Triangle Petroleum Corp - FORM 10-K

Attached files

file	filename
EX-31.01 - Triangle Petroleum Corp	v219018_ex31-01.htm
EX-31.02 - Triangle Petroleum Corp	v219018_ex31-02.htm
EX-21.01 - Triangle Petroleum Corp	v219018_ex21-01.htm
EX-32.01 - Triangle Petroleum Corp	v219018_ex32-01.htm
EX-23.02 - Triangle Petroleum Corp	v219018_ex23-02.htm
EX-99.01 - Triangle Petroleum Corp	v219018_ex99-01.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(mark one)

þANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended January 31, 2011

¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES AND EXCHANGE ACT OF 1934

For the transition period from _____________________________ to _________________________________

Commission file number 001-34945

TRIANGLE PETROLEUM CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

Nevada		98-0430762
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

1660 Wynkoop St., Suite 900
Denver, CO	80202	(303) 260-7125
(Address of Principal Executive offices)	(Zip Code)	(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class:		Name of each exchange on which registered: NYSE Amex LLC
Common Stock, $0.00001 par value

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. Yes ¨ No þ

Indicate by checkmark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes¨ Noþ

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨ Not Required

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the 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.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer ¨		Accelerated filer ¨
Non-accelerated filer ¨		Smaller reporting company þ
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes Noþ

The aggregate market value of the voting common equity held by non-affiliates as of July 31, 2010, based on the closing sales price of the common stock was $49,505,824. For purposes of this computation, all officers, directors, and 5 percent beneficial owners of the registrant are deemed to be affiliates. Such determination should not be deemed an admission that such directors, officers, or 5 percent beneficial owners are, in fact, affiliates of the registrant.

As of April 1, 2011, there were 42,942,538 shares of registrant’s common stock outstanding.

TRIANGLE PETROLEUM CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED JANUARY 31, 2011

		Page
Part I

Item 1.	Business	3

Item 1A.	Risk Factors	14

Item 1B.	Unresolved Staff Comments	26

Item 2.	Properties	26

Item 3.	Legal Proceedings	29

Item 4.	RESERVED	29

Part II

Item 5.	Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30

Item 6.	Selected Financial Data	31

Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	31

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	36

Item 8.	Financial Statements and Supplementary Data	36

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	36

Item 9A.	Controls and Procedures	37

Item 9B.	Other Information	37

Part III

Item 10.	Directors, Executive Officers and Corporate Governance	38

Item 11.	Executive Compensation	43

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	46

Item 13.	Certain Relationships and Related Transactions, and Director Independence	47

Item 14.	Principal Accounting Fees and Services	48

Part IV

Item 15.	Exhibits; Financial Statement Schedules	49

Signatures.

PART I

ITEM 1. BUSINESS

OVERVIEW

We are an exploration and development company currently focused on the acquisition and development of unconventional shale oil resources in the Bakken Shale and Three Forks formations in the Williston Basin of North Dakota and Montana. As of April 1, 2011, we have acquired, or committed to acquire, approximately 30,000 net acres primarily in McKenzie, Williams and Stark Counties of North Dakota and Roosevelt County, Montana. Having identified an area of focus in the Bakken Shale and Three Forks formations that we believe will generate attractive returns on invested capital, we are continuing to explore further opportunities in the region with a long-term goal of reaching 100,000 net acres.

We also hold over 400,000 net acres in the Maritimes Basin of Nova Scotia which contains numerous conventional and unconventional prospective reservoirs, including the Windsor Group sandstones and limestones and Horton Group shales. We currently have no plans to devote a significant portion of our capital budget to this region outside of a regional seismic program and further evaluation of well data in the region. We continue to seek a strategic partner interested in pursuing the potential long-term value offered by our holdings in this region or a farm-out arrangement whereby a partner will fund our future seismic and well programs.

Our Strategy

Our goal is to increase stockholder value by increasing our Williston Basin leasehold position and converting such leasehold position into proven reserves, production and cash flow at attractive returns on invested capital. We are seeking to achieve this goal through the following strategies:

•

Focus on the Williston Basin. We believe the Bakken Shale and Three Forks formations in the Williston Basin represent one of the largest oil deposits in North America. A report issued by the United States Geological Survey (“USGS”) in April 2008 classified these formations as the largest continuous oil accumulation ever assessed by it in the contiguous United States. We expect to continue to aggressively pursue additional leasehold positions where our geologic model suggests the Bakken Shale and/or the Three Forks formations are believed to be prospective. We believe horizontal wells drilled on our acreage will generate attractive returns on invested capital given our outlook for the price of oil and the finding and development costs associated with converting the acreage from resource potential to proven and producing reserves.

•

Continue to pursue leasehold acquisitions at attractive costs. We believe significant additional acreage in the Williston Basin, prospective for the Bakken Shale and Three Forks formations, is and will be available for acquisition allowing us to reach our long-term goal of 100,000 net acres, subject to availability of sources of financing to us that we find reasonable. We believe many of the active operators in the area have assembled sizeable leasehold positions and have shifted from a leasehold acquisition strategy to a development strategy, reducing the competition for additional leasehold acreage. We plan to explore various techniques to add acreage, including participating in state and federal lease sales, pursuing leasehold acquisitions, farm-in agreements with existing operators and farm-in opportunities on lease positions that are about to expire. We believe many operators will choose to farm-out lease positions rather than allow leases to expire, giving us further opportunities to add significant leasehold at attractive costs.

•

Maintain a balanced mix of operated and non-operated leasehold positions. Through our non-operated positions, we plan to leverage our currently low overhead while broadening our operating experience by teaming with operators that we believe are some of the most active and knowledgeable in the Williston Basin. We believe that our partnering approach also provides significant opportunities to expand our collective acreage position. We have significantly expanded our operated leasehold positions and believe we will ultimately be named operator on over 20% of our current approximately 30,000 net acres. We are working to build our operational team and plan to operate up to 2 gross (1.6 net) wells over the next 12 months. We are also currently seeking to enter contracts with qualified service providers and have targeted to commence a one rig operated program in late 2011. Our long-term goal is to serve as operator for two-thirds of our net acreage position.

•

Capture upside value in Nova Scotia. We hold approximately 400,000 net acres in the Province of Nova Scotia in Canada that we believe contains multiple conventional and unconventional targets. Increased industry activity in the Maritimes Basin, along with other factors such as more restrictive permitting procedures in the Gulf of Mexico and activity in other unconventional basins, has increased industry interest in this area. In 2010, Southwestern Energy Company, a mid-cap independent exploration company, announced that it had leased a large undeveloped acreage position in the Province of New Brunswick and committed to spend $47 million on the development of such acreage. Additionally, in 2010, Apache Corporation drilled and tested the B-41 Green Road and the G-59 Will deMille wells pursuant to its December 2009 farm-out agreement with Corridor Resources Inc. We continue to seek a strategic partner interested in pursuing the potential long-term value offered by our holdings in this region or a farm-out arrangement whereby a partner will fund our future seismic and well programs.

•

Maintain conservative leverage position to enhance financial flexibility. Acquisitions and farm-in opportunities will require us to move rapidly in many instances. As such, we expect to maintain excess cash balances and a conservative leverage position while we focus on leasehold acquisitions. Between now and the end of 2011, we expect to primarily use equity capital to fund our leasehold expansion and only add leverage where cash flow and reserve growth allow.

Our Competitive Strengths

We have the following competitive strengths that we believe will help us to successfully execute our business strategies:

•

We benefit from the increasing activity in the Bakken Shale and Three Forks formations acreage. Activity levels in the Williston Basin continue to increase with a drilling rig count of 162 at April 1, 2011 versus 65 at January 1, 2010. We benefit from the increasing number of wells drilled and the corresponding data available from public sources and the North Dakota Industrial Commission. This activity and data has begun to define the geographic extent of the Bakken Shale and Three Forks formations, which we believe reduces the amount of risk we face on future leasehold acquisitions and development operations. In addition, the leading operators in the Williston Basin have developed drilling and completion technologies that have significantly reduced production risk, decreased per unit drilling and completion costs and enhanced returns.

•

Our size allows us to pursue a broader range of acquisition opportunities. Our size provides us with the opportunity to acquire smaller acreage blocks that may be less attractive to larger operators inside of the Williston Basin. Some small private ventures are struggling to secure funding to meet drilling costs which provides us with opportunities for acquisitions at attractive prices. We believe that our acquisition of these smaller blocks will have a meaningful impact on our overall acreage position and should facilitate our long-term goal of owning 100,000 net acres.

•

Experienced management team with proven acquisition and operating capabilities. Dr. Peter Hill, our Chief Executive Officer, has 40 years of oil and natural gas experience, including over 20 years with British Petroleum in a variety of roles including Chief Geologist, Chief of Staff for BP Exploration, President of BP Venezuela and Regional Director for Central and South America. He currently serves as the non-executive Chairman for Toreador Resources Corporation, a public company currently developing an oil shale prospect in the Paris Basin in France. He is complemented by Jonathan Samuels, our Chief Financial Officer, who spent over five years as a member of an energy focused investment management firm.

•

We have no outstanding indebtedness and we have approximately $150 million in cash. As of April 1, 2011, we had approximately $150 million in cash. We will use this cash to meet our drilling commitments and pursue additional leasehold acquisitions.

Operations and Oil and Natural Gas Properties

Williston Basin

We own operated and non-operated leasehold positions in the Williston Basin. We anticipate commencing our first operated well in the second half of 2011. The operations of our non-operated leasehold positions are primarily conducted through agreements with major operators in the Williston Basin, including Slawson Exploration, Inc. (“Slawson”), Kodiak Oil and Gas Corporation (“Kodiak”), EOG Resources, Inc. (“EOG”), Brigham Exploration Company, Marathon Oil Corporation, Continental Resources, Inc., XTO Energy Inc., Whiting Petroleum Corporation, Hess Corporation and others. These companies are experienced operators in the development of the Bakken Shale and Three Forks formations. Upon the closing of our recently announced EOG Purchase and Slawson Purchase, we believe that we will have the right to operate approximately 7,000 net acres, or over 20% of our approximately 30,000 net acres. We continue to build our technical and financial team and, in addition to our experienced geological, land, brokerage and title teams, we expect to have an experienced operating team in place over the next several months. Our primary areas of operation are focused in the Rough Rider area of McKenzie, Williams and Stark Counties in North Dakota and Roosevelt County, Montana.

As of April 1, 2011, we have participated in the drilling of 14 gross non-operated wells, including three producing wells and 11 wells in various stages of drilling and completion. In addition, we have 12 gross non-operated wells set to spud in the next 30 days and an additional 34 gross non-operated wells already permitted to drill. Over the next 12 months, we plan to participate in a minimum of 75 gross (10.6 net) wells, including as many as two gross wells that we will operate. With an average drilling and completion cost of approximately $8 million per well, we have budgeted a range of anticipated drilling capital costs of $80 million to $90 million over this period.

Using industry accepted well-spacing parameters and long lateral well bores, we believe that there could be over 180 net unrisked drilling locations for the Bakken Shale and Three Forks formations on our acreage in the Williston Basin. Based on current industry expectations, we believe we can drill up to eight 9,500 foot lateral wells on 1,280 acre spacing units within our acreage. Consistent with leading field operators, we plan to perform multi-stage fracs with 25 to 30 stages on each lateral well. We also plan to drill shorter laterals on smaller units as dictated by our leasehold position.

Maritimes Basin

We have an 87% working interest in approximately 474,625 gross acres (approximately 412,924 net acres) in the Windsor Sub-Basin of the Maritimes Basin. In October 2009, we completed an approximately 30-square kilometer 2D seismic shoot on the Windsor Block and completed processing and interpreting the data in the fiscal quarter ending January 31, 2010. We believe that this seismic program, combined with the completion operations on three previously drilled vertical exploration wells, satisfied the first-year requirements of our 10-year production lease. We have completed our interpretation of the seismic data on the Windsor Block and we are currently seeking partners to participate in the drilling of the test well and to participate in a joint venture to further evaluate the potential of the Windsor Block.

The seismic program was designed to delineate the western end of the Windsor Basin where we believed the Windsor and Horton Shales to be prospective and that uplift, faulting and thrusting were likely to create conventional structures. We believe the seismic program showed a large, deep seated, conventional four-way closure with a large fault-controlled structural feature. The structures appear to be late Carboniferous in age, with later fault inversion, and precede the Permian natural gas generation following burial and over-thrusting. The setting is almost identical to the McCully Field in the Elgin Basin, New Brunswick and suggests a similar structural evolution. We believe the elevated structure is a natural conduit for migrating natural gas from the basin center, and with significant faulting natural fracturing may help rock porosity and permeability.

Under the terms of the Windsor Block 10-year production lease:

•

The production lease grants rights to approximately 474,625 gross acres (approximately 412,924 net acres).

•

We hold rights to conventional oil and natural gas within the lease, which includes shale natural gas, in the Windsor and Horton Shales, excluding natural gas from coal. We believe coals are not prospective within the Windsor Block.

•

To retain rights to this land block, we have agreed to continue to evaluate the lands during the first five years of the lease by drilling seven wells, completing three exploration wells previously drilled, and acquiring seismic data, which cost approximately Cdn $12.7 million gross (approximately U.S. $11.9 million). These wells are to be distributed across the land block to fully evaluate conventional and shale resources. In addition to annual progress reporting to maintain the lease in good standing, on the second anniversary of the lease, we are obliged to provide a detailed report to the Nova Scotia government to assess our evaluation activities to maintain certain lands. After the fifth anniversary, leased areas not adequately drilled or otherwise evaluated may be subject to surrender.

•

During the first year of the lease, we agreed to complete three exploration wells that were drilled in the prior year and acquire seismic data, which cost approximately Cdn $2 million gross (approximately U.S. $1.9 million).

•

As of April 1, 2011, royalty rates are set at 10% in Nova Scotia.

•

Tenure on some or all of the lands is eligible for renewal after the first 10 years, based on the establishment of commercial production and/or the satisfaction of certain drilling and evaluation criteria.

From May 2007 to June 2008, we executed the first phase of the Windsor Block exploration program consisting of a 2D and 3D seismic program, geological studies, and drilling and completing two vertical test wells (Kennetcook #1 and Kennetcook #2). From July 2008 to September 2009, we executed the second phase of the Windsor Block shale natural gas exploration program, which consisted of drilling three vertical exploration wells (N-14-A, O-61-C and E-38-A) and undertaking completion operations on all three of these wells.

In June 2009, we acquired an additional 30% working interest in the Windsor Block from Contact Exploration Inc. (“Contact”) in exchange for a 5.75% non-convertible gross overriding royalty interest, a cash payment of Cdn $270,000 (approximately U.S. $254,000) and our assumption of the liabilities related to the former working interest from Contact. This acquisition increased our working interest to its current 87% level.

We continue to seek a partner for the drilling of an onshore well in the development of the Windsor Block. In moving forward with the Windsor Block, we intend to consider a range of options pursuant to our existing production lease.

Non-Core Properties

In fiscal 2010, there was no exploration activity on our non-core non-producing and non-core undeveloped land positions and we continue to plan not to participate in any exploration activity for these projects in fiscal 2011. We have recently divested most of our non-core properties. During fiscal 2010, we sold:

•

our 25% working interest in 4,327 non-operated net acres in the Rocky Mountains for gross proceeds of $83,325 in June 2009;

•

our 50% working interest in 5,900 non-operated net acres in the Fayetteville Shale and all the related seismic data for gross cash proceeds of $767,000 in September 2009 and our remaining 3,880 non-operated net acres of the Fayetteville Shale acreage for gross cash proceeds of $247,000 in November 2009. Costs related to these sales were approximately $30,000; and

•

one of the producing wells and our 12% working interest in 154 non-operated net undeveloped acres in the Alberta Deep Basin for $426,600 in January 2010.

In May 2010, we announced that we closed the sale of an existing wellbore and associated acreage in Alberta for approximately $977,000.

Our remaining non-core producing properties include 4,427 non-operated acres in the Rocky Mountains and 3,024 net acres in the Alberta Deep Basin of Canada.

Major Customers

The sale of most of our crude oil is to Eighty Eight Oil LLC and XTO Energy Inc. During the year ended January 31, 2011, 67% of our total oil and natural gas revenues were received from Eighty Eight Oil LLC and 22% of our total oil and natural gas revenues were from XTO Energy Inc. There were no other companies that purchased more than 10% of our oil and natural gas production. Although a substantial portion of our production is purchased by these two customers, we do not believe the loss of these customers would have a material adverse effect on our business as other customers would be accessible to us.

Competitors

In the Williston Basin, we compete with a number of larger public and private companies such as Continental Resources, Inc., Brigham Exploration Company, Enerplus Resources Fund, Kodiak, Oasis Petroleum Inc., Newfield Exploration Co., XTO Energy, Inc. (now part of ExxonMobil) and Whiting Petroleum Corporation. All of these companies have significantly more personnel and experience in the Williston Basin and greater access to capital than we do.

In the Maritimes Basin, there are several specialized competitors who have been pursuing their respective strategies for a number of years. These companies include Contact Exploration Inc., Stealth Ventures Ltd., Corridor Resources Inc., Apache Corporation and Southwestern Energy Company. These companies have gained technical expertise in the area as they have continued to advance their respective exploration programs.

Governmental Regulation

Our business is affected by numerous laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the oil and natural gas industry. We have developed internal procedures and policies to ensure that our operations are conducted in full and substantial environmental regulatory compliance.

Failure to comply with any laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on business. In view of the many uncertainties with respect to future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

We believe that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive an effect on our operations than on other similar companies in the oil and natural gas industry. Our future expenditures to comply with environmental requirements have been estimated in the consolidated financial statements included in this report, under the caption of asset retirement obligations.

Pricing and Marketing of Natural Gas

In Canada, the price of natural gas sold in interprovincial and international trade is determined by negotiations between buyers and sellers. Natural gas exported from Canada is subject to regulation by the National Energy Board of Canada (the “NEB”). Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain criteria prescribed by the NEB. Natural gas (other than propane, butanes and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day) must be made pursuant to an order of the NEB. Natural gas may be exported for a term of no more than one year in respect to propane and butane, and no more than two years in respect to ethane, with all exports requiring an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export license from the NEB and the issue of such a license requires the approval of the Governor in Council. The export of natural gas pursuant to an order or license is subject to the terms and conditions included by the NEB in such order or license.

Also in Canada, the government of Alberta regulates the volume of natural gas that may be removed from the Province for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.

In the U.S., historically, the sale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”), and regulations promulgated thereunder by the Federal Energy Regulatory Commission (“FERC”). In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”). The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993 and sales by producers of natural gas are uncontrolled and can be made at market prices. The natural gas industry historically has been heavily regulated and from time to time proposals are introduced by Congress and the FERC and judicial decisions are rendered that impact the conduct of business in the natural gas industry. We cannot assure you that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

Pricing and Marketing of Oil

In Canada, producers of oil negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. The price depends, in part, on oil quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance and other contractual terms, as well as the world price of oil. Crude oil exported from Canada is subject to regulation by the NEB and the Government of Canada. Oil exports may be made pursuant to export contracts with terms not exceeding two years in the case of heavy crude oil and not exceeding one year in the case of light crude oil, provided that an order approving any such export has been obtained from the NEB. Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export license from the NEB and the issue of such a license requires a public hearing and obtaining the approval of the Governor in Council. The export of oil pursuant to an order or license shall be subject to the terms and conditions included by the NEB in such order or license.

In the U.S., sales of crude oil, condensate and natural gas liquids are not regulated and are made at negotiated prices. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil that allowed for an increase in the cost of transporting oil to the purchaser.

Royalties and Incentives

Royalty Regimes are a significant factor in the profitability of oil, natural gas and natural gas liquids production. In the U.S., all royalties are determined by negotiations between the mineral owner and the lessee. In addition to federal regulation, each province in Canada has legislation and regulations that govern land tenure, royalties, production rates, environmental protection and other matters. In all Canadian jurisdictions, producers of oil and natural gas are required to pay annual rental payments in respect of Crown leases (i.e. government leases), and royalties and freehold production taxes in respect of oil and natural gas produced from Crown and freehold lands (i.e. non-government lands), respectively. Royalties payable on production from non-Crown lands are determined by negotiations between the freehold mineral owner and the lessee. However, Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are from time to time carved out of the working interest owner's interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties or net profits or net carried interests. From time to time the federal and provincial governments of Canada have established incentive programs which have included royalty rate reductions (including for specific wells), royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced planning projects.

Nova Scotia

In the Province of Nova Scotia, the royalty rate for onshore oil and natural gas production has been set at a flat rate of 10% of the petroleum that is produced in each month based on the fair market value of the petroleum at the wellhead. In determining the royalty to be paid on any petroleum other than oil, there is an allowance deducted for the cost of processing or separation as determined in any particular case by the Energy Minister. Notwithstanding the foregoing, no royalty shall be due with respect to any oil or natural gas that is produced pursuant to the first production lease that is granted with respect to lands subject to an exploration agreement, for a period of two years from the date of commencement of such lease.

Land Tenure

Oil and natural gas deposits located in the Province of Nova Scotia are owned by the provincial government and oil and natural gas deposits located in the western provinces of Canada are predominantly owned by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licenses and permits for varying terms and on conditions set forth in provincial legislation including specific work commitments or obligations to make rental, royalty or other payments. Oil and natural gas located in such provinces can also be privately owned, and, rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

The North American Free Trade Agreement

On January 1, 1994, the North American Free Trade Agreement (“NAFTA”) became effective among the governments of Canada, the United States and Mexico. In the context of energy resources, Canada continues to remain free to determine whether exports to the United States or Mexico will be allowed provided that any export restrictions do not: (i) reduce the proportion of energy resource exported relative to total supply (based upon the proportion prevailing in the most recent 36-month period), (ii) impose an export price higher than the domestic price and (iii) disrupt normal channels of supply. All three countries are generally prohibited from imposing minimum export or import price requirements and, except as permitted in the enforcement of countervailing and anti-dumping orders and undertakings, minimum or maximum import price requirements.

NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. NAFTA also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.

Environmental

United States

Like the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state and local laws and regulations designed to protect and preserve our natural resources and the environment. The recent trend in environmental legislation and regulation is generally toward stricter standards, and this trend is likely to continue. These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, seismic acquisition, construction, drilling and other activities on certain lands lying within wilderness and other protected areas; impose substantial liabilities for pollution resulting from our operations; and require the reclamation of certain lands.

The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions or both. In the opinion of our 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 us, as well as the oil and natural gas industry in general. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state statutes impose strict and joint and several liabilities on owners and operators of certain 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 neighboring 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 Resource Conservation and Recovery Act (the “RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize 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 hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements.

Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (the “OPA”) contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. For onshore and offshore facilities that may affect waters of the United States, the OPA requires an operator to demonstrate financial responsibility. Regulations are currently being developed under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on us. In addition, the Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into surface waters or to construct facilities in wetland areas. The Clean Air Act of 1970 and its subsequent amendments in 1990 and 1997 also impose permit requirements and necessitate certain restrictions on point source emissions of volatile organic carbons (nitrogen oxides and sulfur dioxide) and particulates with respect to certain of our operations. We are required to maintain such permits or meet general permit requirements. The EPA and designated state agencies have in place regulations concerning discharges of storm water runoff and stationary sources of air emissions. These programs require covered facilities to obtain individual permits, participate in a group or seek coverage under an EPA general permit. Most agencies recognize the unique qualities of oil and natural gas exploration and production operations. A number of agencies including but not limited to the EPA, the Bureau of Land Management, the Texas Commission of Environmental Quality, the Louisiana Department of Natural Resources, the North Dakota Industrial Commission, the Oklahoma Conservation Commission, the Wyoming Oil and Gas Conservation Commission, the Montana Board of Oil and Gas Conservation and similar commissions within these states and of other states in which we do business have adopted regulatory guidance in consideration of the operational limitations on these types of facilities and their potential to emit pollutants. We believe that we will be able to obtain, or be included under, such permits, where necessary, and to make minor modifications to existing facilities and operations that would not have a material effect on us.

The EPA amended the UIC provisions of the SDWA to exclude hydraulic fracturing from the definition of “underground injection.” However, the U.S. Senate and House of Representatives are currently considering the FRAC Act, which will amend the SDWA to repeal this exemption. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities, which could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. On November 30, 2010, the EPA issued a final rule requiring reporting of GHG emissions from the oil and natural gas industry. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, oil and natural gas operations could increase costs or could adversely affect demand for the oil and natural gas produced from our lands.

Also, on June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, or ACESA, which would establish an economy-wide cap-and-trade program to reduce United States emissions of GHGs including carbon dioxide and methane that may contribute to the warming of the Earth’s atmosphere and other climatic changes. If it becomes law, ACESA would require a 17% reduction in GHG emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of GHG emissions so that such sources could continue to emit GHGs into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic GHG emissions and President Obama has indicated his support of legislation to reduce GHG emissions through an emission allowance system.

Canada

The oil and natural gas industry is governed by environmental regulation under Canadian federal and provincial laws, rules and regulations, which restrict and prohibit the release or emission and regulate the storage and transportation of various substances produced or utilized in association with oil and natural gas industry operations. In addition, applicable environmental laws require that well and facility sites be abandoned and reclaimed, to the satisfaction of provincial authorities, in order to remediate these sites to near natural conditions. Also, environmental laws may impose upon “persons responsible” remediation obligations on contaminated sites. Persons responsible include persons responsible for the substance causing the contamination, persons who caused the release of the substance and any present or past owner, tenant or other person in possession of the site. Compliance with such legislation can require significant expenditures. A breach of environmental laws may result in the imposition of fines and penalties and suspension of production, in addition to the costs of abandonment and reclamation.

In Nova Scotia, environmental laws are consolidated in the Nova Scotia Environment Act. Under this Act, environmental standards and requirements applicable to compliance, cleanup and reporting are administered by the Nova Scotia Department of Environment.

In December 2002, the Government of Canada ratified the Kyoto Protocol (the “Protocol”). The Protocol calls for Canada to reduce its emissions of GHGs to 6% below 1990 “business as usual” levels between 2008 and 2012. It remains uncertain whether the Kyoto target of 6% below 1990 GHG emission levels will be enforced in Canada. On April 26, 2007, the Canadian government released “Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution” (the “Action Plan”), which set forth a plan for regulations to address both GHG and air pollution. On March 10, 2008, the Canadian government released an update to the Action Plan, “Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions” (the “Updated Action Plan”). Regulations for the implementation of the Updated Action Plan were originally intended to be in force by January 1, 2010. To date, no such regulations have been proposed. Further, representatives of the Canadian government have recently indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction ultimately taken by the United States with respect to GHG emissions regulation. Since it is presently unclear what approach will be adopted by the United States, the provisions of the Updated Action Plan, described below are expected to be significantly modified. The proposed compliance mechanisms under the Updated Action Plan include an emissions credit trading system for GHGs and certain industrial air pollutants, and several options for companies to choose from to meet GHG emission intensity reduction targets and encourage the development of new emission reduction technologies, including the option of making payments into a technology fund, an emissions and offset trading system, limited credits for emission reductions created between 1992 and 2006, and international emission credits pursuant to the clean development mechanism under the Kyoto Protocol for up to 10% of each company’s regulatory obligation.

In December 2009, world leaders met in Copenhagen, Denmark. Subsequent to that meeting, the Canadian federal government has indicated its commitment to comply with a non-binding reduction target of GHG emissions of 17% below 2005 levels. No specifics surrounding how this reduction will be achieved have yet been published.

Environmental legislation in the Province of Alberta involving oil and natural gas operations has been consolidated into the Environmental Protection and Enhancement Act (Alberta), the Water Act (Alberta) and the Oil and Gas Conservation Act (Alberta). These statutes impose environmental standards, require compliance, reporting and monitoring obligations and impose penalties. In addition, GHG emission reduction requirements are set out in the Climate Change and Emissions Management Act (Alberta) and came into effect on July 1, 2007. Under this legislation, Alberta facilities emitting more than 100,000 tonnes of GHGs a year must reduce their emissions intensity by 12% from their respective baseline emissions. Companies have four options to choose from in order to meet the reduction requirements outlined in this legislation, including: (i) making improvements to operations that result in reductions; (ii) purchasing emission credits from other sectors or facilities that have reduced their emissions below the required emission intensity reduction levels; (iii) purchasing off-set credits from other sectors or facilities that have emissions below the 100,000 tonne threshold and are voluntarily reducing their emissions in Alberta; or (iv) contributing to the Climate Change and Emissions Management Fund. Companies can choose one of these options or a combination thereof to meet their Alberta emissions reduction requirements.

Climate Change

Climate change has emerged as an important topic in public policy debate regarding our environment. It is a complex issue, with some scientific research suggesting that rising global temperatures are the result of an increase in GHGs, which may ultimately pose a risk to society and the environment. Products produced by the oil and natural gas exploration and production industry are a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations.

Formation

We were incorporated in the State of Nevada on December 11, 2001 under the name Peloton Resources Inc. On May 10, 2005, we changed our name to Triangle Petroleum Corporation.

Employees

As of April 1, 2011, we had 10 full time employees. We consider our relations with our employees to be good.

Properties

We maintain our principal office at 1660 Wynkoop St., Suite 900, Denver, Colorado, 80202. The lease for this location is effective on April 18, 2011. Prior to April 18, 2011, our principal office was located at 1625 Broadway, Suite 780, Denver, Colorado, 80202. Our telephone number is (303) 260-7125 and our facsimile number is (303) 260-5080. We also maintain an office in Calgary, Alberta, Canada. Our current office space consists of approximately 2,370 square feet in our 1625 Broadway office, 9,144 square feet in our 1660 Wynkoop office and 2,475 square feet in our Calgary office. The 1625 Broadway and Calgary leases run until September 2013. The 1660 Wynkoop lease begins on April 18, 2011 and runs through July 2015. Monthly rental payments under the leases are $4,816 for the 1625 Broadway office, $19,812 for the 1660 Wynkoop and Cdn $6,460 for the Calgary office. We will be closing the 1625 Broadway office and the Calgary office after we have transitioned to the office at 1660 Wynkoop.

Research and Development

As an exploration and production company, we do not normally engage in research and there were no development activities, or research and development expenditures made in the last two fiscal years.

Legal Proceedings

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business. We are currently not aware of any such legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse affect on our business, financial condition or results of operations.

Reports to Security Holders

We provide an annual report that includes audited financial information to our stockholders. We make our financial information equally available to any interested parties or investors through compliance with the disclosure rules for a smaller reporting company under the Exchange Act. We are subject to certain disclosure filing requirements, including filing Form 10-K annually and Form 10-Q quarterly. In addition, we file current reports on Form 8-K from time to time as required. The public may read and copy any materials that we file with the SEC, at the SEC’s Public Reference Room at 100 F Street NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically.

References to reserves and future net revenue in this annual report have been determined in accordance with the SEC guidelines and the United States Financial Accounting Standards Board (the “U.S. Rules”) and not in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The reserves data and other oil and natural gas information for the Company prepared in accordance with NI 51-101 can be found for viewing by electronic means in the Company’s Form 51-101F1 – Statements of Reserves Data and Other Oil and Gas Information under the Company’s profile on SEDAR at www.sedar.com.

The practice of preparing production and reserve quantities data under NI 51-101 differs from the U.S. Rules. The primary differences between the two reporting requirements include: (i) NI 51-101 requires disclosure of proved and probable reserves and the U.S. Rules require disclosure of only proved reserves; (ii) NI 51-101 requires the use of forecast prices in the estimation of reserves and the U.S. Rules require the use of 12-month average prices which are held constant; (iii) NI 51-101 requires disclosure of reserves on a gross (before royalties) and net (after royalties) basis and the U.S Rules require disclosure on a net (after royalties) basis; (iv) the Canadian standards require disclosure of production on a gross (before royalties) basis and the U.S. Rules require disclosure on a net (after royalties) basis; and (v) NI 51-101 requires that reserves and other data be reported on a more granular product type basis than required by the U.S. Rules.

Forward-Looking Statements

This annual report contains certain “forward-looking statements” within the meaning of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995 with respect to our business, financial condition, liquidity and results of operations. Words such as “anticipates,” “expects,” “intends,” “plans,” “predicts,” “believes,” “seeks,” “estimates,” “could,” “would,” “will,” “may,” “can,” “continue,” “potential,” “should,” and the negative of these terms or other comparable terminology often identify forward-looking statements. Statements in this annual report that are not historical facts are hereby identified as “forward-looking statements” for the purpose of the safe harbor provided by Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Section 27A of the Securities Act of 1933, as amended (the “Securities Act”). These forward-looking statements are not guarantees of future performance and are subject to risks and uncertainties that could cause actual results to differ materially from the results contemplated by the forward-looking statements, including the risks discussed in this annual report and the risks detailed from time to time in our future SEC reports. These forward-looking statements include, but are not limited to, statements about:

history of losses;

uncertainty of drilling results;

uncertainty of results of acquisitions;

termination of agreements with our partners;

our relationship with our partners;

inability to acquire additional leasehold interests or other oil and natural gas properties;

inability to manage growth in our business;

inability to control properties we do not operate;

inability to protect against certain liabilities associated with our properties;

lack of diversification;

substantial capital requirements and limited access to additional capital;

competition in the oil and natural gas industry;

global financial conditions;

oil and natural gas realized prices;

seasonal weather conditions;

marketing and distribution of oil and natural gas;

the influence of our significant stockholders;

government regulation of the oil and natural gas industry;

potential regulation affecting hydraulic fracturing;

environmental regulations, including climate change regulations;

uninsured or underinsured risks;

aboriginal claims relating to our Canadian properties;

defects in title to our oil and natural gas interests;

material weaknesses in our internal accounting controls; and

foreign currency exchange risks.

Many of the important factors that will determine these results are beyond our ability to control or predict. You are cautioned not to put undue reliance on any forward-looking statements, which speak only as of the date of this annual report. Except as otherwise required by law, we do not assume any obligation to publicly update or release any revisions to these forward-looking statements to reflect events or circumstances after the date of this annual report or to reflect the occurrence of unanticipated events.

GLOSSARY OF ABBREVIATIONS AND TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this report.

2-D seismic or 3-D seismic. Geophysical data that depicts the subsurface strata in two dimensions or three dimensions, respectively. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D seismic.

AMI. Area of mutual interest.

Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

Boepd. Boe per day.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Developed reserves. Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or for which the cost of required equipment is relatively minor when compared to the cost of a new well.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Farm-in or farm-out. An agreement under which the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. A layer of rock which has distinct characteristics that differ from nearby rock.

Horizontal well. A well that is drilled vertically to a certain depth and then drilled at a right angle within a specific interval.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Mcf. Thousand cubic feet of natural gas.

Mcfpd. Mcf per day.

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Mmcf. Million cubic feet of natural gas.

Mmcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved properties. Properties with proved reserves.

Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known accumulations.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres and is often established by regulatory agencies.

Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

Unproved properties. Properties with no proved reserves.

Wellbore. The hole drilled by the bit that is equipped for oil or natural gas production on a completed well.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

ITEM 1A. RISK FACTORS

You should carefully consider the following risk factors and all other information contained herein as well as the information included in this annual report in evaluating our business and prospects. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties, other than those we describe below, that are not presently known to us or that we currently believe are immaterial, may also impair our business operations. If any of the following risks occur, our business and financial results could be harmed. You should refer to the other information contained in this annual report, including our consolidated financial statements and the related notes.

Risks Relating to Our Business

We have a history of losses which may continue and negatively impact our ability to achieve our business objectives.

We incurred net losses of $20,277,197 and $2,140,101 for the fiscal years ended January 31, 2010 and 2011, respectively. We cannot assure you that we can achieve or sustain profitability on a quarterly or annual basis in the future. Our operations are subject to the risks and competition inherent in the oil and natural gas industry. We cannot assure you that future operations will be profitable. Revenues and profits, if any, will depend upon various factors, including whether we will be able to expand our revenues. We may not achieve our business objectives and the failure to achieve such goals would have an adverse impact on our business, financial condition and result of operations.

Oil and natural gas drilling is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.

An investment in us should be considered speculative due to the nature of our involvement in the exploration for, and the acquisition, development and production of, oil and natural gas. Oil and natural gas operations involve many risks, which even a combination of experience and knowledge and careful evaluation may not be able to overcome. There is no assurance that commercial quantities of oil and natural gas will be discovered or acquired by us.

We have substantial capital requirements that, if not met, may hinder our operations.

We anticipate that we will make substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future and for future drilling programs. If we have insufficient revenues, we may have a limited ability to expend the capital necessary to undertake or complete future drilling programs. We cannot assure you that debt or equity financing, or cash generated by operations, will be available or sufficient to meet these requirements or for other corporate purposes, or if debt or equity financing is available, that it will be on terms acceptable to us. Moreover, future activities may require us to alter our capitalization significantly. Our inability to access sufficient capital for our operations could have a material adverse effect on our business, financial condition, results of operations or prospects.

We may not adhere to our proposed drilling schedule.

Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:

the availability and costs of drilling and service equipment and crews;

economic and industry conditions at the time of drilling;

prevailing and anticipated prices for oil and natural gas;

the availability of sufficient capital resources;

the results of our drilling;

the acquisition, review and interpretation of seismic data; and

our ability to obtain permits for drilling locations.

Although we have identified or budgeted for numerous drilling locations, we may not be able to drill those locations within our expected time frame, or at all. In addition, our drilling schedule may vary from our expectations because of future uncertainties.

Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.

Our recent growth is due in large part to acquisitions of producing properties and undeveloped leasehold. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems, and does not involve a review of seismic data or independent environmental testing. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities, including any structural, subsurface and environmental problems that may exist or arise. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete future acquisitions on terms that we believe are acceptable or, even if completed, that do not contain problems that reduce the value of acquired property.

The results of our planned drilling in the Bakken Shale and Three Forks formations, each an emerging play with limited drilling and production history, are subject to more uncertainties than drilling programs in more established formations and may not meet our expectations for production.

In the second half of 2011, we plan to begin drilling wells in the Bakken Shale and Three Forks formations. Part of our drilling strategy to maximize recoveries from the Bakken Shale and Three Forks formations involves the drilling of horizontal wells using completion techniques that have proven to be successful for other companies in other shale formations. Our experience with horizontal drilling of the Bakken Shale and Three Forks formations, as well as the industry’s drilling and production history in the formations, is limited. The ultimate success of these drilling and completion strategies and techniques in these formations will be better evaluated over time as more wells are drilled and longer term production profiles are established. In addition, the decline rates in these formations may be more substantial than in other areas and in other shale formations, making overall production difficult to estimate until our experience in these formations increases. Accordingly, the results of our future drilling in the Bakken Shale and Three Forks formations are more uncertain than drilling results in the other formations with established reserves and production histories.

Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging plays. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and takeaway capacity or otherwise, and/or oil and natural gas prices remain depressed or decline further, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material writedowns of unevaluated properties and the value of our undeveloped acreage could decline in the future.

The lack of availability or high cost of drilling rigs, fracture stimulation crews, equipment, supplies, insurance, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, fracture stimulation crews, equipment, supplies, insurance or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. If increasing levels of exploration and production result in response to strong prices of oil and natural gas, the demand for oilfield services will likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of drilling rigs, equipment, supplies, insurance or qualified personnel were particularly severe in North Dakota or Montana, we could be materially and adversely affected because our operations and properties are concentrated in those areas.

The proposed United States federal budget for fiscal year 2011 and other pending legislation contain certain provisions that, if passed as originally submitted, will have an adverse effect on our business, financial position and results of operation.

In February 2010, the Obama administration released its budget proposals for the fiscal year 2011, which included numerous proposed tax changes. The proposed budget and legislation would repeal many tax incentives and deductions that are currently used by U.S. oil and natural gas companies and impose new taxes. Among others, the provisions include: repeal of the enhanced oil recovery and marginal well tax credits; repeal of the expensing of intangible drilling costs; repeal of the deduction for tertiary injectants; repeal of passive loss exceptions for working interests in oil and natural gas properties; repeal of the percentage depletion deduction for oil and natural gas properties; repeal of the manufacturing tax deduction for oil and natural gas companies; increase in the geological and geophysical amortization period for independent producers; and implementation of a fee on non-producing leases located on federal lands. Should some or all of these provisions become law our taxes could increase, potentially significantly, after net operating losses are exhausted, which would have a negative impact on our business, financial position and results of operation. This could also reduce our drilling activities in the future. Although these proposals initially were made more than one year ago, none have been voted on or become law. We do not know the ultimate impact these proposed changes may have on our business, financial position and results of operation.

We rely on independent experts and technical or operational service providers over whom we may have limited control.

We use independent contractors to provide us with technical assistance and services. We rely upon the owners and operators of rigs and drilling equipment, and upon providers of field services, to drill and develop our prospects to production. In addition, we rely upon the services of other third parties to explore or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. Our limited control over the activities and business practices of these providers, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially and adversely affect our business, results of operations and financial condition.

The termination of our agreements with Slawson, Kodiak or OGR could have a material adverse effect on our business, financial condition and results of operations.

Our agreements with Slawson, Kodiak and Oppenheimer Global Resource Private Equity Fund I and a related co-investment fund (“OGR”) are essential to us and our future development. Our agreement with Slawson remains in effect as long as there is a producing well and for a period of 90 days thereafter, but may be continued if another well is being drilled or reworked at the end of this period. Our agreement with OGR remains in effect until October 2013 unless either OGR achieves certain acquisition thresholds before that date and elects to extend the term of the agreement, or OGR fails to achieve certain thresholds and we elect to terminate the agreement. Also, OGR may terminate the agreement if our net worth falls below a certain level or OGR determines that changes in our executive management team or financial prospects are not satisfactory. Termination of any of these agreements would require us to seek another collaborative relationship in that territory. We cannot assure you that a suitable alternative third party would be identified, and even if identified, we cannot assure you that the terms of any new relationship would be commercially acceptable to us, and as a result, any such termination could have a material adverse effect on our business, financial condition and results of operations.

Our agreements with Slawson, Kodiak and OGR and other agreements that we may enter into, present a number of challenges that could have a material adverse effect on our business, financial condition and results of operations.

Our agreements with Slawson, Kodiak and OGR represent a significant portion of our business in the near future. In addition, as part of our business strategy, we plan to enter into other similar transactions, some of which may be material. These transactions typically involve a number of risks and present financial, managerial and operational challenges, including the existence of unknown potential disputes, liabilities or contingencies that arise after entering into these arrangements related to the counterparties to such arrangements. We could experience financial or other setbacks if such transactions encounter unanticipated problems due to challenges, including problems related to execution or integration. Any of these risks could reduce our revenues or increase our expenses, which could adversely affect our business, financial condition or results of operations.

We depend on successful exploration, development and acquisitions to develop any future reserves and grow production and revenue in the future.

Acquisitions of oil and natural gas acreage, reserves and assets are typically based on engineering and economic assessments made by independent engineers and our own assessments. These assessments will include a series of assumptions regarding such factors as recoverability and marketability of oil and natural gas, future prices of oil and natural gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. In particular, the prices of and markets for oil and natural gas products may change from those anticipated at the time of making such assessment. In addition, all such assessments involve a measure of geologic and engineering uncertainty that could result in lower production and reserves than anticipated. Initial assessments of acquisitions may be based on reports by a firm of independent engineers that are not the same as the firm that we have used. Because each firm may have different evaluation methods and approaches, these initial assessments may differ significantly from the assessments of the firm used by us.

Properties we acquire may be in an unexpected condition and may subject us to increased costs and liabilities, including environmental liabilities. Although we review acquired properties prior to acquisition in a manner consistent with industry practices, such reviews are not capable of identifying all potential conditions. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties or properties with known adverse conditions and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems or permit a buyer to become sufficiently familiar with the properties to assess fully their condition or any deficiencies. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. As a result, we may not acquire good title to some of our acquired properties and we may assume unknown liabilities that could have a material adverse effect on our business, financial condition and results of operations.

We may have difficulty managing growth in our business, which could adversely affect our business plan, financial condition and results of operations.

Growth in accordance with our business plan, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on these resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

Substantially all of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could have a material adverse effect on our future oil and natural gas reserves and production and, therefore, our future cash flow and income.

Substantially all of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. We intend to develop our leasehold acreage by funding our exploration, exploitation and development activities. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

We may be unable to successfully acquire additional leasehold interests or other oil and natural gas properties, which may inhibit our ability to grow our production.

Acquisitions of leasehold interests or other oil and natural gas properties have been an important element of our business, and we will continue to pursue acquisitions in the future. In the last several years, we have pursued and consummated leasehold or other property acquisitions that have provided us opportunities to expand our acreage position and, to a lesser extent, grow our production. Although we regularly engage in discussions and submit proposals regarding leasehold interests or other properties, suitable acquisitions may not be available in the future on reasonable terms.

As most of our properties are in the exploration stage, we cannot assure you that we will establish commercial discoveries on our properties.

Exploration for economically recoverable reserves of oil and natural gas is subject to a number of risks. Few properties that are explored are ultimately developed into producing oil and/or natural gas wells. Most of our properties are only in the exploration stage and we have only limited revenues from operations. While we do have a limited amount of production of natural gas, we may not establish commercial discoveries on any of our properties. Failure to do so would have a material adverse effect on our business, financial condition and results of operations.

We have a limited operating history in the Bakken Shale and Three Forks formations in North Dakota and if we are not successful in continuing to grow our business, then we may have to scale back or even cease our ongoing business operations.

We have a limited operating history in the Bakken Shale and Three Forks formations in North Dakota. Our success is significantly dependent on a successful acquisition, drilling, completion and production program. Our operations in the Bakken Shale and Three Forks formations will be subject to all the risks inherent in the establishment of a developing enterprise and the uncertainties arising from the absence of a significant operating history. We may be unable to locate recoverable reserves or operate on a profitable basis. We are in the early stage of the exploration and development phase of our plan and potential investors should be aware of the difficulties normally encountered by enterprises in this stage. If our business plan is not successful and we are not able to operate profitably, investors may lose some or all of their investment.

Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.

We follow the full cost method of accounting for oil and natural gas properties. Accordingly, all costs associated with the acquisition, exploration and development of oil and natural gas properties, including costs of undeveloped leasehold, geological and geophysical expenses, dry holes, leasehold equipment and legal due diligence costs directly related to acquisition, exploration and development activities, are capitalized. Capitalized costs of oil and natural gas properties also include estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. The capitalized costs plus future development and dismantlement costs are depleted and charged to operations using the equivalent unit-of-production method based on proved oil and natural gas reserves as determined by our independent petroleum engineers. To the extent that such capitalized costs, net of depreciation and amortization, exceed the present value of estimated future net revenues, discounted at 10%, from proved oil and natural gas reserves, after income tax effects, such excess costs are charged to operations, which may have a material adverse effect on our business, financial condition and results of operations. Once incurred, a write down of oil and natural gas properties is not reversible at a later date, even if oil or natural gas prices increase.

We cannot control the activities on the properties we do not operate and are unable to ensure their proper operation and profitability.

We currently do not operate substantially all of the properties in which we have an interest, including all of our acreage in the Bakken Shale and Three Forks formations; however, we currently control and intend to operate 10% to 15% of our acreage. As a result, we have limited ability to exercise influence over, and control the risks associated with, operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology.

Our lack of diversification will increase the risk of an investment in us.

Our current business focus is on the oil and natural gas industry in a limited number of properties, primarily in North Dakota. Larger companies have the ability to manage their risk by diversification. However, we currently lack diversification, in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate, such as the Bakken Shale and Three Forks formations, than we would if our business were more diversified, increasing our risk profile.

Because we have a small asset base and have limited access to additional capital, we may have to limit our exploration activity, which may result in a loss of investment.

We have a small asset base and limited access to additional capital. Due to our brief operating history and historical operating losses, our operations have not been a source of liquidity and we expect to raise additional capital through equity financings. We presently do not have any available credit or bank financing sources of liquidity. We expect significant capital expenditures during 2011 for land acquisitions and drilling programs on our U.S. oil shale program and for overhead and working capital purposes. We cannot assure you that we will be successful in obtaining additional funding. In that event, we may not be able to complete our planned exploration programs. If additional financing is not available or is not available on acceptable terms, we will have to curtail our operations and investors may lose their investment.

If we are unable to raise additional funds or secure a new joint operating partner in the Windsor Block, we may be required to surrender the Windsor Block lease.

On April 15, 2009, we entered into a 10-year production lease for approximately 474,625 gross acres (approximately 412,924 net acres) of land. In April 2011, we are required to provide a technical report and the Government of Nova Scotia may request the surrender of certain lands they deem not adequately evaluated. In the future, we may not meet the Government of Nova Scotia’s drilling and production requirements and therefore we may be required to surrender certain or all lands in this area in the future. At the end of the fifth year of the lease, areas of the land block not adequately drilled or otherwise evaluated may be subject to surrender. Since April 15, 2009, we have completed three exploration wells and acquired seismic data towards the production lease commitments. There is a risk that our joint venture partner in the Windsor Block will not be able to pay for their portion (13%) of the well costs, which could also slow down or stop exploration on the Windsor Block.

We will have to raise additional funds or secure a new joint operating partner in the Windsor Block to complete the exploration and development phase of our Windsor Block programs and we cannot assure you that we will be able to do so. There is a risk that we may not obtain the necessary additional funds or a new partner to continue operations and to determine the existence, discovery and successful exploitation of economically recoverable reserves and the attainment of profitable operations on our Windsor Block. If we do not obtain additional funds or secure a new partner, we may be required to surrender the lease.

Under U.S. generally accepted accounting standards, we review our unevaluated properties at the end of each quarter to determine whether portions of the costs should be reclassified to the full cost pool, subject to amortization and potentially written off as part of the ceiling test. The factors discussed above increase the risk that the carrying value of the Windsor Block could be considered impaired under U.S. generally accepted accounting standards and the impairment charge could be significant.

We face strong competition from other oil and natural gas companies.

We encounter competition from other oil and natural gas companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Our competitors include major oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our competitors have been engaged in the oil and natural gas business much longer than we have and possess substantially larger operating staffs and greater capital resources than us. These companies may be able to pay more for exploratory projects and productive oil and natural gas properties and may be able to 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 be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. Such competitors may also be in a better position to secure oilfield services and equipment on a timely basis or on more favorable terms. We may not be able to conduct our operations, evaluate and select suitable properties and consummate transactions successfully in this highly competitive environment.

Current global financial conditions have been characterized by increased volatility which could have a material adverse effect on our business, prospects, liquidity, financial condition and results of operations.

Current global financial conditions and recent market events have been characterized by increased volatility and the resulting tightening of the credit and capital markets has reduced the amount of available liquidity and overall economic activity. We cannot assure you that debt or equity financing, the ability to borrow funds or cash generated by operations will be available or sufficient to meet or satisfy our initiatives, objectives or requirements. Our inability to access sufficient amounts of capital on terms acceptable to us for our operations could have a material adverse effect on our business, prospects, liquidity, financial condition and results of operations.

The potential profitability of oil and natural gas properties depends upon factors beyond our control.

The potential profitability of oil and natural gas properties is dependent upon many factors beyond our control. For instance, world prices and markets for oil and natural 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. These changes and events may materially affect our financial performance. In addition, a productive well may become commercially unproductive in the event that water or other deleterious substances are encountered which impair or prevent the production of oil and/or natural gas from the well. In addition, production from any well may be unmarketable if it is impregnated with water or other deleterious substances. These factors cannot be accurately predicted and the combination of these factors may result in us not receiving an adequate return on invested capital.

Seasonal weather conditions and other factors could adversely affect our ability to conduct drilling activities.

Our operations could be adversely affected by weather conditions and wildlife restrictions on federal leases. In the Williston Basin, drilling and other oil and natural gas activities cannot be conducted as effectively during the winter months. Winter and severe weather conditions limit and may temporarily halt the ability to operate during such conditions. The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Also, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. These constraints and the resulting shortages or high costs could delay or temporarily halt our oil and natural gas operations and materially increase our operating and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

If we are unable to retain the services of Dr. Hill and Mr. Samuels, or if we are unable to successfully recruit qualified managerial and field personnel having experience in oil and natural gas exploration, we may not be able to continue our operations.

Our success depends to a significant extent upon the continued services of our directors and officers and, in particular, Peter Hill, our Chief Executive Officer, and Jonathan Samuels, our Chief Financial Officer. Loss of the services of Dr. Hill or Mr. Samuels could have a material adverse effect on our growth, revenues and prospective business. We have not and do not expect to obtain key man insurance on our management. In addition, in order to successfully implement and manage our business plan, we will be dependent upon, among other things, successfully recruiting qualified managerial and field personnel having experience in the oil and natural gas exploration business. Competition for qualified individuals is intense. We cannot assure you that we will be able to retain existing employees or that we will be able to find, attract and retain qualified personnel on acceptable terms.

The marketability of natural resources will be affected by numerous factors beyond our control.

The markets and prices for oil and natural gas depend on numerous factors beyond our control. These factors include demand for oil and natural gas, which fluctuate with changes in market and economic conditions, and other factors, including:

worldwide and domestic supplies of oil and natural gas;

actions taken by foreign oil and natural gas producing nations;

political conditions and events (including instability or armed conflict) in oil-producing or natural gas-producing regions;

the level of global and domestic oil and natural gas inventories;

the price and level of foreign imports;

the level of consumer demand;

the price and availability of alternative fuels;

the availability of pipeline or other takeaway capacity;

weather conditions;

terrorist activity;

domestic and foreign governmental regulations and taxes; and

the overall worldwide and domestic economic environment.

Significant declines in oil and natural gas prices for an extended period may have the following effects on our business:

adversely affect our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;

cause us to delay or postpone some of our capital projects;

reduce our revenues, operating income and cash flow; and

limit our access to sources of capital.

We may have difficulty distributing our oil and natural gas production, which could harm our financial condition.

In order to sell the oil and natural gas that we are able to produce from the Williston Basin and the Maritimes Basin, we may have to make arrangements for storage and distribution to the market. We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This situation could be exacerbated to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. These factors may affect our ability to explore and develop properties and to store and transport our oil and natural gas production, which may increase our expenses.

Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas in which we will operate or labor disputes may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.

Oil and natural gas operations are subject to comprehensive regulation which may cause substantial delays or require capital outlays in excess of those anticipated, causing an adverse effect on us.

Oil and natural gas operations are subject to federal, state, provincial 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 natural gas operations are also subject to federal, state, provincial 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 authorities are required for drilling operations to be conducted and no assurance can be given that such permits will be received. The failure or delay in obtaining the requisite approvals or permits may adversely affect our business, financial condition and results of operations.

Hydraulic fracturing, the process used for releasing oil and natural gas from shale rock, has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development.

Recently there has been some public concern over the hydraulic fracturing process with regards to shale gas formations in the United States and Eastern Canada. Most of these concerns have raised questions regarding the drilling fluids used in the fracturing process, their effect on fresh water aquifers, the use of water in connection with completion operations and the ability of such water to be recycled. Certain government and regulatory agencies in Canada, including the Province of Quebec, and the United States have begun investigating the potential risks associated with the hydraulic fracturing process.

The Environmental Protection Agency, or EPA, recently amended the Underground Injection Control, or UIC, provisions of the federal Safe Drinking Water Act (the “SDWA”) to exclude hydraulic fracturing from the definition of “underground injection.” However, the U.S. Senate and House of Representatives are currently considering bills entitled the Fracturing Responsibility and Awareness of Chemicals Act (the “FRAC Act”) to amend the SDWA to repeal this exemption. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities, which could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.

Hydraulic fracturing is the primary production method used to produce reserves located in the Bakken Shale and Three Forks formations. Depending on the legislation that may ultimately be enacted or the regulations that may be adopted at the federal, state and/or provincial levels, exploration and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements. Individually or collectively, such new legislation or regulation could lead to operational delays or increased operating costs and could result in additional burdens that could increase the costs and delay the development of unconventional oil and natural gas resources from shale formations which are not commercial without the use of hydraulic fracturing. This could have an adverse effect on our business, financial condition and results of operations.

In March of 2011 the environmental public hearings board of Quebec recommended, and the government agreed, that the rules for shale gas exploration and development would be delayed pending completion of a strategic environmental assessment. The strategic environmental assessment is expected to begin in June of 2011 and take up to two years to complete. It is unclear at this time whether, and under what circumstances hydraulic fracturing will be permitted in that Province. It is also unknown if any other Provinces, including Nova Scotia, will take a similar approach.

Exploration activities are subject to certain environmental regulations which may prevent or delay the commencement or continuance of our operations.

In general, our exploration activities are subject to certain federal, state, provincial and local laws and regulations relating to environmental quality and pollution control. Specifically, we are subject to legislation regarding emissions into the environment, water discharges and storage and disposition of hazardous wastes. These laws and regulations may require the acquisition of permits before drilling commences; restrict the types, quantities and concentration of various substances that can be released into the environment from drilling and production activities; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and impose substantial liabilities for pollution resulting from our operations. Such laws and regulations increase the costs of our exploration activities and may prevent or delay the commencement or continuance of a given operation. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state or provincial authorities. Such laws and regulations are frequently changed and we are unable to predict the ultimate cost of compliance.

With the introduction of the Kyoto Protocol, oil and natural gas producers may be required to reduce GHG emissions. This could result in, among other things, increased operating and capital expenditures for those producers. This could also make certain production of oil or natural gas by those producers uneconomic, resulting in reductions in such production. The Kyoto Protocol was ratified by the Government of Canada in December of 2002 and commits Canada to reducing its GHG emissions levels to 6% below 1990 “business-as-usual” levels by 2012. It officially came into force on February 16, 2005. Since that date the Government of Canada has indicated it will be unable to meet its Kyoto Protocol commitments. We are unable to predict the effect on our business, financial condition and results of operations of the ratification of the Kyoto Protocol by the Government of Canada or its subsequent position that Canada cannot meet its commitments thereunder.

The first commitment period under the Kyoto Protocol ends in 2012. Government leaders and representatives from approximately 170 countries met in Copenhagen, Denmark from December 7 through 18, 2009 (the “Copenhagen Conference”) to attempt to negotiate a successor to the Kyoto Protocol. The Copenhagen Conference resulted in a broad political consensus rather than a binding international treaty, or the Copenhagen Accord, that has not been endorsed by all participating countries. The Copenhagen Accord reinforces the commitment to reducing the emissions of GHGs contained in the Kyoto Protocol and promises funding to help developing countries mitigate and adapt to climate change. In response to the Copenhagen Accord, the Government of Canada indicated on January 29, 2010 that it will seek to achieve a 17% reduction in GHG emissions from its 2005 levels by 2020. We are unable to predict the effect that compliance with the Copenhagen Accord by the Government of Canada will have on our business, financial condition and results of operation.

Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for, or responding to, those effects.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. On November 30, 2010, the EPA issued a final rule requiring reporting of greenhouse gas emissions from the oil and natural gas industry. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, oil and natural gas operations could increase costs or could adversely affect demand for the oil and natural gas produced from our lands.

Also, on June 26, 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, or ACESA, which would establish an economy-wide cap-and-trade program to reduce United States emissions of GHGs including carbon dioxide and methane that may contribute to the warming of the Earth’s atmosphere and other climatic changes. If it becomes law, ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit GHGs into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and President Obama has indicated his support of legislation to reduce greenhouse gas emissions through an emission allowance system. Although it is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

The EPA has also promulgated regulations which (i) beginning in January 2011, phase in restrictions on GHG emissions from stationary sources and (ii) require collection, beginning in January 2011, and reporting, beginning in March 2012, of data on GHG emissions from certain sources. The EPA's jurisdictional ability to regulate GHG emissions is currently subject to challenge in both the courts and Congress. At this time, it is not possible to predict the ultimate outcome of these challenges.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change and as a result, this could have a material adverse effect on our business, financial condition and results of operations.

Exploratory drilling involves many risks and we may become liable for pollution or other liabilities which may have an adverse effect on our financial position and results of operations.

Drilling operations generally involve a high degree of risk. Hazards such as unusual or unexpected geological formations, power outages, labor disruptions, blow-outs, sour gas leakage, fire, inability to obtain suitable or adequate machinery, equipment or labor and other risks are involved. We may become subject to liability for pollution or hazards against which we cannot adequately insure or for which we may elect not to insure. Incurring any such liability may have a material adverse effect on our financial position and results of operations.

Any change in government regulation and/or administrative practices may have a negative impact on our ability to operate and on our profitability.

The laws, regulations, policies or current administrative practices of any government body, organization or regulatory agency in the United States or Canada or any other jurisdiction may be changed, applied or interpreted in a manner which will fundamentally alter our ability to carry on our 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.

Aboriginal claims could have an adverse effect on us and our operations.

Aboriginal peoples have claimed aboriginal title and rights to portions of Canada where we operate, including in the Province of Nova Scotia, where our Windsor Block acreage is located. We are not aware that any claims have been made in respect of our property and assets. However, if a claim arose and was successful, it could have an adverse effect on us and our business operations, financial conditions and prospects.

We do not plan to insure against all potential operating risks. We might incur substantial losses from, and be subject to substantial liability claims for, uninsured or underinsured risks related to our oil and natural gas operations.

We do not intend to insure against all risks. Our oil and natural gas exploration and production activities will be subject to hazards and risks associated with drilling for, producing and transporting oil and natural gas, and any of these risks can cause substantial losses resulting from:

environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

abnormally pressured formations;

mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

fires and explosions;

personal injuries and death;

regulatory investigations and penalties; and

natural disasters.

We might elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities arising from uninsured and underinsured events or in amounts in excess of existing insurance coverage could have a material adverse effect on our business, financial condition or results of operations.

No assurance can be given that defects in our title to oil and natural gas interests do not exist.

Title to oil and natural gas interests is often not possible to determine without incurring substantial expense. An independent title review was completed with respect to certain of the oil and natural gas rights acquired by us and the interests in oil and natural gas rights owned by us. However, no assurance can be given that title defects do not exist. If a title defect does exist, it is possible that we may lose all or a portion of the properties to which the title defect relates. Our actual interest in certain properties may therefore vary from our records.

We are subject to the requirements of Section 404(a) of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404(a) or if the costs related to compliance are significant, our profitability, stock price, financial condition and results of operations could be materially adversely affected.

We are required to comply with the provisions of Section 404(a) of the Sarbanes-Oxley Act of 2002. Section 404(a) requires that we document and test our internal controls over financial reporting and issue management’s assessment of our internal controls over financial reporting.

We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404(a) of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations, our profitability, stock price, financial condition and results of operations could be materially adversely affected.

We cannot be certain at this time that we will identify any material weaknesses in our internal controls over financial reporting. If we fail to comply with the requirements of Section 404(a) or if we identify and report any additional material weaknesses, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, material weaknesses in the effectiveness of our internal controls over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, financial condition and results of operations.

Our Canadian operations subject us to currency exchange rate risk, which could cause our financial condition and results of operations to fluctuate significantly from period to period.

A portion of our revenues are derived from our Canadian activities and operations. As a result, we translate the financial condition and results of operations of our Canadian operations into U.S. dollars. Therefore, our reported financial condition and results of operations are subject to changes in the exchange relationship between the two currencies. For example, as the relationship of the Canadian dollar strengthens against the U.S. dollar, our revenue denominated in Canadian dollars is favorably affected and conversely our expenses denominated in Canadian dollars are unfavorably affected. Monetary assets and liabilities denominated in foreign currencies are translated into U.S. dollars at rates of exchange in effect at the balance sheet date and gains and losses are recorded in earnings. Non-monetary assets, liabilities and items recorded in income arising from transactions denominated in foreign currencies are translated at rates of exchange in effect at the date of the transaction. Our foreign currency transactions are primarily undertaken in Canadian dollars. We have not, to the date of the consolidated financial statements, entered into derivative instruments to offset the impact of foreign currency fluctuations.

Risks Relating to Our Common Stock

The market price for our common stock may be highly volatile.

The market price for our common stock may be highly volatile and could be subject to wide fluctuations. Some of the factors that could negatively affect such share price include:

actual or anticipated fluctuations in our quarterly results of operations;

liquidity;

sales of common stock by our stockholders;

changes in oil and natural gas prices;

changes in our cash flow from operations or earnings estimates;

publication of research reports about us or the oil and natural gas exploration and production industry generally;

increases in market interest rates which may increase our cost of capital;

changes in applicable laws or regulations, court rulings and enforcement and legal actions;

changes in market valuations of similar companies;

adverse market reaction to any indebtedness we incur in the future;

additions or departures of key management personnel;

actions by our stockholders;

commencement of or involvement in litigation;

news reports relating to trends, concerns, technological or competitive developments, regulatory changes and other related issues in our industry;

speculation in the press or investment community regarding our business;

inability to list our common stock on a national securities exchange;

general market and economic conditions; and

domestic and international economic, legal and regulatory factors unrelated to our performance.

Financial markets have recently experienced significant price and volume fluctuations that have affected the market prices of equity securities of companies and that have, in many cases, been unrelated to the operating performance, underlying asset values or prospects of such companies. Accordingly, the market price of our common stock may decline even if our results of operations, underlying asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause decreases in asset values that are deemed to be other than temporary.

Limited trading volume in our common stock may contribute to price volatility.

As a relatively small company with a limited market capitalization, even if our shares are more widely disseminated, we are uncertain as to whether a more active trading market in our common stock will develop. As a result, relatively small trades may have a significant impact on the price of our common stock. In addition, because of the limited trading volume in our common stock and the price volatility of our common stock, you may be unable to sell your shares of common stock when you desire or at the price you desire. The inability to sell your shares in a declining market because of such illiquidity or at a price you desire may substantially increase your risk of loss.

In the past, we have not paid dividends on our common stock and do not anticipate paying dividends on our common stock in the foreseeable future.

In the past, we have not paid dividends on our common stock and do not expect to declare or pay any cash or other dividends in the foreseeable future on our common stock, as we intend to use cash flow generated by operations to develop our business. Any future determination to pay cash dividends will be at the discretion of our board of directors and will be dependent upon our financial condition, results of operations, capital requirements and such other factors as our board of directors deems relevant.

Future sales or other issuances of our common stock could depress the market for our common stock.

We may seek to raise additional funds through one or more public offerings of our common stock, in amounts and at prices and terms determined at the time of the offering. We may also use our common stock as consideration to make acquisitions, including to acquire additional leasehold interests. Any issuances of large quantities of our common stock could reduce the price of our common stock, and, to the extent that we issue equity securities to fund our business plan, our existing stockholders’ ownership will be diluted.

Issuances, or the availability for sale, of substantial amounts of our common stock could adversely affect the value of our common stock.

No prediction can be made as to the effect, if any, that future issuances of our common stock, or the availability of common stock for future sales, will have on the market price of our common stock. Sales of substantial amounts of our common stock in the public market and the availability of shares for future sale, including by one or more of our significant stockholders or shares of our common stock issuable upon exercise of outstanding options to acquire shares of our common stock, could adversely affect the prevailing market price of our common stock. This in turn would adversely affect the fair value of the common stock and could impair our future ability to raise capital through an offering of our equity securities.

Anti-takeover provisions could make a third party acquisition of us difficult.

We are subject to the anti-takeover law of the Nevada Revised Statutes, commonly known as the Business Combinations Act. This law provides that specified persons who, together with affiliates and associates, own, or within three years did own, 10% or more of the outstanding voting stock of a corporation cannot engage in specified business combinations with us for a period of three years after the date on which the person became an interested stockholder. The law defines the term “business combination” to encompass a wide variety of transactions with or caused by an interested stockholder, including mergers, asset sales and other transactions in which the interested stockholder receives or could receive a benefit on other than a pro rata basis with other stockholders. This provision has an anti-takeover effect for transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for the shares of our common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

All of our oil and natural gas properties are located in the United States and Canada. We are currently participating in oil and natural gas exploration activities in the States of North Dakota and Montana and the Province of Nova Scotia. The Bakken Shale play in the Williston Basin is our core area of operations in the United States. Our other project is a conventional and shale natural gas opportunity located in the Maritimes Basin in the Province of Nova Scotia. We intend to execute an operating plan in order to realize the full value of the land base that has been established in the Maritimes Basin in the Province of Nova Scotia. Our remaining two project areas (Rocky Mountain and Barnett Shale) are currently designated as non-core due to our desire to focus our limited manpower resources on one core and one secondary project.

United States

Williston Basin

We own operated and non-operated leasehold positions in the Williston Basin. We anticipate commencing our first operated well in the second half of 2011. The operations of our non-operated leasehold positions are primarily conducted through agreements with major operators in the Williston Basin, including Slawson, Kodiak, EOG, Brigham Exploration Company, Marathon Oil Corporation, Continental Resources, Inc., XTO Energy Inc., Whiting Petroleum Corporation, Hess Corporation and others. These companies are experienced operators in the development of the Bakken Shale and Three Forks formations. Upon the closing of our recently announced EOG Purchase and Slawson Purchase, we believe that we will have the right to operate approximately 7,000 net acres, or over 20% of our approximately 30,000 net acres. We continue to build our technical and financial team and, in addition to our experienced geological, land, brokerage and title teams, we expect to have an experienced operating team in place over the next several months. We expect to have an experienced operating team in place over the next several months. Our primary areas of operation are focused in the Rough Rider area of McKenzie, Williams and Stark Counties in North Dakota and Roosevelt County, Montana.

As of April 1, 2011, we have participated in the drilling of 14 gross non-operated wells, including 3 producing wells and 11 wells in various stages of drilling and completion. In addition, we have 12 gross non-operated wells set to spud in the next 30 days and an additional 34 gross non-operated wells already permitted to drill. Over the next 12 months, we plan to participate in a minimum of 75 gross (10.6 net) wells, including as many as 2 gross wells that we will operate. With an average drilling and completion cost of approximately $8 million per well, we have budgeted a range of anticipated drilling capital costs of $80 million to $90 million over this period.

Canada

Maritimes Basin

We have an 87% working interest in approximately 474,625 gross acres (approximately 412,924 net acres) in the Windsor Sub-Basin of the Maritimes Basin. We continue to seek a partner for the drilling of an onshore well in the development of the Windsor Block. In moving forward with the Windsor Block, we intend to consider a range of options pursuant to our existing production lease.

Non-Core Properties

In fiscal year 2011, there was no exploration activity on our non-producing and undeveloped land positions and we do not intend to participate in any exploration activity for these projects in fiscal year 2012. We have recently divested most of our non-core properties. During fiscal year 2011, we sold an existing wellbore and associated acreage in Alberta for approximately $977,000.

Our remaining non-core producing properties include 4,427 non-operated acres in the Rocky Mountains and 2,640 net acres in the Alberta Deep Basin of Canada.

Drilling and Other Exploratory and Development Activities

As of January 31, 2011, we had 3 gross productive wells and .43 net productive wells which were all located in North Dakota. A net well represents our percentage ownership of a gross well. Our count of productive wells does not include wells that were awaiting completion, in the process of completion or awaiting flowback subsequent to fracture stimulation. We have not participated in any wells solely targeting natural gas reserves. We have classified all wells drilled to-date targeting the Bakken and Three Forks formations as development wells, meaning we have not drilled any exploratory wells in North Dakota.

Oil and Natural Gas Reserves

Net Reserves of Crude Oil and Natural Gas at Fiscal Year-End 2011

MHA Petroleum Consultants (“MHA”), an independent petroleum engineering firm, determined our estimated proved oil and natural gas reserves as of January 31, 2011 and determined the projected future cash flows from those proved reserves and the present value, discounted at 10% per annum, of those future cash flows (“PV-10 Value”). Those estimates are summarized in the following table and are further discussed in the MHA report, Exhibit 99.01 to this annual report:

Proved developed oil reserves ( MBbls)		164.8
Proved developed non-producing oil reserves (MBbls)		49.4
Proved Undeveloped Oil Reserves (MBbls)		1,021.3
Total proved oil reserves (MBbls)		1,235.5

Present value of estimated future net revenues after income taxes, discounted at 10% (1) (2)	$	13,156,000

(1)

We calculated the present value of estimated future net revenues as of January 31, 2011 using the 12 month arithmetic average first of month price from February 2010 through January 2011. The average resulting price used as of January 31, 2011was $68.76 per barrel of oil.

(2)

The Present Value of Estimated Future Net Revenues After Income Taxes, Discounted at 10%, is referred to as the "Standardized Measure." There is a $2.627 million tax effect reducing the present value of estimated future net revenues. See Information Regarding Proved Oil and Natural Gas Reserves (Unaudited) included in our audited financial statements for the year ended January 31, 2011.

At January 31, 2010, our proved reserve estimates and future cash flows discounted at 10% were valued at an inconsequential amount, therefore we did not obtain a reserve report at January 31, 2010.

In estimating reserves, MHA used the SEC definition of proved reserves. Projected future cash flows are based on economic and operating conditions as of January 31, 2011 and future oil and natural gas prices used in the projection reflect a simple average of prices for the well or property on the first day of the twelve months in the fiscal year.

Volumes of reserves actually recovered and cash flows actually received from actual production may differ significantly from the proved reserve estimates and the related projected cash flows, respectively. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment and the existence of development plans. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Internal Controls Over Reserve Estimation

Our year-end reserve report is prepared by MHA based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geoscience and engineering data, and other information we provide to them. This information is reviewed by knowledgeable members of our Company to ensure accuracy and completeness of the data prior to submission to MHA. Upon analysis and evaluation of data provided, MHA issues a preliminary report of our reserves which is reviewed by our Subsurface Manager, our Chief Financial Officer and our Chief Executive Officer for completeness of the data presented and reasonableness of the results obtained. Once all questions have been addressed, MHA issues the final report, reflecting their conclusions.

Developed and Undeveloped Acreage:

The table below presents the approximate gross acres and our approximate net acres as to our interests in oil and natural gas mineral leases as of January 31, 2011:

	Developed Acres				Undeveloped Acres				Total Acres
Project	Gross		Net		Gross		Net		Gross		Net
Williston Basin, ND		6,000		1,500		50,000		11,600		56,000		13,100
Maritimes Basin, Canada		-		-		474,625		412,924		474,625		412,924

Acreage Totals		6,000		1,500		524,625		424,524		530,625		426,024

As a non-operator, we are subject to lease expirations if an operator does not commence the development of operations within the agreed terms of our leases. All of our leases for undeveloped acreage summarized in the table below will expire at the end of their respective primary terms unless we renew the existing leases, establish commercial production from the acreage or some other “savings clause” is exercised. We expect to establish production from most of our acreage prior to expiration of the applicable lease terms however, there can be no guarantee we can do so. The approximate expiration of our net acres which are subject to expire between fiscal year 2012 and 2016 and thereafter are set forth below:

Year Ended	Acres
January 31, 2012		1,123
January 31, 2013		1,317
January 31, 2014		2,135
January 31, 2015		2,007
January 31, 2016 and thereafter		1,247
Total		7,829

Costs Incurred and Capitalized Costs:

The costs incurred in oil and natural gas acquisition, exploration and development activities in fiscal year 2011 follow:

Property acquisition	$	13,654,462
Development		4,575,424
Exploration		-

Total	$	18,229,886

The following table summarizes capitalized costs excluded from amortization as of January 31, 2011 and 2010, respectively, by country. We anticipate these excluded costs will be included in the amortization computation over the next five years. We are unable to predict the future impact on amortization rates.

	January 31,
	2011		2010
United States	$	11,206,667	$	-
Canada	$	4,000,000	$	18,783,375
Total	$	15,206,667	$	18,783,375

Sales Volumes and Prices and Production Costs:

Our oil and natural gas production and proved reserves are located in the United States and Canada. The table below summarizes our oil and natural gas production, average sales price and average production costs per barrel of oil equivalent for the two most recent fiscal years, in total. Our production is attributable to our direct interests in producing properties after deducting royalty interests and similar interests. The lease operating expenses shown below relate to our net production.

	Fiscal Year Ended January 31,
	2011		2010
Net Sales Volume
Natural Gas (Mcf)		23,689		40,744
Oil (Bbls)		6,174		-
Total equivalent barrels (6 mcf = 1 boe)		10,122		6,791
Average Sales Price Per Unit
Natural Gas (per Mcf)	$	4.46	$	3.75
Oil (per Bbl)	$	74.20	$	-
Weighted average (per Boe)	$	55.69	$	22.52
Lease Operating Expenses (per Boe)	$	14.29	$	14.12

Office Facilities

We maintain our principal office at 1660 Wynkoop St., Suite 900, Denver, Colorado, 80202. The lease for this location is effective on April 18, 2011. Prior to April 18, 2011, our principal office was located at 1625 Broadway, Suite 780, Denver, Colorado, 80202. Our telephone number is (303) 260-7125 and our facsimile number is (303) 260-5080. We also maintain an office in Calgary, Alberta, Canada. Our current office space consists of approximately 2,370 square feet in our 1625 Broadway office, 9,144 square feet in our 1660 Wynkoop office and 2,475 square feet in our Calgary office. The 1625 Broadway and Calgary leases run until September 2013. The 1660 Wynkoop lease begins on April 18, 2011 and runs through July 2015. We will be closing the 1625 Broadway office and the Calgary office after we have transitioned to the office at 1660 Wynkoop. As of January 31, 2011, our obligation to provide aggregate annual rental payments was as follows:

Fiscal year ending January 31,	Annual Rental Amount
2012	$	71,316
2013	$	72,501
2014	$	48,861

ITEM 3. LEGAL PROCEEDINGS

ITEM 4. RESERVED

PART II

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

MARKET INFORMATION

On November 5, 2010, our common stock began trading on the NYSE Amex LLC (“NYSE Amex”) under the symbol "TPLM." In connection with its listing on the NYSE Amex, the Company's common stock ceased trading on the OTC Bulletin Board. The Company's shares of common stock were also delisted from the TSX Venture Exchange effective April 1, 2011. The Company also underwent a 1-for-10 reverse stock split which became effective for trading purposes as of November 5, 2010. The table below sets forth the high and low sales price for our common stock in each quarter of the last two fiscal years (adjusted for the 10-for-1 stock split).

	Fiscal Year 2010
	High		Low
February 1, 2009 to April 30, 2009	$	2.50	$	1.10
May 1, 2009 to July 31, 2009	$	2.10	$	1.50
August 1, 2009 to October 31, 2009	$	1.80	$	0.70
November 1, 2009 to January 31, 2010	$	4.00	$	0.80

	Fiscal Year 2011
	High		Low
February 1, 2010 to April 30, 2010	$	9.20	$	0.90
May 1, 2010 to July 31, 2010	$	8.00	$	4.00
August 1, 2010 to October 31, 2010	$	6.00	$	4.50
November 1, 2010 to November 3, 2010	$	7.10	$	5.50
November 4, 2010 to January 31, 2011	$	8.55	$	5.50
February 1, 2011 to April 1, 2011	$	9.73	$	6.70

HOLDERS

As of April 1, 2011, we had approximately 45 registered holders of our common stock. The number of record holders was determined from the records of our transfer agent and does not include beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, and registered clearing agencies. The transfer agent of our common stock is Continental Stock Transfer & Trust Company, 17 Battery Place, New York, New York 10004.

DIVIDENDS

We do not anticipate paying any cash dividends to stockholders in the foreseeable future. Any future determination to pay cash dividends will be at the discretion of our board of directors and will be dependent upon our financial condition, results of operations, capital requirements, and such other factors as our board of directors deem relevant.

RECENT SALE OF UNREGISTERED SECURITIES AND EQUITY PURCHASES BY THE COMPANY

On August 6, 2010, we completed a private placement with certain accredited investors, pursuant to which such investors purchased an aggregate of 2,044,187 shares of our common stock at a purchase price of $0.43 per share (without giving effect to the reverse stock split), yielding us aggregate gross proceeds of approximately $880,000 and net proceeds of approximately $836,000. Our common stock was offered and sold in reliance on the private placement exemption from registration under Section 4(2) of the Securities Act, and Regulation D promulgated thereunder, or Regulation D. We relied on this exemption based on applicable facts, including that (i) the offers and sales were made to a limited number of persons, all of whom represented that they were “accredited investors” (as such term is defined in Regulation D), (ii) no general solicitation or advertising was used in connection with the offering and sale of our common stock and (iii) the investors’ represented that they were acquiring our common stock for investment only. Johnson Rice & Company L.L.C. served as lead placement agent for the private placement.

On March 16, 2010, we completed a private placement with certain accredited investors, pursuant to which such investors purchased an aggregate of 27,993,939 shares of our common stock at a purchase price of $0.33 per share (without giving effect to the reverse stock split), yielding us aggregate gross proceeds of approximately $9,238,000 and net proceeds of approximately $8,300,000. Our common stock was offered and sold in reliance on the private placement exemption from registration under Section 4(2) of the Securities Act and Regulation D. We relied on this exemption based on applicable facts, including that (i) the offers and sales were made to a limited number of persons, all of whom represented that they were “accredited investors” (as such term is defined in Regulation D), (ii) no general solicitation or advertising was used in connection with the offering and sale of our common stock and (iii) the investors’ represented that they were acquiring our common stock for investment only. Johnson Rice & Company L.L.C. served as lead placement agent for the private placement.

Equity Compensation Plan Information

The following table sets forth certain information about the common stock that may be issued upon the exercise of options under the equity compensation plans as of January 31, 2011.

Plan Category	Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Shares Reflected in the First Column)
Equity compensation plans approved by stockholders		343,333	$	1.60		1,909,225
Equity compensation plans not approved by stockholders		509,636	$	-		2,990,364
Total		852,969	$	1.50		4,899,589

ITEM 6. SELECTED FINANCIAL DATA

Not required under Regulation S-K for “smaller reporting companies.”

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This Management's Discussion and Analysis of Financial Condition and Results of Operations includes a number of forward-looking statements that reflect our management's current views with respect to future events and financial performance. You can identify these statements by forward-looking words such as “may,” “will,” “expect,” “anticipate,” “believe,” “estimate” and “continue,” or similar words. Those statements include statements regarding the intent, belief or current expectations of us and members of our management team as well as the assumptions on which such statements are based. Prospective investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve risk and uncertainties, and that actual results may differ materially from those contemplated by such forward-looking statements.

Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC. The following Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Company should be read in conjunction with the Consolidated Financial Statements and notes related thereto included in this annual report on Form 10-K. Important factors currently known to our management could cause actual results to differ materially from those in forward-looking statements. We undertake no obligation to update or revise forward-looking statements to reflect changed assumptions, the occurrence of unanticipated events or changes in the future operating results over time. We believe that our assumptions are based upon reasonable data derived from and known about our business and operations. No assurances are made that actual results of operations or the results of our future activities will not differ materially from our assumptions. Factors that could cause differences include, but are not limited to, expected market demand for our products, fluctuations in pricing for materials, and competition.

Overview

Plan of Operations

We own operated and non-operated leasehold positions in the Williston Basin. We anticipate commencing our first operated well in the second half of 2011. The operations of our non-operated leasehold positions are primarily conducted through agreements with major operators in the Williston Basin, including Slawson, Kodiak, EOG, Brigham Exploration Company, Marathon Oil Corporation, Continental Resources, Inc., XTO Energy Inc., Whiting Petroleum Corporation, Hess Corporation and others. These companies are experienced operators in the development of the Bakken Shale and Three Forks formations. Upon the closing of our recently announced EOG Purchase and Slawson Purchase, we believe that we will have the right to operate approximately 7,000 net acres, or over 20% of our approximately 30,000 net acres. We continue to build our technical and financial team and, in addition to our experienced geological, land, brokerage and title teams, we expect to have an experienced operating team in place over the next several months. Our primary areas of operation are focused in the Rough Rider area of McKenzie, Williams and Stark Counties in North Dakota and Roosevelt County, Montana.

As of April 1, 2011, we have participated in the drilling of 14 gross non-operated wells, including 3 producing wells and 11 wells in various stages of drilling and completion. In addition, we have 10 gross non-operated wells set to spud in the next 30 days and an additional 34 gross non-operated wells already permitted to drill. Over the next 12 months, we plan to participate in a minimum of 75 gross (10.6 net) wells, including as many as 2 gross wells that we will operate. With an average drilling and completion cost of approximately $8 million per well, we have budgeted a range of anticipated drilling capital costs of $80 million to $90 million over this period.

Maritimes Basin

We have an 87% working interest in approximately 474,625 gross acres (approximately 412,924 net acres) in the Windsor Sub-Basin of the Maritimes Basin located in the Windsor Block. We are currently seeking partners to participate in the further evaluation of the potential of the Windsor Block.

Non-Core Producing Properties

Our producing well in the Alberta Deep Basin of Canada was sold in May 2010 along with the associated undeveloped acreage for $977,000 in cash. We also have production from three low working interest shale natural gas wells in the Barnett Shale trend of the Fort Worth Basin of Texas, although we consider the production volumes to be immaterial.

Non-Core Undeveloped Properties

We have 4,427 non-operated net acres in the Rocky Mountains and 2,640 net acres in the Alberta Deep Basin of Canada. In fiscal 2011, there was no exploration activity on these undeveloped land positions and there continues to be no exploration activity planned for these projects in fiscal year 2012.

Results of operations for the year ended January 31, 2011 compared to the year ended January 31, 2010

For the fiscal year ended January 31, 2011, we recorded a net loss attributable to common stockholders of $20,277,197, ($1.63 per common share, basic and diluted) as compared to a net loss attributable to common stockholders of $2,140,101 ($0.31 per common share, basic and diluted) for the fiscal year ended January 31, 2010.

Oil and Natural Gas Operations

For fiscal year 2011, we had total oil and natural gas revenues of $563,670 compared with $152,938 for fiscal year 2010. Oil and natural gas sales and production costs for each year are summarized in the table that follows. Oil sales volumes and revenues increased in fiscal year 2011 compared to 2010 due to production from wells in the Bakken formation that were drilled or acquired in fiscal year 2011. Natural gas sales volume and revenues decreased in fiscal year 2011 compared to 2010 because we sold all of our natural gas producing properties in fiscal year 2011.

	Fiscal Year Ended January 31,
	2011			2010
Oil sold (barrels)		6,174			-
Average oil price	$	74.20		$	-
Oil revenue	$	458,111		$	-
Gas and NGL's sold (mcf)		23,689			40,744
Average gas price	$	4.46		$	3.75
Gas revenue	$	105,559		$	152,938
Total oil and gas revenues	$	563,670		$	152,938
Less royalties		26,907			21,693
Less lease operating expenses		144,606			95,852
Less oil and gas amortization expense		96,000			38,781
Less accretion of asset retirement obligations		250,319			150,007
Less impairments of oil and gas properties		14,917,356			-
Plus gain on sale of oil and gas properties		1,006,294			1,266,294
Income (loss) from oil and gas operations	$	(13,865,224	)	$	1,112,899
Other income		59,373			6,260
Plus foreign exchange gain		35,615			753,950
Less depreciation of furniture and equipment		39,296			26,198
Less general and administrative expenses		6,467,665			3,987,012
Income (loss) from operations	$	(20,277,197	)	$	(2,140,101	)
Total barrels of oil equivalent (“boe”) sold		10,122			6,791
Oil and gas revenue per boe sold	$	55.69		$	22.52
Lease operating expense per boe sold	$	14.29		$	14.12
Amortization expense per boe sold	$	9.48		$	5.71

Impairment of Oil and Natural Gas Properties

During the fiscal year 2011, we recorded impairment cost of $14,917,356 in connection with our property in the Maritimes Basin of Nova Scotia. The Company assesses all unproved property for possible impairment annually or upon a triggering event. The assessment includes consideration of, among others, intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, and the assignment of proved reserves. The circumstances that contributed to the impairment included the lack of immediate funding allocated to the project, the belief that the carrying amounts may not be recoverable and the lack of proved reserves attributable to the property.

General and Administrative Expenses

In fiscal year 2011, general and administrative expenses of $6,468,000 exceeded that of $3,987,000 or 62% in fiscal year 2010 due primarily to the following: (i) an increase in stock-based compensation of $272,000 due to the granting of restricted stock to officers and directors in fiscal year 2011, (ii) an increase of $229,000 in travel expense in connection with investor relations, (iii) an increase in consulting and legal fees of $572,000, (iv) an increase in salaries, wages and benefits of $1,073,000 due to cash bonuses paid to certain officers and employees for service in fiscal year 2011 and (v) an increase of $335,000 in miscellaneous office costs associated with establishing an office in the US. The following table summarizes general and administrative expenses for the fiscal years ending 2011 and 2010:

	2011		2010
Salaries, benefits and consulting fees	$	2,916,982	$	1,844,226
Office costs		1,355,007		844,605
Professional fees		817,369		245,235
Public company costs		311,996		303,809
Operating overhead recoveries		-		(45,224	)
Stock-based compensation		1,066,311		794,361
Total G&A	$	6,467,665	$	3,987,012

Income Taxes

Our 2011 provision for deferred income taxes is zero due to recognition of 100% valuation allowances against our net deferred tax assets of $21,332,804 and $15,466,223 at January 31, 2011 and 2010, respectively. If facts and circumstances indicate that all or a portion of the deferred tax asset is more likely than not to be realized in the future, then the valuation allowance would be correspondingly reduced and a deferred tax benefit recognized.

Liquidity and Capital Resources

Our primary cash requirements are for exploration, development and acquisition of oil and natural gas properties. We currently anticipate capital requirements for fiscal year 2012 to be approximately $80 to $90 million. We expect to be able to fund these expenditures as well as other commitments and working capital requirements using existing capital as well as with additional capital raised through the sale of debt or equity. In March 2011 we raised $134.3 million (net of underwriting discounts and commissions and estimated offering expenses) through the sale of our equity securities. We may expand or reduce our capital expenditures depending on, among other things, the results of future wells, and our available capital.

As of January 31, 2011, we had cash of $57,773,269 consisting primarily of cash held in bank accounts with Wells Fargo, Royal Bank of Canada and JP Morgan Chase as compared to $4,878,601 at January 31, 2010. Working capital was $53,607,065 as of January 31, 2011 as compared to $4,841,074 at January 31, 2010. We may generate additional capital to fund increases in capital expenditures through additional sales of our securities, or debt financing. We may not be able to obtain equity or debt financing on terms favorable to us, or at all. Our ability to continue to acquire property and grow our oil and natural gas reserves and cash flow would be severely impacted if we are unable to obtain sufficient capital.

Net Cash Used By Operating Activities

Cash flow used by operating activities was $3,567,810 and $2,099,940 for the fiscal years ended January 31, 2011 and 2010, respectively. The $1,467,870 increase in cash used in fiscal year 2011 compared with fiscal year 2010 is due primarily to an approximate $2.5 million increase in general and administrative expenses.

Net Cash Used By Investing Activities

In fiscal year 2011, investing activities used $16,099,012 in cash as compared to $2,192,365 used in fiscal year 2010. Cash used in investing activities increased primarily as a result of the acquisitions of oil and natural gas properties.

Net Cash Provided By Financing Activities

Our $72,534,207 in cash provided by financing activity was primarily a result of the sale of our equity securities during the year. In November 2010, we sold 12,420,000 shares of our common stock at $5.50 per share, providing net proceeds of approximately $63 million in cash after offering and issuance costs. In March 2010, we sold 2,799,394 shares at a price of $3.30 for net proceeds of approximately $8.5 million and in August 2010, we sold 204,419 shares at a price of $4.30 for net proceeds of approximately $856,000. During fiscal year 2011, we also received proceeds of $235,000 for the exercise of stock options.

Contractual Obligations as of January 31, 2011

The Company leases office facilities in Denver, Colorado and Calgary, Alberta, Canada under operating lease agreements that both expire in September 2013. The Company also leases office equipment under an operating lease that expires in 2014.

The following table shows the annual rentals per year for the life of the leases:

Fiscal year ending January 31,	Annual Rental Amount
2012	$	74,880
2013	$	76,065
2014	$	52,428

Off-Balance Sheet Arrangements

None.

Critical Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires us 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 reporting period. Actual results could differ from those estimates. We base our estimates and assumptions on current facts, historical experience and various other factors that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities and the accrual of costs and expenses that are not readily apparent from other sources. The actual results experienced by us may differ materially and adversely from our estimates. To the extent there are material differences between the estimates and the actual results, future results of operations will be affected.

Full Cost Accounting Method

We use the full cost method of accounting for our oil and natural gas properties. Under this method, all acquisition, exploration, development and estimated abandonment costs incurred for the purpose of acquiring and finding oil and natural gas are capitalized. Unevaluated property costs are excluded from the amortization base until we have made a determination as to the existence of proved reserves on the respective property or impairment. We review our unevaluated properties at the end of each quarter to determine whether portions of the costs should be reclassified to the full cost pool and thereby subject to amortization. Sales of oil and natural gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

Capitalized costs of oil and natural gas properties (net of related deferred income taxes) may not exceed a ceiling amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved oil and natural gas reserves plus the cost of unevaluated properties (adjusted for related income tax effects). Should capitalized costs exceed this ceiling amount, the excess is charged to earnings as an impairment expense, net of its related reduction of the deferred income tax provision. The present value of estimated future net cash flows is computed by applying period-end oil and natural gas prices of oil and natural gas to estimated future production of proved oil and natural gas reserves as of period-end, less estimated future expenditures (at period-end rates) to be incurred in developing and producing the proved reserves and assuming continuation of economic conditions existing at period-end. The present value of future net cash flows of proved reserves excludes future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet.

Asset Retirement Obligations

We recognize a liability for future retirement obligations associated with our oil and natural gas properties. The estimated fair value of the asset retirement obligations is based on the current estimated cost escalated at an inflation rate and discounted at a credit adjusted risk-free rate. This liability is capitalized as part of the cost of the related asset and amortized over its useful life. The liability accretes until we settle the obligation. The costs are estimated by management based on its knowledge of industry practices, current laws and past experiences. The costs could increase significantly from management’s current estimate.

Estimates of Proved Oil and Natural Gas Reserves

Estimates of our proved oil and natural gas reserves have a significant impact on the carrying value of our oil and natural gas properties, the related property amortization expense and related property impairment expense. Volumes of reserves actually recovered and cash flows actually received from actual production may differ significantly from the proved reserve estimates and the related projected cash flows, respectively. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment and the existence of development plans. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Income Taxes

Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statement and income tax reporting. We routinely assess the likelihood of realization of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices).

Stock-Based Compensation

We record compensation expense in the consolidated financial statements for stock options and restricted stock granted to employees, consultants and directors using the fair value method. Fair values for options granted are determined using the Black Scholes option pricing model, which is sensitive to the estimate of our stock price volatility and the options expected life. Fair values for restricted stock are based on the trading price of the Company’s common stock on the grant date of the award. Compensation costs are recognized over the vesting period.

Recently Issued Accounting Pronouncements

Refer to Note 2 of the Financial Statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required under Regulation S-K for “smaller reporting companies.”

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our Consolidated Financial Statements required by this item are included on the pages immediately following the Index to Financial Statements appearing on page F-1.

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

None.

ITEM 9A – CONTROLS AND PROCEDURES

MANAGEMENT’S EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is collected and communicated to management to allow timely decisions regarding required disclosures. The Chief Executive Officer and the Chief Financial Officer have concluded, based on their evaluation as of January 31, 2011 that disclosure controls and procedures were effective in providing reasonable assurance that material information is made known to them by others within the Company.

Management’s Annual Report on Internal Control over Financial Reporting

In regards to internal control over financial reporting, our management is responsible for the following:

establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act), and

assessing the effectiveness of internal control over financial reporting.

The Company’s internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and affected by our board of directors, management and other personnel. It was designed to provide reasonable assurance to our management, our board of directors and external users regarding the fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that:

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets,

provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors, and

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. 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.

Under the supervision and with the participation of our Chief Executive Officer and our Chief Financial Officer, management assessed the effectiveness of our internal control over financial reporting as of January 31, 2011. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework.

Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of our internal control over financial reporting. Based upon the assessment, management believes that, as of January 31, 2011, our internal control over financial reporting is effective based on those criteria.

Changes to Internal Controls and Procedures Over Financial Reporting

We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes. As of January 31, 2011, we remediated our control deficiency identified in prior filings with the addition of personnel to perform financial accounting and reporting functions. The additional personnel bring technical accounting and U.S. Generally Accepted Accounting Principles (“GAAP”) experience as well as specialized knowledge of oil and gas accounting. Our previous control deficiency indicated that we did not maintain sufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of GAAP commensurate with the complexity of our financial accounting and reporting requirements. We believe that the additional personnel alleviate this deficiency in addition to improving controls in other areas including segregation of duties.

ITEM 9B – OTHER INFORMATION

None.

PART III.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Names:	Ages	Position
F. Gardner Parker (1)	69	Chairman of the Board
Peter Hill	63	Chief Executive Officer and Director
Jonathan Samuels	32	Chief Financial Officer, Corporate Secretary and Director
Stephen A. Holditch (1)	64	Director
Randal Matkaluk (1)	52	Director

(1) Independent Director, Member of Audit, Compensation and Nominating and Corporate Governance Committees.

Directors are elected to serve until the next annual meeting of stockholders and until their successors are elected and qualified. Currently there are five seats on our board of directors.

Officers are elected by our board of directors and serve until their successors are appointed by our board of directors. Biographical resumes of each officer and director are set forth below.

F. Gardner Parker has been a director and Chairman of the board of directors since November 2009. From 1970 to 1984, Mr. Parker worked at Ernst & Ernst (now Ernst & Young LLP), an accounting firm, and was a partner at that firm from 1978 to 1984. Mr. Parker served as Managing Outside Trust Manager with Camden Property Trust, a real estate investment trust, from 1998 to 2005 and still serves as a Trust Manager of Camden Property Trust. He has also served as a director of Carrizo Oil & Gas, Inc. since 2000. Mr. Parker also serves on the boards of Hercules Offshore, Inc., Gas Resources Inc. and Sharpes Compliance Corp. He is a graduate of the University of Texas and is a CPA in Texas. Mr. Parker is board certified by the National Association of Corporate Directors. Mr. Parker previously served as a director of Blue Dolphin Energy Company from 2004 to 2007. Mr. Parker’s qualifications to sit on the board of directors include significant public company governance and audit experience.

Dr. Peter Hill has been a director and our Chief Executive Officer since November 2009. Dr. Hill has over 37 years of experience in the international oil and natural gas industry. He commenced his career in 1972 and spent 22 years in senior positions at British Petroleum including Chief Geologist, Chief of Staff for BP Exploration, President of BP Venezuela and Regional Director for Central and South America. Dr. Hill then worked as Vice President of Exploration at Ranger Oil Ltd. in England (1994-95), Managing Director Exploration and Production at Deminex GMBH Oil in Germany (1995-97), Technical Director/Chief Operating Officer at Hardy Oil & Gas plc (1998-2000), President and Chief Executive Officer at Harvest Natural Resources, Inc. (2000-2005), Director/Chairman at Austral Pacific Energy Ltd. (2006-2008), independent advisor to Palo Alto Investors (January 2008 to December 2009) and Non-Executive Chairman at Toreador Resources Corporation (January 2009 to present). Dr. Hill has a B.Sc. (Honors) in Geology and a Ph.D. Dr. Hill’s qualifications to sit on the board of directors include significant public company governance experience, significant experience as an exploration geologist and over 20 years of general management experience.

Jonathan Samuels has been a director, and our Chief Financial Officer and Corporate Secretary since December 2009. Prior to joining us, Mr. Samuels was an investment professional responsible for research and investment sourcing in the energy sector at Palo Alto Investors, a hedge fund founded in 1989. Mr. Samuels worked for five years at California-based Palo Alto Investors. Mr. Samuels received his B.A. from the University of California and his MBA from the Wharton School. He also has a Certified Financial Analyst designation. Mr. Samuels’s qualifications to sit on the board of directors include significant capital markets experience and significant experience investing in public companies.

Dr. Stephen A. Holditch has been a director since February 2006. Since January 2004, Dr. Holditch has been the Head of the Department of Petroleum Engineering at Texas A&M University. Since 1976 through the present, Dr. Holditch has been a faculty member at Texas A&M University, as an Assistant Professor, Associate Professor, Professor and Professor Emeritus. Since its founding in 1977 until 1997, when it was acquired by Schlumberger Technology Corporation, Dr. Holditch was the Founder and President of S.A. Holditch & Associates, Inc., a petroleum technology consulting firm providing analysis of low permeability natural gas reservoirs and designing hydraulic fracture treatments. Dr. Holditch is a registered Professional Engineer in Texas, has received numerous honors, awards and recognitions and has authored or co-authored over 100 publications on the oil and natural gas industry. Dr. Holditch received his B.S., M.S. and Ph.D. in Petroleum Engineering from Texas A&M University in 1969, 1970 and 1976, respectively. Dr. Holditch’s qualifications to sit on the board of directors include significant experience with completions, well operations and fracture technology.

Randal Matkaluk has been a director since August 2007. Since February 2010, Mr. Matkaluk has been the Chief Financial Officer of Capio Exploration Ltd., a private oil and natural gas exploration and development company. From November 2008 to November 2009, Mr. Matkaluk was the Chief Financial Officer and Corporate Secretary of Vigilant Exploration Inc., a private oil and natural gas exploration company that was acquired by Tourmaline Oil Corp. in November 2009. From March 2006 to October 2008, Mr. Matkaluk was an independent businessman. Mr. Matkaluk has been a director and officer of Virtutone Networks Inc. (formerly Sawhill Capital Ltd.) since October 2005. Between January 2003 and February 2006, Mr. Matkaluk was the co-founder and Chief Financial Officer of Relentless Energy Corporation, a private oil and natural gas exploration company. Between June 2001 and December 2002, Mr. Matkaluk was the Chief Financial Officer of Antrim Energy Inc., a public international oil and natural gas exploration company listed on the TSX Exchange. Mr. Matkaluk has also worked for Gopher Oil and Gas Company and Cube Energy Corp. Mr. Matkaluk has been a Chartered Accountant since 1983. Mr. Matkaluk received his Bachelor’s Degree in Commerce in 1980 from the University of Calgary. Mr. Matkaluk’s qualifications to sit on the board of directors include significant public company governance and audit experience.

Composition of the Board of Directors

Our board of directors currently consists of five members, including our Chief Executive Officer and Chief Financial Officer. We have three directors that qualify as independent directors under the corporate governance standards of the NYSE Amex and the independence requirements of Rule 10A-3 of the Exchange Act.

Board of Directors Leadership Structure

Our board of directors understands that there is no single, generally accepted approach to providing board leadership and that given the dynamic and competitive environment in which we operate, the right board leadership structure may vary as circumstances warrant. To this end, our board of directors has no policy mandating the combination or separation of the roles of Chairman and Chief Executive Officer and believes the matter should be discussed and considered from time to time as circumstances change. We currently have a separate Chairman and Chief Executive Officer. This leadership structure is appropriate for us at this time as it permits our Chief Executive Officer to focus on management of our day-to-day operations, while allowing our Chairman to lead our board of directors in its fundamental role of providing advice to and independent oversight of management.

Board of Directors Oversight of Risk Management

Our entire board of directors oversees our risk management process. Our board of directors oversees a company-wide approach to risk management, carried out by management. Our entire board of directors determines the appropriate risk for us generally, assesses the specific risks faced by our Company and reviews the steps taken by management to manage those risks.

While the entire board of directors maintains the ultimate oversight responsibility for the risk management process, its committees oversee risk in certain specified areas. In particular, our compensation committee is responsible for overseeing the management of risks relating to our executive compensation plans and arrangements and the incentives created by the compensation awards it administers. Our compensation committee believes that the Company’s overall executive compensation program does not encourage excessive risk or unnecessary risk taking. Our audit committee oversees management of enterprise risks as well as financial risks and is also responsible for overseeing potential conflicts of interests. Pursuant to the board of directors’ instruction, management regularly reports on applicable risks to the relevant committee or the entire board of directors, as appropriate, with additional review or reporting on risks conducted as needed or as requested by the board of directors and its committees.

Board of Directors Committees

The board of directors currently has a standing audit committee, compensation committee and nominating and corporate governance committee. Members serve on these committees until their respective resignations or until otherwise determined by our board of directors. Our board of directors may, from time to time, establish other committees.

Audit Committee

The audit committee is currently comprised of three directors, Messrs. Randal Matkaluk, F. Gardner Parker and Stephen Holditch, with Mr. Matkaluk elected as Chairman of the committee. Our board of directors has determined that all members of the audit committee satisfy the requirements to serve as “independent” directors, as those requirements have been defined by Rule 10A-3 of the Exchange Act and the NYSE Amex. The board of directors has determined that Mr. Matkaluk, who is a Chartered Accountant having over 25 years of financial experience, qualifies as an “audit committee financial expert.” Mr. Matkaluk is independent of management based on the independence requirements set forth in the Financial Industry Regulatory Authority’s definition of “independent director.”

The audit committee is appointed by our board of directors to assist the board of directors in overseeing (1) the quality and integrity of our financial statements; (2) the independent auditor’s qualifications and independence; (3) the performance of our independent auditor; and (4) our compliance with legal and regulatory requirements. The authority and responsibilities of the audit committee are set forth in a written audit committee charter adopted by the board of directors. The charter grants to the audit committee sole responsibility for the appointment, compensation and evaluation of our independent auditor, as well as establishing the terms of such engagements. The audit committee has the authority to retain the services of independent legal, accounting or other advisors as the audit committee deems necessary, with appropriate funding available from us, as determined by the audit committee, for such services. The audit committee reviews and reassesses the charter annually and recommends any changes to the board of directors for approval.

Report of the Audit Committee

The audit committee of our board of directors is currently comprised of three directors, Messrs. Randal Matkaluk, F. Gardner Parker and Stephen Holditch, all of which satisfy the requirements to serve as Independent Directors, as those requirements have been defined by the SEC and NYSE Amex. Our board of directors has determined that Mr. Matkaluk, who is a Chartered Accountant and having over 25 years of financial experience, qualifies as an "audit committee financial expert." Mr. Matkaluk is independent of management based on the independence requirements set forth in the Financial Industry Regulatory Authority’s definition of "independent director."

The audit committee has furnished the following report:

The audit committee is appointed by our board of directors to assist the board of directors in overseeing (1) the quality and integrity of the financial statements of the Company; (2) the independent auditor’s qualifications and independence; (3) the performance of the Company’s independent auditor; and (4) the Company’s compliance with legal and regulatory requirements. The authority and responsibilities of the audit committee are set forth in a written audit committee Charter adopted by the board of directors. The Charter grants to the audit committee, sole responsibility for the appointment, compensation and evaluation of the Company’s independent auditor for the Company, as well as establishing the terms of such engagements. The audit committee has the authority to retain the services of independent legal, accounting or other advisors as the audit committee deems necessary, with appropriate funding available from the Company, as determined by the audit committee, for such services. The audit committee reviews and reassesses the Charter annually and recommends any changes to the board of directors for approval.

The audit committee is responsible for overseeing the Company’s overall financial reporting process. In fulfilling its oversight responsibilities for the financial statements for the Company’s fiscal year ended January 31, 2011, the audit committee:

Reviewed and discussed the annual audit process and the audited financial statements for the fiscal year ended January 31, 2011 with management and KPMG LLP, the Company’s independent auditor;

Discussed with management, and KPMG LLP the adequacy of the system of internal controls;

Discussed with KPMG LLP the matters required to be discussed by Statement on Auditing Standards No. 114 relating to the conduct of the audit; and

Received a letter from KPMG LLP regarding its independence as required by Independence Standards Board Standard No. 1 and discussed with KPMG LLP its independence.

The audit committee also considered the status of pending litigation, taxation matters and other areas of oversight relating to the financial reporting and audit process that the audit committee determined appropriate. In addition, the audit committee’s meetings included executive sessions with the Company’s independent auditor and the Company’s accounting and reporting staff, in each case without the presence of the Company’s management.

In performing all of these functions, the audit committee acts only in an oversight capacity. Also, in its oversight role, the audit committee relies on the work and assurances of the Company’s management, which has the primary responsibility for financial statements and reports, and of the independent auditor, who, in their report, express an opinion on the conformity of the Company’s annual financial statements to accounting principles generally accepted in the United States of America.

Based on the audit committee’s review of the audited financial statements and discussions with management and KPMG LLP, the audit committee recommended to the board of directors that the audited financial statements be included in the Company’s annual report on Form 10-K for the fiscal year ended January 31, 2011 for filing with the SEC.

Audit Committee

Randal Matkaluk, Chairman

Stephen A. Holditch

F. Gardner Parker

Audit Committee Pre-Approval Policy

Pursuant to the terms of the Company’s audit committee Charter, the audit committee is responsible for the appointment, compensation and oversight of the work performed by the Company’s independent auditor. The audit committee, or a designated member of the audit committee, must pre-approve all audit (including audit-related) and non-audit services performed by the independent auditor in order to ensure that the provisions of such services does not impair the auditor’s independence. The audit committee has delegated interim pre-approval authority to the Chairman of the audit committee. Any interim pre-approval of permitted non-audit services is required to be reported to the audit committee at its next scheduled meeting. The audit committee does not delegate its responsibilities to pre-approve services performed by the independent auditor to management.

The term of any pre-approval is 12 months from the date of pre-approval, unless the audit committee specifically provides for a different period. With respect to each proposed pre-approved service, the independent auditor must provide detailed back-up documentation to the audit committee regarding the specific service to be provided pursuant to a given pre-approval of the audit committee. Requests or applications to provide services that require separate approval by the audit committee will be submitted to the audit committee by both the independent auditor and the Company’s Chief Financial Officer, and must include a joint statement as to whether, in their view, the request or application is consistent with the SEC’s rules on auditor independence. All of the services described in Item 14, Principal Accountant Fees and Services, were approved by the audit committee.

Compensation Committee

The compensation committee is currently comprised of three directors, Messrs. Randal Matkaluk, F. Gardner Parker and Stephen Holditch, with Mr. Matkaluk elected as Chairman of the committee. Our board of directors has determined that all of the members of the compensation committee are “non-employee” directors as defined in Rule 16b-3(b)(3) under the Exchange Act, and “outside” directors within the meaning of Section 162(m)(4)(c)(i) of the Internal Revenue Code.

The compensation committee has responsibility for assisting the board of directors in, among other things, evaluating and making recommendations regarding the compensation of our executive officers and directors, assuring that the executive officers are compensated effectively in a manner consistent with our stated compensation strategy, periodically evaluating the terms and administration of our incentive plans and benefit programs and monitoring of compliance with the legal prohibition on loans to our directors and executive officers.

Nominating and Corporate Governance Committee

The nominating and corporate governance committee is currently comprised of three directors, Messrs. Randal Matkaluk, F. Gardner Parker and Stephen Holditch, with Mr. Matkaluk elected as Chairman of the committee. Our board of directors has determined that all members of the nominating and corporate governance committee satisfy the requirements to serve as “independent” directors, as those requirements have been defined by Rule 10A-3 of the Exchange Act and the NYSE Amex.

The nominating and corporate governance committee will be responsible for identifying, screening and recommending candidates to the board of directors for board of directors' membership; advising the board of directors with respect to the corporate governance principles applicable to us; and overseeing the evaluation of the board and management.

Qualifications for consideration as a director nominee may vary according to the particular areas of expertise being sought as a complement to the existing composition of the board of directors. However, at a minimum, candidates for director must possess:

high personal and professional ethics and integrity;

the ability to exercise sound judgment;

the ability to make independent analytical inquiries;

a willingness and ability to devote adequate time and resources to diligently perform board of directors and committee duties; and

the appropriate and relevant business experience and acumen.

In addition to these minimum qualifications, the nominating and corporate governance committee will also take into account when considering whether to nominate a potential director candidate the following factors:

whether the person possesses specific industry expertise and familiarity with general issues affecting our business;

whether the person’s nomination and election would enable the board of directors to have a member that qualifies as an “audit committee financial expert” as such term is defined by the SEC in Item 401 of Regulation S-K;

whether the person would qualify as an “independent” director under the listing standards of the various stock markets and exchanges;

the importance of continuity of the existing composition of the board of directors to provide long-term stability and experienced oversight; and

the importance of diversified board of directors' membership, in terms of both the individuals involved and their various experiences and areas of expertise.

The nominating and corporate governance committee will also consider director candidates recommended by stockholders provided such recommendations are submitted in accordance with the procedures set forth below. In order to provide for an orderly and informed review and selection process for director candidates, the board of directors has determined that stockholders who wish to recommend director candidates for consideration by the board of directors must comply with the following:

the recommendation must be made in writing to our Corporate Secretary;

the recommendation must include the candidate’s name, home and business contact information, detailed biographical data and qualifications, information regarding any relationships between us and the candidate within the last three years and evidence of the recommending person’s ownership of our common stock;

the recommendation shall also contain a statement from the recommending stockholder in support of the candidate; professional references, particularly within the context of those relevant to board membership, including issues of character, judgment, diversity, age, independence, expertise, corporate experience, length of service, other commitments and the like; and

a statement from the stockholder nominee indicating that such nominee wants to serve on the board of directors and could be considered “independent” under the listing standards of the various stock markets and exchanges and the SEC, as in effect at that time.

All candidates submitted by stockholders will be evaluated by the board of directors according to the criteria discussed above and in the same manner as all other director candidates.

Code of Ethics

We have adopted a code of business conduct and ethics (within the meaning of Item 406(b) of Regulation S-K) that applies to our directors, officers and employees. The code of business conduct and ethics is designed to deter wrongdoing and to promote honest and ethical conduct and full, fair, accurate, timely and understandable disclosure in our SEC reports and other public communications. The code of business conduct and ethics promotes compliance with applicable governmental laws, rules and regulations. The code of business conduct and ethics is posted to our website.

Compensation Committee Interlocks and Insider Participation

None of our officers or employees are members of the compensation committee. None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our board of directors or compensation committee. No member of our board of directors is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Section 16(a) Compliance

Section 16(a) of the Exchange Act requires our directors and executive officers, and persons who own beneficially more than ten percent (10%) of our common stock, to file reports of ownership and changes of ownership with the SEC. Copies of all filed reports are required to be furnished to us pursuant to Section 16(a). Based solely on the reports we received and on written representations from reporting persons, we believe that, during fiscal year 2011, our directors, executive officers and 10% stockholders complied with all Section 16(a) filing requirements.

ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation Table

The following tables set forth certain information regarding our CEO and CFO whose total annual salary and bonus for the fiscal years ending January 31, 2011 and 2010 exceeded $100,000:

Name & Principal Position	Year	Salary		Bonus (c)		Stock Awards (d)		Option Awards (e)		All Other Compensation (f)		Total
Peter Hill (a), CEO, Principal	2011	$	277,350	$	750,000	$	208,849	$	33,290	$	36,526	$	1,306,015
Executive Officer	2010	$	41,667	$	-	$	-	$	5,660	$	-	$	47,327

Jonathan Samuels (b), CFO, Principal	2011	$	214,791	$	600,000	$	208,849	$	22,589	$	10,751	$	1,056,980
Financial Officer	2010	$	25,000	$	-	$	-	$	3,841	$	-	$	28,841

Effective November 30, 2009, we agreed to pay a salary of $250,000 per year to Dr. Hill. Effective February 1, 2011, we agreed to increase Dr. Hill’s salary to $350,000 per year.

Effective December 16, 2009, we agreed to pay a salary of $200,000 per year to Mr. Samuels. Effective February 1, 2011, we agreed to increase Mr. Samuels’s salary to $300,000 per year.

The compensation committee approved the payment of the fiscal year 2011 short-term incentive cash bonuses for Dr. Hill and Mr. Samuels of $750,000 and $600,000, respectively, based on their extraordinary performances during the fiscal year.

This column represents the aggregate grant date fair value computed in accordance with FASB ASC Topic 718. The assumptions used are described in note 5 of the financial statements included in this document.

This column represents the aggregate grant date fair value under FASB ASC Topic 718. The assumptions used are described on page in note 5 of the financial statements included in this document.

Other compensation includes health insurance and rent paid on behalf of the executive officers.

There were no other executive officers in the Company in fiscal year 2011 that earned over $100,000.

Employment Agreements with Executive Officers

Both Dr. Hill and Mr. Samuels have entered into amended and restated employment agreements with the Company effective December 2, 2010. The agreements provide a two year term for Dr. Hill and a one year term for Mr. Samuels, with an automatic renewal for an additional year unless either party provides written notice of non-renewal. On December 2, 2010, our board of directors, as recommended by our compensation committee, determined that Dr. Hill and Mr. Samuels had met the performance objectives set forth in their respective employment agreements with respect to the “Restructuring STI Award” resulting in the award to Dr. Hill and Mr. Samuels of 90,909 shares of restricted stock of the Company and 72,727 shares of restricted stock of the Company, respectively. In addition, due to the efforts and performance of Dr. Hill and Mr. Samuels in connection with the November 2010 public offering of shares of common stock of the Company, the board of directors further determined to grant each of Dr. Hill and Mr. Samuels an additional 10,000 shares of restricted stock of the Company. Both of these awards are set forth in the employment agreements. The awards of the restricted stock will not become effective until approval by the stockholders of the Company of a new omnibus equity incentive plan in 2011 and, once approved, such grants will vest in full on January 31, 2012 subject to their continued service with the Company until the vesting date and the terms and provisions of the new omnibus equity incentive plan and applicable award agreement.

Peter Hill

The agreement with Dr. Hill provides for an annual salary of not less than $250,000. In addition, Dr. Hill is eligible to receive an annual bonus of up to 200% of base salary based upon performance (the "Hill STI Award"), as determined by the Compensation Committee of the board of directors. Additionally, he is entitled to participate in any and all benefit plans, from time to time, in effect for executives, along with vacation, sick and holiday pay in accordance with our policies established and in effect from time to time. In the event that Dr. Hill’s employment is terminated by us without cause (as defined in the agreement) or by the employee for good reason, Dr. Hill is entitled to the continuation of payment of annual salary, any unpaid Hill STI Award, the target Hill STI Award for the year in which termination occurs (pro-rated for the period worked prior to the termination), benefits for an 18-month period and the immediate vesting of all shares of common stock previously awarded. In the event that Dr. Hill’s employment is terminated by us after a Change of Control (as defined in the agreement), he is entitled to a lump sum cash payment of two and one-half times annual salary, any unpaid Hill STI Award, the target Hill STI Award for the year in which termination occurs (pro-rated for the period worked prior to the termination), benefits for an 18-month period and the immediate vesting of all shares of common stock previously awarded.

Jonathan Samuels

The agreement with Mr. Samuels provides for an annual salary of not less than $200,000. In addition, Mr. Samuels is eligible to receive an annual bonus of up to 200% of base salary based upon performance (the “Samuels STI Award”), as determined by the Compensation Committee of the board of directors. Additionally, he is entitled to participate in any and all benefit plans, from time to time, in effect for executives, along with vacation, sick and holiday pay in accordance with our policies established and in effect from time to time. In the event that Mr. Samuels’ employment is terminated by us without cause (as defined in the agreement) or by the employee for good reason, Mr. Samuels is entitled to the continuation of payment of annual salary, any unpaid Samuels STI Award, the target Samuels STI Award for the year in which termination occurs (pro-rated for the period worked prior to the termination), benefits for an 18-month period and the immediate vesting of all shares of common stock previously awarded. In the event that Mr. Samuels employment is terminated by us after a Change of Control (as defined in the agreement), he is entitled to a lump sum cash payment of two times annual salary, any unpaid Samuels STI Award, the target Samuels STI Award for the year in which termination occurs (pro-rated for the period worked prior to the termination), benefits for an 18-month period and the immediate vesting of all shares of common stock previously awarded.

GRANTS OF PLAN-BASED AWARDS

The following table sets forth information regarding the number of shares of restricted stock granted to named executive officers during fiscal year 2011:

Name	Grant Date	All Other Equity Awards: Number of Restricted Shares granted		Base Price of Restricted Stock Awards per share		Grant Date Fair Value of Stock Awards
Peter Hill	February 2, 2010 (a)		60,000	$	3.50	$	210,000
	December 2, 2010 (b)		100,909	$	5.90	$	595,363

Jonathan Samuels	February 2, 2010 (a)		60,000	$	3.50	$	210,000
	December 2, 2010 (b)		82,727	$	5.90	$	488,089

(a)

The shares of restricted stock granted on February 2, 2010 were fully vested on February 2, 2011.

(b)

The shares of restricted stock granted on December 7, 2010 will not become effective until the approval by the stockholders of the Company of a new omnibus equity incentive plan in 2011 and, once approved, such grants will vest in full on January 31, 2012.

Outstanding Equity Awards at Fiscal Year-End

The following table sets forth information for the named executive officers regarding the number of equity awards outstanding as of January 31, 2011:

Option awards										Stock awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable			Equity incentive plan awards: Number of securities underlying unexercised unearned options (#)	Option Exercise Price		Option Expiration Date	Number of shares or units that have not vested			Market value (at January 31, 2011) of shares or units of stock that have not vested		Number of shares or units granted subsequent to January 31, 2011
Peter Hill		46,667		93,333	(a)		$	1.25	11/30/2015		160,909	(b)	$	1,253,481		470,909

Jonathan Samuels		31,667		63,333	(a)		$	1.25	11/30/2015		142,727	(b)	$	1,111,843		452,727

(a)

The stock options vest ratably in thirds over a three-year period beginning on the first anniversary of the grant date, which was November 30, 2009.

(b)

The shares of restricted stock granted on February 2, 2010 were fully vested on February 2, 2011. The shares of restricted stock granted on December 7, 2010 will not become effective until the approval by the stockholders of the Company of a new omnibus equity incentive plan in 2011 and, once approved, such grants will vest in full on January 31, 2012.

Option Exercises and Stock Vested

There were no stock options exercised and no restricted stock vested during the fiscal year ended January 31, 2011 by the above named executive officers.

Potential Payments Upon Change of Control

The following table sets forth the estimated potential payments and other benefits each of our named executive officers would have received in the event of a Change of Control (as defined in the employment agreements). We have assumed that the event triggering the payment occurred on January 31, 2011. The table does not include Accrued Obligations (as defined in the agreements) at the time of the triggering event. All calculations assume a stock value of $7.79 per share, which was the closing price of our common stock on the NYSE Amex on January 31, 2011.

Name	Multiple of Base Salary		Short Term Incentive Award		Pro-rata Shart Term Incentive		Stock Options (Vesting Accelerated) (a)		Stock Award Vesting		Benefits		Total
Peter Hill	$	625,000	$	-	$	250,000	$	908,600	$	1,253,481	$	19,000	$	3,056,081

Jonathan Samuels	$	400,000	$	-	$	200,000	$	616,550	$	1,111,843	$	9,500	$	2,337,893

(a)	Amounts represent the spread between the exercise price and the closing price of our common stock on January 31, 2011 of options that would vest on an accelerated basis if a Change of Control (as defined in the employment agreements) or other triggering event occurred on that day.

The Company does not provide a retirement plan (e.g. a 401(k) plan) to its employees or officers.

Director Compensation

Our directors are elected by the vote of a majority in interest of the holders of our voting stock and hold office until the expiration of the term for which he was elected and until a successor has been elected and qualified.

A majority of the authorized number of directors constitutes a quorum of the board of directors for the transaction of business. The directors must be present at the meeting to constitute a quorum. However, any action required or permitted to be taken by the board of directors may be taken without a meeting if all members of the board of directors individually or collectively consent in writing to the action.

The director compensation package for non-employee directors consists of annual cash compensation and discretionary awards of stock options or restricted stock. The Chairman of the board of directors received cash compensation of $12,500 for the first quarter and $18,750 per quarter for the remaining three quarters of fiscal year 2011. All other non-employee board of directors received cash compensation of $10,000 for the first quarter and $12,500 per quarter for the remaining three quarters of fiscal year 2011. For fiscal 2011, F. Gardner Parker received additional cash compensation for serving as the Chairman of our board of directors.

Directors received compensation for their services for the fiscal year ended January 31, 2011 as set forth below:

Name	Fees Earned or Paid in Cash		Stock Awards (a)		Total
Stephen A. Holditch	$	47,500	$	70,000	$	117,500
Randal Matkaluk	$	47,500	$	70,000	$	117,500
F. Gardner Parker	$	68,750	$	105,000	$	173,750

(a)

This column represents the aggregate grant date fair value computed in accordance with FASB ASC Topic 718. The assumptions used are described in note 5 of the audited financial statements included in this document.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth certain information with respect to the beneficial ownership of our common stock of: (1) each person or entity who owns of record or beneficially 5% or more of any class of our voting securities; (2) each of our named executive officers and directors; and (3) all of our directors and named executive officers as a group. The percentage of beneficial ownership of our common stock is based upon 42,942,538 shares issued and outstanding on April 1, 2011.

Except as otherwise indicated in the footnotes below, each of the beneficial owners has, to our knowledge, sole voting and investment power with respect to the indicated shares of common stock. Unless otherwise noted, the address of each beneficial owner is 1660 Wynkoop Street, Suite 900, Denver, Colorado 80202.

NAME AND ADDRESS OF OWNER	TITLE OF CLASS	NUMBER OF SHARES OWNED			PERCENTAGE OF CLASS			NUMBER OF UNVESTED SHARES			NUMBER OF SHARES OWNED INCLUDING UNVESTED SHARES		PERCENTAGE OF CLASS INCLUDING UNVESTED SHARES
Peter Hill	Common Stock		106,667	(1)		*			665,151	(8)		771,818		1.72	%

Jonathan Samuels	Common Stock		91,667	(2)		*			598,787	(9)		690,454		1.54	%

F. Gardner Parker	Common Stock		45,000	(3)		*			162,272	(10)		207,272		*

Randal Matkaluk	Common Stock		40,000	(4)		*			98,101	(11)		138,101		*

Stephen A. Holditch	Common Stock		31,737	(5)		*			98,101	(12)		129,838		*

All Officers and Directors	Common Stock		315,071	(6)		0.73	%		1,622,412	(13)		1,937,483		4.32	%
As a Group (5 persons)

Cambrian Capital, L.P.	Common Stock		2,819,395	(7)		6.52	%		-			-		6.28	%
45 Coolidge Point
Manchester, Massachusetts 01944

*Less than 1%.

(1)

Includes 46,667 shares of common stock underlying options that are currently exercisable or exercisable within 60 days and 60,000 shares of common stock that became issuable to Dr. Hill on February 2, 2011 pursuant to the automatic vesting of restricted stock. On December 2, 2010, the board of directors, as recommended by the Compensation Committee of the board of directors, determined that Dr. Hill had met the performance objectives set forth in his employment agreement with respect to the Restructuring STI Award (as defined therein), resulting in the award to Dr. Hill of 90,909 shares of our restricted stock. In addition, due to the efforts and performance of Dr. Hill in connection with the public offering of shares of common stock on November 10, 2010, the board of directors further determined to grant Dr. Hill an additional 10,000 shares of restricted stock. This grant of the restricted stock will not become effective until the approval by our stockholders of a new omnibus equity incentive plan in 2011 and, once approved, such grants shall vest in full on January 31, 2012 subject to Dr. Hill’s continued service with us until the vesting date and the terms and provisions of the new omnibus equity incentive plan and applicable award agreement.

(2)

Includes 31,667 shares of common stock underlying options that are currently exercisable or exercisable within 60 days and 60,000 shares of common stock that became issuable to Mr. Samuels on February 2, 2011 pursuant to the automatic vesting of restricted stock. On December 2, 2010, the board of directors, as recommended by the Compensation Committee of the board of directors, determined that Mr. Samuels had met the performance objectives set forth in his employment agreement with respect to the Restructuring STI Award (as defined therein), resulting in the award to Mr. Samuels of 72,727 shares of our restricted stock. In addition, due to the efforts and performance of Mr. Samuels in connection with the public offering of shares of common stock on November 10, 2010, the board of directors further determined to grant Mr. Samuels an additional 10,000 shares of restricted stock. This grant of the restricted stock will not become effective until the approval by our stockholders of a new omnibus equity incentive plan in 2011 and, once approved, such grants shall vest in full on January 31, 2012 subject to Mr. Samuels’ continued service with us until the vesting date and the terms and provisions of the new omnibus equity incentive plan and applicable award agreement.

(3)

Includes 15,000 shares of common stock underlying options that are currently exercisable or exercisable within 60 days and 30,000 shares of common stock that became issuable to Mr. Parker on February 2, 2011 pursuant to the automatic vesting of restricted stock.

(4)

Includes 10,000 shares of common stock underlying options that are currently exercisable or exercisable within 60 days and 20,000 shares of common stock that became issuable to Mr. Matkaluk on February 2, 2011 pursuant to the automatic vesting of restricted stock.

(5)

Includes 10,000 shares of common stock underlying options that are currently exercisable or exercisable within 60 days and 20,000 shares of common stock that became issuable to Dr. Holditch on February 2, 2011 pursuant to the automatic vesting of restricted stock.

(6)

Includes 113,334 shares of common stock underlying options that are currently exercisable or exercisable within 60 days and 190,000 shares of common stock that became issuable on February 2, 2011 pursuant to the automatic vesting of restricted stock.

(7)

As reported pursuant to a Schedule 13G/A filed with the SEC on March 15, 2011. Cambrian Capital L.P. serves as the investment manager to CamCap Energy Offshore Master Fund, L.P., which owns 1,212,122 shares of our common stock, and CamCap Resources Offshore Master Fund, L.P., which owns 1,607,273 shares of our common stock. CamCap Resources Partners, LLC serves as general partner of CamCap Resources Offshore Master Fund, L.P. CamCap Energy Partners, LLC serves as general partner of CamCap Energy Offshore Master Fund, L.P. Cambrian Capital, LLC is the general partner of Cambrian Capital L.P. Ernst von Metzsch and Roland von Metzsch are the managers of each of Cambrian Capital, LLC, CamCap Resources Partners, LLC and CamCap Energy Partners, LLC, and in such capacities may be deemed to have voting and investment control over the shares for such entities. Each of the reporting persons disclaims beneficial ownership of all shares except to the extent of its pecuniary interest therein.

(8)

Includes 93,333 shares of common stock underlying options and 571,818 shares of restricted stock.

(9)

Includes 63,333 shares of common stock underlying options and 535,454 shares of restricted stock.

(10)

Includes 30,000 shares of common stock underlying options and 132,272 shares of restricted stock.

(11)

Includes 5,000 shares of common stock underlying options and 93,101 shares of restricted stock.

(12)

Includes 5,000 shares of common stock underlying options and 93,101 shares of restricted stock.

Equity Compensation Plan Information

The following table sets forth certain information about the common stock that may be issued upon the exercise of options under the equity compensation plans as of January 31, 2011.

Plan Category	Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Shares Reflected in the First Column)
Equity compensation plans approved by stockholders		343,333	$	1.60		1,909,225
Equity compensation plans not approved by stockholders		509,636	$	-		2,990,364
Total		852,969	$	1.50		4,899,589

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE

There have been no transactions, or proposed transactions, which have materially affected or will materially affect us in which any director, executive officer or beneficial holder of more than 5% of the outstanding common stock, or any of their respective relatives, spouses, associates or affiliates, has had or will have any direct or material indirect interest. We have no policy regarding entering into transactions with affiliated parties.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES (AMOUNTS IN CANADIAN DOLLARS).

Audit Fees

The aggregate fees billed by our current auditor during the years ended January 31, 2011 and 2010, for professional services rendered for the audit of our annual financial statements, the reviews of the financial statements included in our quarterly reports on Form 10-Q and for required securities filings such as prospectuses, Form S-1, Form S-3 and Form S-8 during the fiscal years, were $221,311 and $92,656, respectively.

Audit-Related Fees

Our current independent registered public accounting firm did no bill us for audit related services during the fiscal years ended January 31, 2011 and 2010, respectively.

Tax Fees

Our current independent registered public accounting firm billed us $22,730 and $13,654, respectively, during the fiscal years ended January 31, 2011 and 2010, for tax related work.

All Other Fees

Our current independent registered public accounting firm did not bill us during fiscal years ended January 31, 2011, or 2010 for other services.

Our board of directors and audit committee have considered whether the provision of non-audit services is compatible with maintaining the principal accountant's independence.

PART IV.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

Exhibit No.		Description

3.1		Articles of Incorporation, as amended, effective as of November 4, 2010, filed as an exhibit to the Registration Statement on Amendment No. 3 on Form S-1 filed with the Securities and Exchange Commission on November 4, 2010 and incorporated herein by reference.

3.2		Second Amended and Restated Bylaws, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 5, 2010 and incorporated herein by reference.

4.1		Specimen Common Stock Certificate, filed as an exhibit to the Registration Statement on Amendment No. 1 on Form S-1 filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.

10.01		Stock Option Plan, filed as an exhibit to the Registration Statement on Form S-8 filed with the Securities and Exchange Commission on January 31, 2011 and incorporated herein by reference.

10.02		Production Lease, dated as of April 15, 2009, by and between the Company and Her Majesty the Queen in the Right of the Province of Nova Scotia, filed as an exhibit to the Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on April 20, 2009 and incorporated herein by reference.

10.03		Overriding Royalty Agreement, dated as of June 10, 2009, by and between Elmworth Energy Corporation and Contact Exploration Inc., filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 2, 2009 and incorporated herein by reference.

10.04		Amended and Restated Employment Agreement, dated as of December 2, 2010, by and between Triangle Petroleum Corporation and Dr. Peter Hill, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 6, 2010 and incorporated herein by reference.

10.05		Amended and Restated Employment Agreement, dated as of December 2, 2010, by and between Triangle Petroleum Corporation and Jonathan Samuels filed as an exhibit to the Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 6, 2010 and incorporated herein by reference.

10.06		Deferred Share Unit Agreement, dated February 2, 2010 between Triangle Petroleum Corporation and Peter Hill, filed as an exhibit to the Registration Statement on Amendment No. 1 to Form S-1 filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.

10.07		Deferred Share Unit Agreement, dated February 2, 2010 between Triangle Petroleum Corporation and Jonathan Samuels, filed as an exhibit to the Registration Statement on Amendment No. 1 to Form S-1 filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.

10.08		Form of Deferred Share Unit Agreement entered into by each of Gardner Parker, Randal Matkaluk and Steve Holditch, each dated February 2, 2010, filed as an exhibit to the Registration Statement on Amendment No. 2 to Form S-1 filed with the Securities and Exchange Commission on November 2, 2010 and incorporated herein by reference.

14.01		Code of Business Conduct and Ethics, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.

21.01*		List of Subsidiaries.

23.02*		Consent of MHA Petroleum Consultants.

24.01		Power of Attorney (incorporated by reference to the signature page of this Annual Report on Form 10-K).

31.01*		Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.02*		Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.01*		Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.01*		Reserve Estimate Report of MHA Petroleum Consultants.

* Filed herewith.

TRIANGLE PETROLEUM CORPORATION

INDEX TO THE FINANCIAL STATEMENTS

		Page

Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets as of January 31, 2011 and 2010		F-3

Consolidated Statements of Operations for each of the years ended January 31, 2011 and 2010		F-4

Consolidated Statements of Cash Flows for each of the years ended January 31, 2011 and 2010		F-5

Consolidated Statement of Stockholders' Equity for each of the years ended January 31, 2011 and 2010		F-6

Notes to the Consolidated Financial Statements		F-7 to F-18

F-1

The Board of Directors and Stockholders

Triangle Petroleum Corporation

We have audited the accompanying consolidated balance sheets of Triangle Petroleum Corporation as of January 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years then ended January 31, 2011. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatements. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Triangle Petroleum Corporation as of January 31, 2011 and 2010, and the results of its operations and its cash flows for each of the years then ended in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Chartered Accountants

Calgary, Alberta

April 13, 2011

F-2

TRIANGLE PETROLEUM CORPORATION

CONSOLIATED BALANCE SHEETS

AS OF JANUARY 31, 2011 AND 2010

	2011			2010
ASSETS
CURRENT ASSETS
Cash	$	57,773,269		$	4,878,601
Restricted cash		105,264			-
Prepaid expenses		316,069			342,635
Other receivables		232,828			313,785
Total current assets		58,427,430			5,535,021

PROPERTY AND EQUIPMENT (Note 3)
Furniture, fixtures and equipment		-			39,296
Oil and gas properties		22,133,885			18,783,375
Prepaid drilling costs		1,469,453			-
Total assets	$	82,030,768		$	24,357,692

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable	$	1,939,754		$	574,723
Accrued liabilities		2,880,611			119,224
Total current liabilities		4,820,365			693,947

Asset retirement obligations (Note 2)		1,403,697			1,180,515
Total liabilities		6,224,062			1,874,462

COMMITMENTS (Note 6)

STOCKHOLDERS' EQUITY (Note 5)
Common stock, $.00001 par value, 70,000,000 shares authorized; 22,525,672 and 6,992,692 shares issued and outstanding at January 31, 2011 and 2010, respectively		225			70
Additional paid-in capital		159,788,323			81,950,705
Warrants		-			4,237,100
Accumulated deficit		(83,981,842	)		(63,704,645	)
Total stockholders’ equity		75,806,706			22,483,230
Total liabilities and stockholders’ equity	$	82,030,768		$	24,357,692

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

F-3

TRIANGLE PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEARS ENDED JANUARY 31, 2011 AND 2010

	2011			2010
REVENUES
Oil and Natural Gas Revenue, net of royalties	$	536,763		$	131,245

OPERATING EXPENSES
Lease operating expenses		144,606			95,852
Impairment of unproved oil and gas properties (Note 3)		14,917,356			-
General and administrative		6,467,665			3,987,012
Gain on sale of oil and gas property (Note 3)		(1,006,294	)		(1,266,294	)
Accretion of asset retirement obligations (Note 2)		250,319			150,007
Depletion, depreciation and amortization (Note 3)		135,296			64,979
Foreign exchange gain		(35,615	)		(753,950	)
Total operating expense		20,873,333			2,277,606

LOSS FROM OPERATIONS		(20,336,570	)		(2,146,361	)

OTHER INCOME
Interest and royalty income		46,301			6,260
Interest expense		(898	)		-
Other income		13,970			-
Total other income		59,373			6,260

NET LOSS	$	(20,277,197	)	$	(2,140,101	)

NET LOSS PER COMMON SHARE - BASIC AND DILUTED	$	(1.63	)	$	(0.31	)

Weighted average common shares outstanding – basic and diluted		12,463,751			6,992,604

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

F-4

TRIANGLE PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

FOR THE YEARS ENDED JANUARY 31, 2011 AND 2010

	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(20,277,197	)	$	(2,140,101	)
Adjustments to reconcile net loss to net cash used in operating activities:
Accretion of asset retirement obligations		250,319			150,007
Depreciation, depletion and amortization		135,296			64,979
Impairment of unproved oil and gas properties		14,917,356			-
Stock-based compensation		1,066,311			794,361
Gain on sale of oil and natural gas properties		(1,006,294	)		(1,266,294	)
Foreign exchange changes		(29,518	)		(766,200	)
Asset retirement expenditures		(29,361	)		(23,956	)
Changes in operating assets and liabilities:
Foreign exchange changes		2,233			(8,652	)
Prepaid expenses		26,566			(22,146	)
Other receivables		80,956			706,517
Accounts payable and accrued liabilities		1,295,523			411,545
Cash used in operating activities		(3,567,810	)		(2,099,940	)

CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of property and equipment		-			(25,729	)
Oil and gas property expenditures		(16,255,639	)		(3,033,254	)
Restricted cash		(105,264	)		-
Cash advanced to operators for oil and gas property expenditures		(715,009	)		(677,842	)
Proceeds received from sale of oil and gas properties		976,900			1,544,460
Cash used in investing activities		(16,099,012	)		(2,192,365	)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of common stock for exercise of options		234,956			-
Proceeds from issuance of common stock		78,426,848			-
Common stock issuance costs		(6,127,597	)		-
Cash provided by financing activities		72,534,207			-

Foreign exchange change on cash		27,283			721,435

NET INCREASE (DECREASE) IN CASH		52,894,668			(3,570,870	)

CASH, BEGINNING OF YEAR		4,878,601			8,449,471

CASH, END OF YEAR	$	57,773,269		$	4,878,601

Non-cash investing activities
Additions to oil and gas properties through accounts payable and accrued liabilities	$	2,076,609		$	-

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

F-5

TRIANGLE PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED JANUARY 31, 2011 AND 2010

	Common Stock		Stock Amount		Additional Paid-in Capital			Warrants			Accumulated Deficit			Total Equity
Balance - January 31, 2009		6,992,692	$	70	$	81,156,344		$	4,237,100		$	(61,564,544	)	$	23,828,970
Stock-based compensation		-		-		794,361			-			-			794,361
Net loss for the year		-		-		-			-			(2,140,101	)		(2,140,101	)
Balance - January 31, 2010		6,992,692		70		81,950,705			4,237,100			(63,704,645	)		22,483,230

Exercise of stock options		79,167		1		234,956			-			-			234,957
Sale of stock at $3.30/share		2,799,394		28		9,237,972			-			-			9,238,000
Stock offering costs		-		-		(773,531	)		-			-			(773,531	)
Sale of stock at $4.30/share		204,419		2		879,000			-			-			879,002
Stock offering costs		-		-		(23,401	)		-			-			(23,401	)
Shares issued pursuant to termination agreement		30,000		-		180,000			-			-			180,000
Expiration of warrants		-		-		4,237,100			(4,237,100	)		-			-
Sale of stock at $5.50/share		12,420,000		124		68,309,876			-			-			68,310,000
Stock offering costs		-		-		(5,330,665	)		-			-			(5,330,665	)
Stock-based compensation		-		-		886,311			-			-			886,311
Net loss for the year		-		-		-			-			(20,277,197	)		(20,277,197	)
Balance - January 31, 2011		22,525,672	$	225	$	159,788,323		$	-		$	(83,981,842	)	$	75,806,706

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

F-6

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

As of and For the Years Ended January 31, 2011 and 2010

Note 1 - Nature of Operations

Triangle Petroleum Corporation (“Triangle” or the “Company”) is an exploration and development company currently focused on the acquisition and development of unconventional shale oil resources in the Bakken Shale and Three Forks formations in the Williston Basin of North Dakota and Montana. Triangle has identified an area of focus in the Bakken Shale and Three Forks formations.

The Company also owns acreage in the Maritimes Basin of Nova Scotia, which contains numerous conventional and unconventional prospective reservoirs, including the Windsor Group sandstones and limestones and Horton Group shales.

Note 2 - Summary of Significant Accounting Policies

Basis of Presentation

These financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America, and are expressed in U.S. dollars. These consolidated financial statements include the accounts of the Company and its two wholly-owned subsidiaries, Elmworth Energy Corporation, incorporated in the Province of Alberta, Canada, and Triangle USA Petroleum Corporation, incorporated in the State of Colorado, USA. All significant intercompany balances and transactions have been eliminated. The Company’s fiscal year-end is January 31.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of oil and natural gas reserves, assets and liabilities and disclosure on contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of oil and natural gas reserve quantities provide the basis for calculation of depletion, depreciation, and amortization, and impairment, each of which represents a significant component of the consolidated financial statements.

Foreign Currency Translation

The Company's functional currency is the United States dollar and these financial statements are stated in United States Dollars. Monetary assets and liabilities denominated in foreign currencies are translated into United States dollars at rates of exchange in effect at the balance sheet date and gains and losses are recorded in earnings. Non-monetary assets, liabilities and items recorded in income arising from transactions denominated in foreign currencies are translated at rates of exchange in effect at the date of the transaction. Foreign currency transactions are primarily undertaken in Canadian dollars. The Company has not, to the date of these financial statements, entered into derivative instruments to offset the impact of foreign currency fluctuations.

Cash

The Company considers all highly liquid instruments with maturity of three months or less at the time of acquisition to be cash equivalents.

Restricted cash consists of certificates of deposits maintained as cash collateral balances with Wells Fargo Bank.

Prepaid Drilling Costs

Included in prepaid drilling costs are cash advances of approximately $1.5 million paid to operators for future drilling costs. Upon commencement of drilling of a well, the prepayments are applied to the drilling costs which are capitalized to oil and natural gas properties. Due to the long-term nature of the costs, they are included in non-current assets.

Property and Equipment

Property and equipment consists of computer hardware, geophysical software, furniture and equipment and leasehold improvements, and is recorded at cost. Computer hardware and geophysical software are depreciated on a straight-line basis over their estimated useful lives of three years. Furniture and equipment and leasehold improvements are depreciated on a straight-line basis over their estimated useful lives of five years.

F-7

Oil and Natural Gas Properties

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration, development and estimated abandonment costs incurred for the purpose of acquiring and finding oil and natural gas are capitalized within cost centers. At January 31, 2011 and 2010, the Company had two cost centers – the United States and Canada. Unevaluated property costs are excluded from the amortization base until determination of the existence of proved reserves on the respective property or the requirement for impairment. Unevaluated properties are reviewed at the end of each quarter to determine whether portions of the costs should be reclassified to the full cost pool and thereby subject to amortization. Sales of oil and natural gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

Capitalized costs of oil and natural gas properties evaluated as having, or not having, proved reserves are amortized in the aggregate by country using the unit-of-production method based upon estimated proved oil and natural gas reserves. For amortization purposes, relative volumes of oil and natural gas production and reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Amortizable costs include estimates of future development costs of proved undeveloped reserves. The costs of properties not yet evaluated are not amortized until evaluation of the property. Such evaluations for a well and associated lease rights are made when it is determined whether or not the well has proved oil and natural gas reserves. Other unevaluated properties are evaluated for impairment as of the end of each calendar quarter based upon various factors at the time, including drilling plans, drilling activity, management’s estimated fair values of lease rights by project, and remaining lives of leases.

Capitalized costs of oil and natural gas properties (net of related deferred income taxes) may not exceed a ceiling amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved oil and natural gas reserves plus the cost of unevaluated properties (adjusted for related income tax effects). Should capitalized costs exceed this ceiling amount, the excess is charged to earnings as an impairment expense, net of its related reduction of the deferred income tax provision. The present value of estimated future net cash flows is computed by applying the twelve-month historical averages of prices of oil and natural gas to estimated future production of proved oil and natural gas reserves as of period-end, less estimated future expenditures (at period-end rates) to be incurred in developing and producing the proved reserves and assuming continuation of economic conditions existing at period-end. The present value of future net cash flows of proved reserves excludes future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet.

Impairment

Long-lived assets to be held and used are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Oil and natural gas properties accounted for using the full cost method of accounting are excluded from this requirement but continue to be subject to the full cost method’s impairment rules of SEC Regulation S-X Rule 4-10.

Asset Retirement Obligations

The Company recognizes a liability for future asset retirement obligations associated with the Company’s oil and natural gas properties. The estimated fair value of the asset retirement obligations are based on the estimated cost escalated using an inflation rate and discounted at the Company’s credit adjusted risk-free rate. This liability is capitalized as part of the cost of the related asset and amortized over its useful life. The liability accretes until the Company settles the obligation.

The following table reflects the change in asset retirement obligations for the years ended January 31, 2011 and 2010:

	2011			2010
Balance, beginning of year	$	1,180,515		$	727,862
Liabilities incurred		2,224			357,807
Liabilities settled		(29,361	)		(55,161	)
Accretion		250,319			150,007
Balance, end of year	$	1,403,697		$	1,180,515

Revenue Recognition

The Company recognizes oil and natural gas revenues from our interests in producing wells when production is delivered to, and title has transferred to, the purchaser and to the extent the selling price is reasonably determinable. Gas-balancing arrangements are accounted for using the sales method.

F-8

Accounts Receivable and Credit Policies

We have certain trade receivables consisting of oil and natural gas sales obligations due under normal trade terms. Management regularly reviews trade receivables and reduces the carrying amount by a valuation allowance that reflects the best estimate of the amount that may not be collectible. The Company wrote off $47,073 in uncollectible accounts receivable during fiscal 2011 and no uncollectible amounts were written off in fiscal 2010. As of January 31, 2011 and 2010, management had determined that no allowance for uncollectible receivables was necessary.

Income Taxes

The Company follows the asset and liability method for recording deferred income taxes. Under this method, deferred taxes are recognized based on temporary differences at the balance sheet date using the enacted tax rates. The Company is required to compute tax asset benefits for net operating losses carried forward. Potential benefits of deferred income tax assets are not recognized in the accounts until realization is more likely than not. As of January 31, 2011 and 2010, the Company did not have any amounts recorded pertaining to uncertain tax positions.

The Company files federal and provincial income tax returns in Canada and federal, state and local income tax returns in the U.S., as applicable. The Company may be subject to a reassessment of federal and provincial income taxes by Canadian tax authorities for a period of four years from the date of the original notice of assessment in respect of any particular taxation year. For Canadian income tax returns, the open tax years range from 2007 to 2011. The U.S. federal statute of limitations for assessment of income tax is closed for the tax years ending on or prior to January 31, 2007. In certain circumstances, the U.S. federal statute of limitations can reach beyond the standard three year period. U.S. state statutes of limitations for income tax assessment vary from state to state. Tax authorities of Canada and U.S. have not audited any of the Company’s, or its subsidiaries’, income tax returns for the open taxation years noted above.

The Company recognizes interest and penalties related to uncertain tax positions in tax expense. During the years ended January 31, 2011 and 2010, there were no charges for interest or penalties.

Basic and Diluted Earnings Per Share (“EPS”)

Basic EPS is computed by dividing net loss available to common stock (numerator) by the weighted average number of shares outstanding (denominator) during the period. Diluted EPS gives effect to all dilutive instruments outstanding during the period including stock options and warrants, using the treasury stock method. In computing diluted EPS, the average stock price for the period is used in determining the number of shares assumed to be purchased from the exercise of stock options or warrants. Diluted EPS excludes instruments if their effect is anti-dilutive.

Fair Value of Financial Instruments

The fair values of financial instruments, which include cash, restricted cash, other receivables, accounts payable and accrued liabilities approximate their carrying values due to the relatively short time to maturity of these instruments.

Concentration of Risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash. We maintain substantially all cash assets at three financial institutions, Wells Fargo bank, Chase Bank and Royal Bank of Canada. We periodically evaluate the credit worthiness of financial institutions, and maintain cash accounts only in large high quality financial institutions. We believe that credit risk associated with cash is remote. The Company is exposed to credit risk in the event of nonpayment by counter parties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counter parties is subject to continuing review.

Segment Reporting

Operating segments are components of an enterprise about which separate financial information is available that is evaluated regularly by the Company in deciding how to allocate resources and in assessing performance. The financial information is required to be reported on the basis that is used internally for evaluating segment performance and deciding how to allocate resources to segments. The Company operates in one segment, oil and natural gas producing activities.

F-9

Stock-Based Compensation

The Company records stock-based compensation based on the estimated fair values of all stock-based awards made to employees, consultants and directors. All transactions in which goods or services are received for the issuance of equity instruments are accounted for based on the fair value of the consideration received or the fair value or the equity instrument issued, whichever is the more reliable measure.

The fair value of stock-based awards is estimated on the date of grant using the Black-Scholes option pricing model. This model is affected by the Company’s stock price as well as assumptions regarding a number of subjective variables. These subjective variables include, but are not limited to the Company’s expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise behaviors. The value of the portion of the award that is ultimately expected to vest is recognized as an expense in the consolidated statement of operations over the requisite service period.

Reclassification

Certain amounts in the 2010 consolidated financial statements have been reclassified to conform to the 2011 financial statement presentation. Such reclassifications have no effect on net loss.

Recent Accounting Pronouncements

The Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") 2010-03, Extractive Activities—Oil and Gas (Topic 932), to amend existing oil and natural gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules. The significant modifications involve revised definitions of oil and natural gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month average of the first day of the month prices and additional disclosure requirements. In contrast to the applicable SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and natural gas information in the notes to the financial statements. In April 2010, the FASB issued ASU 2010-14 which amends the guidance on oil and natural gas reporting in Accounting Standards Codification (“ASC”) 932.10.S99-1 by adding the Codification SEC Regulation S-X, Rule 4-10 as amended by the SEC Final Rule 33-8995. Both ASU 2010-03 and ASU 2010-14 are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments. This new authoritative guidance became effective for periods ending on or after September 15, 2009, and did not have a material impact on the Company’s consolidated financial statements.

The FASB has issued ASU No. 2010-13, Compensation—Stock Compensation (Topic 718): Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades. This ASU codifies the consensus reached in EITF Issue No. 09-J, "Effect of Denominating the Exercise Price of a Share-Based Payment Award in the Currency of the Market in Which the Underlying Equity Security Trades." The amendments to the Codification clarify that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity shares trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity would not classify such an award as a liability if it otherwise qualifies as equity. This rule will not have a material impact on the Company’s financial position or results of operations.

F-10

Note 3 - Property and Equipment

Property and equipment as of January 31, 2011 and 2010 consisted of the following:

	2011			2010
Oil and gas properties, full cost method:
Unevaluated costs, not yet subject to amortization	$	15,206,667		$	18,783,375
Evaluated costs		7,023,218			-
		22,229,885			18,783,375
Less accumulated amortization		(96,000	)		-
Net carrying value of oil and gas properties		22,133,885			18,783,375
Cost of other property and equipment		-			176,615
Less accumulated depreciation and amortization		-			(137,319	)
Net property and equipment	$	22,133,885		$	18,822,671

Total property and equipment located in the United States	$	18,133,885		$	-
Total property and equipment located in Canada	$	4,000,000		$	18,822,671

On December 7, 2010, the Company finalized the first closing on an agreement to acquire substantially all the assets of Williston Exploration LLC (“Williston”) which includes approximately 1,732 net undeveloped acres in Williams County, North Dakota. Total consideration for the acquisition was approximately $2.2 million of cash which was paid on the first closing and 433,500 shares of common stock to be issued on the second closing, which is expected to occur on February 15, 2011.

During fiscal 2011, the Company sold an existing wellbore and associated acreage in Alberta for $977,000 plus the associated asset retirement obligation of $29,294. The carrying amount of this property had previously been written off and a gain on sale of oil and natural gas properties of $1,006,294 was recorded.

In January 2010, the Company sold its interests in an Alberta gas well and 896 gross acres of undeveloped land (108 net acres) for gross proceeds of $426,600. The net book value of the Canadian full cost pools subject to depletion at the time of the sale was $273,666. As such, the Company recorded a gain on the sale of assets of $152,934.

In June 2009, the Company sold its 25% working interest in 17,307 gross acres (4,327 net acres) of undeveloped land in the Nugget area of Colorado (Rocky Mountains project) for cash of $83,325 and recovered a drilling deposit in the Fayetteville area of Arkansas for cash of $50,000. The net book value of the U.S. properties at the time of sale was $8,704. As such, the Company recorded a gain on sale of assets of $124,621.

In September 2009, the Company sold its 50% working interest in 11,800 gross acres (5,900 net acres) of undeveloped land in the Fayetteville area of Arkansas and all the related seismic rights for net cash proceeds of $744,408. The acquirer also assumed the non-cash asset retirement obligations pertaining thereto of $39,375. The net book value of the U.S. properties at the time of sale was $171. As such, the Company recorded a gain on sale of assets of $783,612.

In November 2009, the Company sold its 50% working interest in its remaining 6,760 gross acres (3,880 net acres) of undeveloped land in the Fayetteville area of Arkansas for net cash proceeds of $240,127. The net book value of the U.S. properties at the time of sale was $35,000. As such, the Company recorded a gain on sale of assets of $205,127.

During fiscal 2011, an impairment cost of $14,917,356 was recorded in connection with the Company’s property in the Maritimes Basin of Nova Scotia. The Company assesses all unproved property for possible impairment annually or upon a triggering event. The assessment includes consideration of, among others, intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, and the assignment of proved reserves. The circumstances that contributed to the impairment included the lack of immediate funding allocated to the project, the belief that the carrying amounts may not be recoverable and the lack of proved reserves attributable to the property.

F-11

The costs incurred in oil and natural gas acquisition, exploration and development activities in fiscal 2011 follow:

Property acquisition	$	13,654,462
Development		4,709,404
Exploration		-

Total	$	18,363,866

Note 4 - Income Taxes

Income tax expense differs from the amount that would result from applying the U.S federal, state and Canadian income tax rates to the loss before income taxes. The reconciliation of the provision for income taxes to the expected tax provision based on the loss for the year multiplied by the statutory tax rate of 38% for fiscal 2011 and 2010 is as follows:

	2011			2010
Expected income tax benefit	$	7,705,335		$	813,238
Permanent differences		(19,597	)		(301,857	)
Difference in foreign tax rates		(1,936,736	)		(120,434	)
Change in tax rates		-			(557,126	)
Changes in valuation allowance		(5,866,580	)		1,066,015
Other		117,578			(899,836	)
Provision for income taxes	$	-		$	-

The significant components of the Company’s deferred tax assets and liabilities as of January 31, 2011 and 2010 are as follows:

	2011			2010
Deferred income tax assets:
Current:
Uncollectible accounts receivable	$	17,888		$	-
Non-Current:
Oil and natural gas properties		3,485,083			2,397,706
Net losses carried forward		16,670,848			12,769,031
Asset retirement obligations		363,109			299,486
Stock-based compensation		638,657			-
Property and equipment		157,219			-
Gross deferred income tax assets		21,332,804			15,466,223
Valuation allowance		(21,332,804	)		(15,466,223	)
Net deferred income tax asset	$	-		$	-

As of January 31, 2011, the Company had a net operating loss carry forward for regular income tax reporting purposes which will begin expiring in 2023.

In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the use of such net operating losses are allowed. Among other items, management considers the scheduled reversal of deferred tax liabilities, tax planning strategies and projected future taxable income.

F-12

Note 5 - Stockholders’ Equity

Common Stock

The Consolidated Statement of Stockholders’ Equity provides a listing of changes in the common stock outstanding from February 1, 2009 to January 31, 2011.

In March 2010, the Company issued 2,799,394 shares of common stock in a private offering for gross proceeds of $9,238,000. The Company paid $773,531 in expenses related to this offering.

In August 2010, the Company issued 204,419 shares of common stock in a private offering for gross proceeds of $879,002. The Company paid $23,401 in expenses related to this offering.

In November 2010, the Company issued 12,420,000 shares of common stock in a public offering for gross proceeds of $68,310,000. The Company paid $5,330,665 in expenses related to this offering.

On November 5, 2010, Triangle’s common stock began trading on the NYSE Amex LLC (“NYSE Amex”) under the symbol "TPLM." In connection with its listing on the NYSE Amex, the Company's common stock ceased trading on the OTC Bulletin Board. The Company's shares of common stock were also delisted from the TSX Venture Exchange effective April 1, 2011. The Company also underwent a 1-for-10 reverse stock split which became effective for trading purposes as of November 5, 2010. Share numbers throughout the financial statements have been retrospectively adjusted to reflect this stock split.

Warrants

As of January 31, 2010, the Company had 9,128,750 warrants outstanding that could be exercised for 9,128,750 shares of common stock at a price of $2.25 per share. These warrants expired on June 3, 2010. There are no warrants outstanding as of January 31, 2011.

Stock Options

Effective August 5, 2005, the Company approved the 2005 Incentive Stock Plan (the “2005 Plan”) to issue up to 2,000,000 shares of common stock. Effective August 17, 2007, the Company approved the 2007 Incentive Stock Plan (the “2007 Plan”) to issue up to 2,000,000 shares of common stock. Pursuant to the 2005 Plan and 2007 Plan, stock options vest 20% upon granting and 20% every six months, and allowed for the granting of stock options at a price of not less than fair value of the stock and for a term not to exceed five years. As of January 31, 2009, the Company had no stock options available for granting pursuant to the 2005 Plan and 2007 Plan since, in connection with the TSX Venture Exchange listing in December 2008, the Company agreed it would not issue any more stock options under the 2005 Plan and 2007 Plan.

Effective January 28, 2009, the Company’s board of directors approved a Stock Option Plan (the “Rolling Plan”) whereby the number of authorized but unissued shares of common stock that may be issued upon the exercise of stock options granted under the Rolling Plan at any time plus the number of shares of common stock reserved for issuance under the outstanding 2005 Plan and the 2007 Plan shall not exceed 10% of the issued and outstanding shares of common stock on a non-diluted basis at any time, and such aggregate number of shares of common stock shall automatically increase or decrease as the number of issued and outstanding shares of common stock change. Pursuant to the Rolling Plan, stock options become exercisable as to one-third on each of the first, second and third anniversaries of the date of the grant, and allow for the granting of stock options at a price of not less than fair value of the common stock and for a term not to exceed ten years. As of January 31, 2011 and 2010, the Company had 1,909,225 and 1,292,604 stock options, respectively, available for granting pursuant to the Rolling Plan.

All stock options outstanding are those issued under the 2009 Rolling Plan. The following table summarizes the status of stock options outstanding under the plan:

F-13

	Number of Shares			Weighted Average Exercise Price
Options outstanding - January 31, 2009 (146,000 exercisable)		498,500		$	11.40
Options granted		305,000		$	1.40
Less options canceled		(5,000	)	$	14.00
Less options forfeited		(228,500	)	$	13.50
Options outstanding - January 31, 2010 (183,667 exercisable)		570,000		$	5.20
Less: options canceled		(85,000	)	$	27.80
Less options forfeited		(62,500	)	$	17.30
Less options exercised		(79,167	)	$	3.00
Options outstanding - January 31, 2011 (125,833 exercisable)		343,333		$	1.60

The weighted average grant date estimated fair value of stock options granted during fiscal 2010 was $1.00 per underlying share of common stock. During the years ended January 31, 2011 and 2010, the Company recorded stock-based compensation related to stock option grants of $93,418 and $794,361, respectively, as general and administrative expense.

The following table presents additional information related to the stock options outstanding at January 31, 2011 under the 2009 Rolling Plan:

				Number of Shares
Exercise price per share		Remaining contractual life (years)		Outstanding		Exercisable
$	3.00		3.08		63,333		32,500
$	1.30		3.83		280,000		93,333
					343,333		125,833

Weighted average exercise price per share				$	1.60	$	1.70
Weighted average remaining contractual life					3.69		3.63
Aggregate intrinsic value, January 31, 2011				$	397,741	$	214,167

F-14

There were no stock options granted in fiscal 2011. The following assumptions were used in the Black-Scholes model for options granted in fiscal 2010:

Expected option life (in years)	4.0
Expected annual volatility over option life	130	%
Risk-free interest rate	1.60	%
Forfeiture rate	30	%
Dividend yield	0	%

As of January 31, 2011 and 2010, there was $244,496 and $468,260, respectively, of total unrecognized compensation costs related to non-vested stock-based compensation arrangements granted under the stock option plans which are expected to be recognized over a weighted-average period of 2.0 and 2.6 years, respectively.

A summary of the status of the Company’s non-vested options as of January 31, 2011, and changes during the years ended January 31, 2011 and 2010, is presented below:

	Number of Shares			Weighted- Average Grant Date Fair Value
Non-vested options - January 31, 2009		352,500		$	3.10
Options granted		305,000		$	1.00
Options vested		(171,167	)	$	3.90
Less options canceled		(1,000	)	$	7.80
Less options forfeited		(99,000	)	$	2.80
Non-vested options - January 31, 2010		386,333		$	1.10
Options vested		(115,833	)	$	1.20
Less options canceled		(3,000	)	$	-
Less options forfeited		(50,000	)	$	1.70
Non-vested options - January 31, 2011		217,500		$	1.10

Restricted Stock

During fiscal 2011, the Company awarded restricted stock to officers, directors and employees of the Company. These awards will not become effective until the 2011 Omnibus Incentive Plan (the “2011 Plan”) is approved by Triangle stockholders at the Company’s next annual general meeting. Once the 2011 Plan is approved, the restricted stock will vest based on the pre-established vesting timeline subject to the continued service of the executives, directors and employees. The restricted stock vests over a period of between one and three years. The following table summarizes the status of restricted stock outstanding:

	Number of Shares		Weighted-Average Award Date Fair Value
Restricted stock outstanding - January 31, 2010		-
Restricted stock granted - one year vesting		393,636	$	4.62
Restricted stock granted - three year vesting		116,000	$	5.63
Restricted stock outstanding - January 31, 2011		509,636

The NYSE Amex requires that all grants of options and awards of restricted stock be issued under a plan approved by stockholders. Therefore, 213,636 shares of restricted stock that were awarded after November 5, 2010 are not approved awards under the NYSE Amex rules. Because of this, stock-based compensation for these awards has not been recorded. At the time the 2011 Plan is approved by the Company’s stockholders and ratified by its board of directors, compensation expense will be recognized based on the original vesting schedule. The restricted stock will be valued at the market value on the date the 2011 Plan is approved and ratified for purposes of calculating stock-based compensation.

F-15

Prior to being listed on the NYSE Amex, grants of options and awards of restricted stock were not required to be issued under a plan approved by the stockholders; although the grants and awards still do not become effective until a plan is approved. Therefore, stock-based compensation was recognized on all grants and awards that occurred prior to November 5, 2010. Awards of restricted stock prior to listing on the NYSE Amex were valued at the trading price of Triangle’s common stock at the date of award. The Company recognized $792,893 of stock-based compensation in fiscal 2011 related to restricted stock awards prior to November 5, 2010. As of January 31, 2011, $406,507 of compensation expense related to all unvested restricted stock awards (granted prior to listing on the NYSE Amex) remained to be recognized. This expense is expected to be recognized over a weighted-average period of 1.64 years.

Note 6 - Commitments

Office and Equipment Leases

The Company leases office facilities in Denver, Colorado and Calgary, Alberta, Canada under operating lease agreements that both expire in September 2013. Rent expense was $94,351 and $519,416 for the years ended January 31, 2011 and 2010, respectively.

The Company also leases office equipment under an operating lease that expires in 2014.

The following table shows the annual rentals per year for the life of the leases:

Fiscal year ending January 31,	Annual Rental Amount
2012	$	74,880
2013	$	76,065
2014	$	52,428

Note 7 - Subsequent Events

In March 2011, the Company completed the offering of 18,975,000 shares of common stock at a price of $7.50 per share for gross proceeds of $142.3 million. The net proceeds to the Company of this offering, after deducting underwriting discounts and commissions and other estimated offering expenses, is expected to be approximately $134.3 million.

On March 14, 2011, the Company acquired approximately 7,700 undeveloped net acres in McKenzie County, North Dakota for aggregate consideration of approximately $34.1 million in cash, subject to customary purchase price adjustments. Based on our initial due diligence, management believes the Company will only acquire approximately 6,500 net acres, as 1,200 net acres are being conveyed in the form of a top lease, which may not vest due to an existing well producing on the underlying leases in question, which are held by another operator. In the event the top lease does not vest, the purchase price may be adjusted downward to $28.6 million.

On April 1, 2011, to the Company acquired approximately 6,716 undeveloped net acres in Williams County, North Dakota for aggregate consideration, subject to customary purchase price adjustments, of approximately $14.5 million in cash and 1,004,199 shares of common stock.

On February 15, 2011, the Company issued 433,500 shares of common stock to Williston Exploration LLC in the second closing of the Williston acquisition.

On March 16, 2011, the Company signed a contract to lease 9,144 square feet of office space in Denver, Colorado. The lease term is 39 months, the anticipated commencement date is April 15, 2011 and the annual rentals per year for the life of the lease are as follows:

Lease period	Annual Rental Amount
Months 1 through 15	$	237,744
Months 16 through 27	$	242,316
Months 28 through 39	$	246,888

Subsequent to January 31, 2011 the Company’s board of directors awarded, subject to stockholder approval of the 2011 Plan, 1,625,836 shares of restricted stock to certain officers, directors and employees of the Company.

F-16

Subsequent to January 31, 2011, the Company issued 4,167 shares of common stock pursuant to the exercise of stock options.

Note 8 - Information Regarding Proved Oil and Natural Gas Reserves (Unaudited)

As defined by SEC Regulation S-X 4-10, proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas (and, in some cases, natural gas liquids) which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (i) from a given date forward, from known reservoirs, and under existing economic and operating conditions, operating methods, and government regulations and (ii) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that contract renewal is reasonably certain. Existing economic conditions with regards to a crude oil or natural gas selling price is the average price during the twelve-month period prior to the given date, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

As defined by SEC Regulation S-X 4-10, proved developed oil and natural gas reserves include those proved reserves expected to be recovered through existing wells with existing equipment and operating methods. See SEC Regulation S-X 4-10 for the complete SEC definition of proved developed oil and natural gas reserves.

The determination of oil and natural gas reserves is highly complex and interpretive. The estimates are subject to continuing change as additional information becomes available.

All of Triangle’s proved oil and natural gas reserves are located within the continental United States as of January 31, 2011. MHA Petroleum Consultants (“MHA”), an independent petroleum engineering firm, determined the Company’s estimated proved oil and natural gas reserves as of January 31, 2011 which are summarized in this note. The Company did not obtain a reserve report at January 31, 2010 as the proved reserves were not considered material. MHA determined the projected future cash flows from those proved reserves and the present value, discounted at 10% per annum, of those future cash flows reflected in this note, except for cash outflows for income taxes. In estimating reserves, MHA used the SEC definition of proved oil and natural gas reserves. Projected future cash flows are based on economic and operating conditions as of January 31, 2011.

Using Company data and MHA’s estimates of proved reserves and future cash flows as of the fiscal year-end management determined for fiscal 2011 (i) the changes in proved reserves, (ii) the future income tax expense amounts in the Standardized Measure and (iii) the changes in the Standardized Measure, disclosed in the tables below.

Estimated net quantities of proved developed and undeveloped reserves of oil and natural gas for the years ended January 31, 2011 and 2010, respectively, are presented in table below.

	Oil (MBbls)								Gas (MMcf)									Liquids (MBbls)								Total (Boe)
	Canada		US			Total			Canada			US			Total			Canada			US		Total			Canada			US			Total

Proved reserves, February 1, 2009		-		-			-			42			56			98			1,178			-		1,178			1,185			9			1,194
Revisions of previous estimates		-		-			-			(20	)		(38	)		(58	)		-			-		-			(3	)		(6	)		(10	)
Sales of reserves		-		-			-			(5	)		-			(5	)		(334	)		-		(334	)		(335	)		-			(335	)
Production		-		-			-			(17	)		(18	)		(35	)		(844	)		-		(844	)		(847	)		(3	)		(850	)
Proved reserves, February 1, 2010		-		-			-			-			-			-			-			-		-			-			-			-
Discoveries		-		1,239			1,239			-			-			-			-			-		-			-			1,239			1,239
Sales of reserves		-		-			-			-			-			-			-			-		-			-			-			-
Production		-		(4	)		(4	)		-			-			-			-			-		-			-			(4	)		(4	)
Proved reserves, January 31, 2011		-		1,235			1,235			-			-			-			-			-		-			-			1,235			1,235

Proved developed reserves at January 31, 2011:																																	214
Proved Undeveloped Reserves at January 31, 2011:																																	1,021

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

RELATING TO PROVED OIL AND NATURAL GAS RESERVES

The “Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves” (standardized measure) is a disclosure required under U.S. GAAP. The standardized measure does not purport to present the fair market value of a Company’s proved oil and natural gas reserves. In addition, there are uncertainties inherent in estimating quantities of proved reserves.

F-17

The following table is the standardized measure relating to proved oil and natural gas reserves of January 31, 2011:

Future cash inflows	$	84,954
Future Costs:
Production		(19,054	)
Development		(20,003	)
Future income tax expense		(2,627	)
Future net cash flows		43,270
10% discount factor		(30,403	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	12,867

The principal sources of changes in the standardized measure of discounted future net cash flows during the year ended January 31, 2011, are as follows:

Balance at beginning of period	$	-
Extensions and discoveries		18,959
Net change in future development costs		(5,735	)
Net change in prices and production costs		(68	)
Net change in income taxes		(290	)
Other		1
Balance at end of period	$	12,867

Future cash inflows were estimated by applying the 12 month arithmetic average first of month price from February, 2010 to January 2011, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. The price used for the standardized measures above was $68.76 per barrel for oil in 2011. Future production and development costs (including the estimated asset retirement obligations) are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to oil and natural gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of the Company’s proved oil and natural gas properties.

F-18

SIGNATURES

In accordance with the requirements of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

TRIANGLE PETROLEUM CORPORATION

Date: April 19, 2011	By:	/s/ PETER HILL
	Peter Hill
	Chief Executive Officer (Principal Executive Officer)

Date: April 19, 2011	By:	/s/ JONATHAN SAMUELS
	Jonathan Samuels
	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Peter Hill and Jonathan Samuels, jointly and severally, his or her attorney-in-fact, with the power of substitution, for him or her in any and all capacities, to sign any amendments to this annual report on Form 10-K and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorneys-in-fact, or his or her substitute or substitutes, may do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this annual report on Form 10-K has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Name	Position	Date

/s/ PETER HILL	Chief Executive Officer (Principal Executive Officer)	April 19, 2011
Peter Hill	and Director

/s/ JONATHAN SAMUELS	Chief Financial Officer (Principal Financial Officer and	April 19, 2011
Jonathan Samuels	Principal Accounting Officer), and Director

/s/ F. GARDNER PARKER	Director	April 19, 2011
F. Gardner Parker

/s/ STEPHEN A. HOLDITCH	Director	April 19, 2011
Stephen A. Holditch

/s/ RANDAL MATKALUK	Director	April 19, 2011
Randal Matkaluk

Exhibit No.		Description

3.1		Articles of Incorporation, as amended, effective as of November 4, 2010, filed as an exhibit to the Registration Statement on Amendment No. 3 on Form S-1 filed with the Securities and Exchange Commission on November 4, 2010 and incorporated herein by reference.

3.2		Second Amended and Restated Bylaws, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 5, 2010 and incorporated herein by reference.

4.1		Specimen Common Stock Certificate, filed as an exhibit to the Registration Statement on Amendment No. 1 on Form S-1 filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.

10.01		Stock Option Plan, filed as an exhibit to the Registration Statement on Form S-8 filed with the Securities and Exchange Commission on January 31, 2011 and incorporated herein by reference.

10.02		Production Lease, dated as of April 15, 2009, by and between the Company and Her Majesty the Queen in the Right of the Province of Nova Scotia, filed as an exhibit to the Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on April 20, 2009 and incorporated herein by reference.

10.03		Overriding Royalty Agreement, dated as of June 10, 2009, by and between Elmworth Energy Corporation and Contact Exploration Inc., filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 2, 2009 and incorporated herein by reference.

10.04		Amended and Restated Employment Agreement, dated as of December 2, 2010, by and between Triangle Petroleum Corporation and Dr. Peter Hill, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 6, 2010 and incorporated herein by reference.

10.05		Amended and Restated Employment Agreement, dated as of December 2, 2010, by and between Triangle Petroleum Corporation and Jonathan Samuels filed as an exhibit to the Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 6, 2010 and incorporated herein by reference.

10.06		Deferred Share Unit Agreement, dated February 2, 2010 between Triangle Petroleum Corporation and Peter Hill, filed as an exhibit to the Registration Statement on Amendment No. 1 to Form S-1 filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.

10.07		Deferred Share Unit Agreement, dated February 2, 2010 between Triangle Petroleum Corporation and Jonathan Samuels, filed as an exhibit to the Registration Statement on Amendment No. 1 to Form S-1 filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.

10.08		Form of Deferred Share Unit Agreement entered into by each of Gardner Parker, Randal Matkaluk and Steve Holditch, each dated February 2, 2010, filed as an exhibit to the Registration Statement on Amendment No. 2 to Form S-1 filed with the Securities and Exchange Commission on November 2, 2010 and incorporated herein by reference.

14.01		Code of Business Conduct and Ethics, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.

21.01*		List of Subsidiaries.

23.02*		Consent of MHA Petroleum Consultants.

24.01		Power of Attorney (incorporated by reference to the signature page of this Annual Report on Form 10-K).

31.01*		Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.02*		Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.01*		Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.01*		Reserve Estimate Report of MHA Petroleum Consultants.

* Filed herewith.

Triangle Petroleum Corp - FORM 10-K - April 19, 2011

Attached files

Triangle Petroleum Corp Reports