May 12, 2006) to February 28, 2010, of Mainland Resources, Inc. and our report dated May 27, 2010 expressed an unqualified opinion thereon.

De Joya Griffith & Company, LLC

/s/ De Joya Griffith & Company, LLC
Henderson, NV
May 27, 2010

2580 Anthem Village Drive, Henderson, NV 89052
Telephone (702) 563-1600 Ÿ Facsimile (702) 920-8049

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MAINLAND RESOURCES INC.
(An Exploration Stage Company)
BALANCE SHEETS
(Audited)

The accompanying notes are an integral part of these financial statements.

- 50 -

MAINLAND RESOURCES INC.
(An Exploration Stage Company)

STATEMENTS OF OPERATIONS

The accompanying notes are an integral part of these financial statements.

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The accompanying notes are an integral part of these financial statements.

- 52 -

- 53 -

The accompanying notes are an integral part of these financial statements.

- 54 -

MAINLAND RESOURCES INC.
(An Exploration Stage Company)

NOTES TO FINANCIAL STATEMENTS
FEBRUARY 28, 2010, February 28, 2009 and February 29, 2008
(Audited)

Mainland Resources Inc. (the "Company") is an exploration stage as defined in FASB ASC 915 "Development Stage Entities". The Company was incorporated May 12, 2006 in the State of Nevada for the purpose of mineral exploration. During 2008, the Company entered into an option agreement on certain oil and gas leaseholds in the state of Louisiana (refer to Note 3). The Company now intends to locate, explore, acquire and develop oil and gas properties in the United States. The Company began drilling its first well in October 2008 which was completed at the end of January 2009 and commenced production from the Haynesville Shale formation. Through April 2010, the Company had five wells at various stages of drilling, completion and production in the Haynesville Shale formation. Subsequent to the period on April 22, 2010 the Company sold all its Haynesville Shale assets in East Holly Field, DeSoto Parish, Louisiana including the five producing wells (refer to Note 9).

Subsequent to the year end on March 22, 2010, the Company and American Exploration Corporation ("AEC") entered into a definitive Merger Agreement and Plan of Merger (the "Merger Agreement") that contemplates a stock-for-stock merger to be effected under the laws of Nevada. Under the terms of the Merger Agreement, the AEC stockholders will receive one share of the Company for every four shares of AEC common stock they own. Currently, there are approximately 59,718,000 shares of AEC common stock outstanding, which would result in the issuance of approximately 14,929,500 shares of the Company's common stock to the former stockholders of AEC which would represent approximately 15.6% of the issued and outstanding common stock of the Company, as the surviving corporation. The merger is be subject to various conditions, including approval of the respective stockholders of each of the Company and AEC and completion of due diligence. The due diligence by both parties was completed on May 5, 2010. The proposed merger is still subject to respective stockholders approval (refer to Note 4).

The Company commenced operations on May 12, 2006. Although the Company has realized revenues, as of February 28, 2010, the Company has an accumulated deficit during the exploration stage of $17,948,946. The ability of the Company to continue as a going concern is dependent on raising capital to fund ongoing operations and carry out its business plan and ultimately to attain profitable operations. Accordingly, these factors raise substantial doubt as to the Company's ability to continue as a going concern. These financials do not include any adjustments relating to the recoverability and classification of recorded asset amounts or amounts and classification of liabilities that might result from this uncertainty. To date, the Company has funded its initial operations by way of private placements of common stock, advances from related parties and bridge loan financing. During fiscal 2009, the Company completed a private placement of $4,000,000 at $0.33 per unit with each unit consisting of one common share and one half warrant at $0.67 per share exercisable for a period of one year from issuance (refer to Note 6). In addition, during the year ended February 28, 2010, 1,729,500 warrants were exercised at $0.67 for net proceeds to the company of $1,153,000. On August 10, 2009, the Company closed a $3,500,000 bridge loan financing which was replaced effective October 16, 2009 with a secured senior line of credit for $40,000,000 of which $10,278,485 had been advanced as of February 28, 2010. Subsequent to the year end, the entire outstanding balance owed on the secured line of credit was repaid from the sale of assets (refer to Note 3 and 5).

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MAINLAND RESOURCES INC.
(An Exploration Stage Company)

NOTES TO FINANCIAL STATEMENTS
FEBRUARY 28, 2010, February 28, 2009 and February 29, 2008
(Audited)

These financial statements are presented in United States dollars and have been prepared in accordance with United States generally accepted accounting principles.

The Company follows the full cost method of accounting for its oil and gas operations whereby all costs related to the acquisition of methane, petroleum, and natural gas interests are capitalized. Under this method, all productive and non-productive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such costs include land and lease acquisition costs, annual carrying charges of non-producing properties, geological and geophysical costs, costs of drilling and equipping productive and non-productive wells, and direct exploration salaries and related benefits. Proceeds from the disposal of oil and gas properties are recorded as a reduction of the related capitalized costs without recognition of a gain or loss unless the disposal would result in a change of 20 percent or more in the depletion rate. The Company currently operates solely in the U.S.

Depreciation and depletion of proved oil and gas properties is computed on the units-of-production method based upon estimates of proved reserves, as determined by independent consultants, with oil and gas being converted to a common unit of measure based on their relative energy content.

The costs of acquisition and exploration of unproved oil and gas properties, including any related capitalized interest expense, are not subject to depletion, but are assessed for impairment either individually or on an aggregated basis. The costs of certain unevaluated leasehold acreage are also not subject to depletion. Costs not subject to depletion are periodically assessed for possible impairment or reductions in recoverable value. If a reduction in recoverable value has occurred, costs subject to depletion are increased or a charge is made against earnings for those operations where a reserve base is not yet established.

Estimated future removal and site restoration costs are provided over the life of proven reserves on a units-of-production basis. Costs, which include production equipment removal and environmental remediation, are estimated each period by management based on current regulations, actual expenses incurred, and technology and industry standards. The charge is included in the provision for depletion and depreciation and the actual restoration expenditures are charged to the accumulated provision amounts as incurred.

The Company applies a ceiling test to capitalized costs which limits such costs to the aggregate of the estimated present value, using a ten percent discount rate of the estimated future net revenues from production of proven reserves at year end at market prices less future production, administrative, financing, site restoration, and income tax costs plus the lower of cost or estimated market value of unproved properties. If capitalized costs are determined to exceed estimated future net revenues, a write-down of carrying value is charged to depletion in the period.

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MAINLAND RESOURCES INC.
(An Exploration Stage Company)

NOTES TO FINANCIAL STATEMENTS
FEBRUARY 28, 2010, February 28, 2009 and February 29, 2008
(Audited)

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates. Significant areas requiring management's estimates and assumptions are the determination of the fair value of transactions involving common stock, stock based compensation, financial instruments as well as deferred tax balances and asset impairment tests. Further, depreciation, depletion and amortization of oil and gas properties and the impairment of oil and gas properties are determined using estimates of oil and gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures, including future costs to dismantle, dispose, plug, and restore the Company's properties. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. Proved reserves of oil and natural gas are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing conditions.

The fair value of the Company's financial assets and financial liabilities approximate their carrying values due to the immediate or short-term maturity of these financial instruments.

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalent accounts in financial institutions. As of February 28, 2010, the Company's cash and cash equivalents exceed federally insured limits.

Basic earnings (loss) per share includes no dilution and is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. Dilutive earnings (loss) per share reflect the potential dilution of securities that could share in the earnings of the Company. Where applicable, dilutive loss per share is equal to that of basic loss per share as the effects of stock options and warrants have been excluded as they are anti-dilutive.

Oil and natural gas revenues are recorded using the sales method, whereby the Company recognizes oil and natural gas revenue based on the amount of oil and gas sold to purchasers, when title passes, the amount is determinable and collection is reasonably assured. Actual sales of gas are based on sales, net of the associated volume charges for processing fees and for costs associated with delivery, transportation, marketing, and royalties in accordance with industry standards. Operating costs and taxes are recognized in the same period in which revenue is earned.

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MAINLAND RESOURCES INC.
(An Exploration Stage Company)

NOTES TO FINANCIAL STATEMENTS
FEBRUARY 28, 2010, February 28, 2009 and February 29, 2010
(Audited)

The Company has adopted FASB ASC 718-10, "Compensation- Stock Compensation", which requires the compensation cost related to share-based payments, such as stock options and employee stock purchase plans, be recognized in the financial statements based on the grant-date fair value of the award.

The Company accounts for equity instruments issued in exchange for the receipt of goods or services from other than employees in accordance with FASB ASC 718-10 and the conclusions reached by the FASB ASC 505-50. Costs are measured at the estimated fair market value of the consideration received or the estimated fair value of the equity instruments issued, whichever is more reliably measurable. The value of equity instruments issued for consideration other than employee services is determined on the earliest of a performance commitment or completion of performance by the provider of goods or services as defined by FASB ASC 505-50.

In June 2009, the FASB issued FASB ASC 860-10, "Transfers and Servicing", FASB ASC 860-10 eliminates the concept of a "qualifying special-purpose entity," changes the requirements for derecognizing financial assets, and requires additional disclosures in order to enhance information reported to users of financial statements by providing greater transparency about transfers of financial assets, including securitization transactions, and an entity's continuing involvement in and exposure to the risks related to transferred financial assets. FASB ASC 860-10 is effective for fiscal years beginning after November 15, 2009. The Company will adopt FASB ASC 860-10 in fiscal 2010. The Company does not expect that the adoption of FASB ASC 860-10 will have a material impact on its financial position, cash flows or results of operations.

In June 2009, the FASB issued FASB ASC 810-10, "Consolidation", which included the following: (1) the elimination of the exemption for qualifying special purpose entities, (2) a new approach for determining who should consolidate a variable-interest entity, and (3) changes to when it is necessary to reassess who should consolidate a variable-interest entity. FASB ASC 810-10 is effective for the first annual reporting period beginning after November 15, 2009 and for interim periods within that first annual reporting period. The Company will adopt FASB ASC 810-10 in fiscal 2010. The Company does not expect that the adoption of FASB ASC 810-10 will have a material impact on its financial position, cash flows or results of operations.

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In August 2009, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2009-05, "Fair Value Measurements and Disclosures (Topic 820): Measuring Liabilities at Fair Value". The guidance provided in this update is effective for the first reporting period beginning after issuance. The adoption of this statement has had no material effect on the Company's financial position, cash flows or results of operations.

In September 2009, the Financial Accounting Standards Board (FASB) issued ASU 2009-12, "Fair Value Measurements and Disclosures" (Topic 820): Investments in Certain Entities That Calculate Net Asset Value Per Share (or Its Equivalent). This update provides amendments to subtopic 820-10, Fair Value Measurements and Disclosures - Overall, for the fair value measurement of investments in certain entities that calculate net asset value per share (or its equivalent). The amendments in this update are effective for interim and annual periods ending after December 15, 2009. Early application is permitted in financial statements for earlier interim and annual periods that have not been issued. The adoption of this statement did not have a material impact on the Company's financial position, cash flows and results of operations.

In January 2010, the FASB issued Accounting Standards Update (ASU) 2010-01, "Equity (Topic 505-10): Accounting for Distributions to Shareholders with Components of Stock and Cash (A Consensus of the FASB Emerging Issues Task Force)". This amendment to Topic 505 clarifies the stock portion of a distribution to shareholders that allows them to elect to receive cash or stock with a limit on the amount of cash that will be distributed is not a stock dividend for purposes of applying Topics 505 and 260. This standard is effective for interim and annual periods ending on or after December 15, 2009, and would be applied on a retrospective basis. The adoption of this statement did not have a material impact on the Company's financial position, cash flows and results of operations.

In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2010-02, "Consolidation (Topic 810): Accounting and Reporting for Decreases in Ownership of a Subsidiary". This amendment to Topic 810 clarifies, but does not change, the scope of current US GAAP. It clarifies the decrease in ownership provisions of Subtopic 810-10 and removes the potential conflict between guidance in that Subtopic and asset derecognition and gain or loss recognition guidance that may exist in other US GAAP. An entity will be required to follow the amended guidance beginning in the period that it first adopts FAS 160 (now included in Subtopic 810-10). For those entities that have already adopted FAS 160, the amendments are effective at the beginning of the first interim or annual reporting period ending on or after December 15, 2009. The amendments should be applied retrospectively to the first period that an entity adopted FAS 160. The Company does not expect the provisions of ASU 2010-02 to have a material effect on the financial position, results of operations or cash flows of the Company.

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In January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2010-6, "Improving Disclosures about Fair Value Measurements." This update requires additional disclosure within the roll forward of activity for assets and liabilities measured at fair value on a recurring basis, including transfers of assets and liabilities between Level 1 and Level 2 of the fair value hierarchy and the separate presentation of purchases, sales, issuances and settlements of assets and liabilities within Level 3 of the fair value hierarchy. In addition, the update requires enhanced disclosures of the valuation techniques and inputs used in the fair value measurements within Levels 2 and 3. The new disclosure requirements are effective for interim and annual periods beginning after December 15, 2009, except for the disclosure of purchases, sales, issuances and settlements of Level 3 measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010. As ASU 2010-6 only requires enhanced disclosures, the Company does not expect that the adoption of this update will have a material effect on its financial position, cash flows and results of operations.

On February 27, 2008, the Company entered into an option agreement (the "Option Agreement") with Kingsley Resources, Inc. ("Kingsley"), pursuant to which the Company acquired all the right, title and interest Kingsley had in and to certain leasehold estates in the state of Louisiana ("the Leases") which were the subject of a purchase agreement dated December 11, 2007, and modified February 1, 2008 (collectively, the "Leasehold Purchase Agreement") between Kingsley and Permian Basin Acquisition Fund ("Permian"), pursuant to which Kingsley had the right to acquire the sub-surface rights provided for in the Leases. In order to complete the acquisition of the Leases the Company was required to pay $100,000 on April 2, 2008 to Kingsley and assume all of Kingsley's obligations under the Leasehold Purchase Agreement. On March 14, 2008, the Company completed the Option agreement and the Leasehold Purchase Agreement at a total cost of $687,596, which includes the $100,000 that was paid on April 2, 2008, for approximately 2,551 net acres.

On December 21, 2009, the Company acquired, under its agreement with Petrohawk, an additional 159.3 net acres for $412,985 and on December 23, 2009 the Company also acquired an additional 51.96 net acres in conjunction with Petrohawk for $94,731 within the Cotton Valley/Haynesville trend in the State of Louisiana.

The Company has leased various other properties totalling approximately 144 net acres, consisting of approximately 84 net acres leased as of February 29, 2008 and added 60 net acres leased during the year ended February 28, 2009 for additional consideration of $22,753. These additional property leases, within the Cotton Valley/Haynesville trend in the state of Louisiana, are for three year terms. The Company has a 100% Working Interest and a 75% N.R.I. in the leases comprising a total of 2,695 net acres.

On July 14, 2008, The Company entered into a binding venture agreement with Petrohawk Energy Corporation ("Petrohawk") for the joint development of the Haynesville Shale on the Company's properties ("the Leases") in De Soto Parish, Louisiana. Effective August 4, 2008, the Company entered into a definitive binding agreement with Petrohawk consummating the transaction on July 14, 2008.

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The Company will transfer 60% of its De Soto Parish leases to Petrohawk at closing, but only as the Leases relate to all depths below the base of the Cotton Valley Formation, and specifically the Haynesville Shale. Petrohawk agrees to gather and market the Company's production from above the base of the Cotton Valley Formation, pursuant to a mutually acceptable agreement.

The first well under the Petrohawk Agreement, the Griffiths 11- #1, began drilling in October 2008. The well commenced production at the end of January 2009. The Company owns a 40% working interest in the well.

The second well under the Petrohawk Agreement, the Steven Douglas LLC 16 - #1, began drilling in April 2009. The well commenced production in March, 2010. The Company owns a 19.09% working interest in the well.

The third well under the Petrohawk Agreement, the Dehan 15 - #1-H, began drilling in May 2009. The well commenced production in August 2009. The Company owns a 25.73% working interest in the well.

The fourth well under the Petrohawk Agreement, the International Paper 12-#1H commenced production in April 2010. The Company owns a 20.58% working interest in the well.

The fifth well under the Petrohawk Agreement, the Paul Little 7H-#1. Drilling was completed in May 2010 and is waiting on completion. The Company owns a 20.54% working interest in the well.

Subsequent to the period on April 22, 2010, the Company closed the sale of its Haynesville Shale assets in East Holly Field, DeSoto Parish, Louisiana. The assets have been sold to EXCO Operating Company, LP., a wholly owned subsidiary of EXCO Resources, for $28,159,604 effective January 1, 2010. The Company has sold its 40% working interest in all rights deeper than the base of the Cotton Valley formation (which has been defined to be 100 feet below the stratigraphic equivalent of the Cotton Valley formation and includes all of the Company's producing wells as described above) in the East Holly Field. The Company continues to own a 100% interest in all rights above this depth and specifically, in the Cotton Valley, Hosston and Upper Bossier sections.

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On September 3, 2008, the Company signed an Option Agreement with Westrock Land Corp ("Westrock") to acquire 5,000 net acres in mineral oil and gas leases located in the State of Mississippi. In accordance with the terms and provisions of the Option Agreement; (i) the Company will acquire a 100% working interest and a 75% net revenue interest in the Leases; (ii) the Company has agreed to pay certain acquisition costs per net mineral acres and also paid a $500,000 deposit on September 3, 2008 to secure the Option Agreement; (iii) the balance of the acquisition costs totalling $2,275,000 will be due and payable upon completion of the due diligence, to be completed by the Company no later than October 15, 2008. The Option Agreement was subsequently

extended on each of October 15, 2008, November 30, 2008, April 16, 2009 and June 1, 2009 whereby the option period has been extended until January 20, 2010. Additional deposits of $250,000, $100,000, $250,000, $100,000 and $100,000 were paid on October 17, 2008, December 1, 2008, December 29, 2008, April 27, 2009, May 6, 2009 and June 5, 2009 for a total deposit to date of $1,300,000 (February 28, 2009 - $1,100,000). Effective February 12, 2010, based upon completion of its due diligence, the Board of Directors determined that it was not in the best interests of the Company and its shareholders to proceed with the acquisition and development of the Leases in accordance with the terms and provisions of the Option Agreement and the Company authorized the termination of the Option Agreement. The company and Westrock agreed that the Option Agreement would be terminated and the Company and Westrock would be released from their respective duties and obligations. The Company has forfeited its deposit of the $1,300,000 paid to Westrock which was recorded as a loss during the period.

On June 22, 2009, the Company signed an Option Agreement with Westrock Land Corp to acquire approximately 8,000 net acres in mineral oil and gas leases located in the State of Mississippi. In accordance with the terms and provisions of the Option Agreement; (i) the Company will acquire a 100% working interest and a minimum 75% net revenue interest in the Leases; (ii) the Company has agreed to pay certain acquisition costs per net mineral acres by August 31, 2009. On September 28, 2009, the Company amended the Option Agreement to expand the acreage to include an additional 225 acres thus aggregating approximately 8,225 net acres subject to the Option Agreement. The Company further agreed to advance a payment of $300,000 towards the total purchase price of the acreage under the Option Agreement on August 31, 2009. On October 13, 2009 the Company paid an addition $900,000 towards the purchase price of the property and paid the final instalment of $2,090,060 on November 3, 2009 for a total purchase price of $3,290,060. During the year the Company acquired approximately an additional 861 net acres for $122,376 and subsequent to year end the Company acquired approximately an additional 8,573 net acres at a cost of $556,258. The Company's total acreage as of May 14, 2010 is approximately 17,434 net acres, with net revenue interests ranging from 71.00% to 78.34%.

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Effective on September 17, 2009, the Board of Directors of the Company authorized the execution of a letter agreement (the "Letter Agreement") with American Exploration Corporation, a Nevada corporation ("AEC") to jointly develop contiguous acreage known as the Buena Vista Area located in Mississippi (the "Joint Development Project"). In accordance with the terms and provisions of the Letter Agreement: (i) AEC agreed to commit approximately 5,000 net acres and the Company agreed to commit approximately 8,225 net acres to the Joint Development Project; (ii) the Company shall be the operator of the Joint Development Project; (iii) the Company agreed to pay 80% of the initial well drilling and completion costs to earn a 51% working interest in the well and the total Joint Development Project; and (iv)AEC agreed to pay 20% of the initial well drilling and completion costs to earn a 49% working interest in the well and the total Joint Development Project. Also in accordance with the terms and provisions of the Joint Development Project, future costs, including drilling and completions, for oil and gas activities of the net acreage in the Joint Development Project will be split on a 51% / 49% basis between the Company and AEC, respectively. The Company was required to acquire the acreage committed to the Joint Development Project from an unrelated third party on or before October 15, 2009 otherwise the Letter Agreement would terminate and would no longer be in force and effect. The Company completed the transaction as per above paragraph.

Subsequent to the year end on April 26, 2010, AEC failed to fund its 20% share of the estimated total well costs of the Burkley-Phillips No. 1 well on the company's Buena Vista Prospect ("Prospect") in Jefferson County, Mississippi. As a result, AEC forfeited its rights to a 29% working interest in the well and in the Prospect in favour of the Company. AEC will continue to be entitled to receive a 20% working interest in the first well and the Prospect after completion, subject to compliance by AEC with all other terms and conditions of the Letter Agreement and the related Joint Operating Agreement. Subsequent to the year end on March 22, 2010 the Company and AEC entered into a definitive Merger Agreement and Plan of Merger (refer to Note 4).

The Company's Oil and Gas properties are made up as follows:

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