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EX-10.12 - Triangle Petroleum Corpv180495_ex10-12.htm
EX-23.01 - Triangle Petroleum Corpv180495_ex23-01.htm
EX-32.01 - Triangle Petroleum Corpv180495_ex32-01.htm
EX-31.01 - Triangle Petroleum Corpv180495_ex31-01.htm
EX-10.11 - Triangle Petroleum Corpv180495_ex10-11.htm
EX-31.02 - Triangle Petroleum Corpv180495_ex31-02.htm
EX-14.02 - Triangle Petroleum Corpv180495_ex14-02.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the Fiscal Year Ended January 31, 2010

Commission File Number 000-51321
TRIANGLE PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Nevada
 
98-0430762
(State or other jurisdiction of incorporation
or organization)
 
(IRS Employer Identification No.)

Suite 750, 521 - 3 Avenue SW
Calgary, Alberta, Canada
T2P 3T3
(403) 262-4471
(Address of principal executive office)
(Zip Code)
(Registrant’s telephone number,
including area code)
     
Securities registered pursuant to Section 12(b) of the Act:  None.

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

Title of each class
Name of each exchange on which registered
Common Stock, $0.0001 par value
Over-the-Counter Bulletin Board

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

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§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.   o

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

 Large accelerated filer o
 Accelerated filer o 
 Non-accelerated filer o 
 Smaller reporting company x
(Do not check if a smaller reporting company)
 

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

The aggregate market value of the voting common equity held by non-affiliates as of July 31, 2009, based on the closing sales price of the Common Stock as quoted on the Over-the-Counter Bulletin Board was $6,553,069. 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 8, 2010, there were 97,919,982 shares of registrant’s common stock outstanding.

 
 

 

TRIANGLE PETROLEUM CORPORATION
FORM 10-K
For the Fiscal Year Ended January 31, 2010

Part I
   
Page
     
Item 1.
Business
3
     
Item 1A.
Risk Factors
9
     
Item 1B.
Unresolved Staff Comments
16
     
Item 2.
Properties
16
     
Item 3.
Legal Proceedings
19
     
Item 4.
RESERVED
19
     
Part II
   
Page
     
Item 5.
Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
20
     
Item 6.
Selected Financial Data
21
     
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
21
     
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
27
     
Item 8.
Financial Statements and Supplementary Data
F-1
     
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
28
     
Item 9A.
Controls and Procedures
28
     
Item 9B.
Other Information
29
     
Part III
   
Page
     
Item 10.
Directors, Executive Officers and Corporate Governance
30
     
Item 11.
Executive Compensation
33
     
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
36 
     
Item 13.
Certain Relationships and Related Transactions, and Director Independence
37
     
Item 14.
Principal Accounting Fees and Services
37
     
Part IV
   
Page
      
Item 15.
Exhibits; Financial Statement Schedules
39
     
Signatures.
41

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PART I

FORWARD-LOOKING INFORMATION

This Annual Report of Triangle Petroleum Corporation on Form 10-K includes a number of forward-looking statements that reflect the current views of our management 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 our and members of our management team’s intent, belief or current expectations 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.

ITEM 1.  BUSINESS.

OVERVIEW

We are an oil and gas exploration and development company focused primarily on the acquisition, exploration and development of resource properties consisting mainly of unconventional oil and gas reserves. We have recently undertaken a new strategic investment strategy in the Bakken Shale play in North Dakota with our entry into a joint participation agreement, effective January 15, 2010 (the “Slawson Agreement”), with Slawson Exploration Company, Inc. (“Slawson”), aimed at the acquisition and development of acreage in known areas of production in McKenzie and Williams Counties of North Dakota. In addition, we have interests in the Maritimes Basin in the Province of Nova Scotia. See “Our Operations” below.

RECENT TRANSACTIONS

In November 2009, Palo Alto Investors, Inc. (“Palo Alto”), our largest shareholder, initiated discussions with us regarding the potential for several proactive measures, including changes to our board of directors (the “Board”) and management and other strategic alternatives. On November 30, 2009, we entered into a memorandum of understanding with a fund managed by Palo Alto, providing for the restructuring of the Board and management, as well as our intention to consider changes in our strategic direction and certain related matters.

As part of this memorandum of understanding, on November 30, 2009, we restructured the Board and senior management team. Three new directors were appointed on November 30, 2009, including Gardner Parker, who was appointed Chairman of the Board, Dr. Peter Hill and Jonathan Samuels. Two former directors also resigned from the Board. The Board is currently comprised of five directors, each of whom, other than Dr. Hill and Mr. Samuels, is independent under Canadian securities laws.

The Board also immediately restructured our senior management team. As part of the memorandum of understanding with Palo Alto, Dr. Hill was appointed our new Chief Executive Officer and Mr. Samuels was appointed our new Chief Financial Officer.

The Board and our senior management team have extensive knowledge of the oil and natural gas industry, and have broad experience in acquiring early stage oil and natural gas projects and exploring and developing oil and natural gas projects. Our officers and directors also have extensive experience in raising capital through the public equity markets and project finance.   See “Item 10: Directors, Executive Officers and Corporate Governance” for biographical information on our officers and directors.

In March 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, yielding aggregate gross proceeds to us of approximately $9,238,000 and net proceeds of approximately $8,300,000.

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OUR OPERATIONS

During fiscal 2010, we continued our exploration operations in the Maritimes Basin of Eastern Canada on our Windsor Block. In the first half of fiscal 2010, we finished the second phase of our Windsor Block exploration program by completing three gross wells (1.71 net). In the second half of fiscal 2010, we acquired 30 kilometers of 2D seismic on the Windsor Block.

During fiscal 2010, we had two producing wells in the Alberta Deep Basin, Canada, and three producing wells in the Barnett Shale of Texas, U.S.A.

We refer you to “Item 2: Properties”, of this Form 10-K for a more detailed discussion our properties and their operations.

Williston Basin

The Bakken Shale play in the Williston Basin is our core area of operations in the United States. Having identified what we believe is the prime Bakken Shale fairway, we are continuing to explore further opportunities in the region. We are constantly reviewing potential transactions and are actively pursuing the acquisition of additional leases and acreage in North Dakota in furtherance of our new strategic direction, with an ongoing acreage acquisition program targeting 1,000 acres per month.

We have entered into the Slawson Agreement to acquire and develop acreage in known areas of production from the Middle Bakken Shale and Three Forks formations. Our acreage is located in the Rough Rider area of the play, primarily McKenzie and Williams Counties, North Dakota and consists of several drill-ready locations. Under the terms of the Slawson Agreement, we have agreed to participate with a 30% working interest in the exploration and development of certain oil and gas leasehold interests acquired by Slawson (the “Project”).

As part of the Slawson Agreement, we have agreed to pay our participation interest share of all costs incurred in the Project, plus (i) an additional amount equal to 20% to 60% of our costs directly attributable to lease acquisitions, which amount depends on the bonus cost of a lease per net acre, (ii) an additional amount equal to 50% of our share of brokerage costs and other leasehold costs except those direct lease costs set out above and except those included in an applicable authorization for expenditure, and (iii) an additional 10% of our share in costs proposed in the applicable authorizations for expenditure for wells drilled under the Slawson Agreement.

The Slawson Agreement also provides that Slawson will generally be responsible for initiating well proposals, provided that we may recommend the drilling of a well upon land which we own an interest in the leases. If a party to the Slawson Agreement elects not to participate in a proposed well, then, subject to certain condition, it forfeits all rights within the spacing unit boundaries for such well, plus all contiguous sections. The Slawson Agreement also sets out a form of joint operating agreement, pursuant to which all wells initiated under the Slawson Agreement are to be operated.

Through the signing of the Slawson Agreement, awards at a recent North Dakota state lease sale, and the on-going success of our joint leasing program, we have acquired approximately 13,000 gross (4,000 net) acres at a total cost to us of $2.9 million. We are currently budgeting an additional minimum $7.0 million to acquire additional leases in the Bakken Shale play in the Williston Basin over the remainder of 2010. Under the terms of the Slawson Agreement, we have the ability to limit our participation to no more than $25 million in any 12-month period for total gross acreage acquisition capital, of which we are 30%. However, this limitation may be exceeded at our option.

Eastern Canadian Shale Gas Project (Windsor Block)

We have an 87% working interest in 474,625 gross acres (412,924 net acres) in the Windsor Sub-Basin of the Maritimes Basin located in the Province of Nova Scotia, Canada (the “Windsor Block”) and serve as operator of the Windsor Block. Until April 15, 2009, the land was governed by an exploration agreement between us and the Province of Nova Scotia. On April 15, 2009, the Windsor Block exploration agreement was transferred to a 10-year production lease. We acquired an additional 30% working interest in the Windsor Block in June 2009 from Contact Exploration Inc. (“Contact”) in exchange for a 5.75% non-convertible gross overriding royalty interest, a cash payment of Cdn $270,000 and our assumption of the liabilities related to the former working interest of Contact. This acquisition increased our working interest to its current 87% level.

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In October 2009, we acquired 30 kilometers of 2D seismic 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 three completion operations on previously drilled vertical exploration wells, satisfied the first-year requirements of our 10-year production lease.

We are continuing to evaluate the anticipated performance and viability of our working interest in the Windsor Block. In moving forward with such property, we intend to consider a range of options pursuant to our existing production lease.

COMPETITORS

In the Willison Basin in North Dakota, we compete with a number of larger public and private companies such as Continental Resources, Brigham Exploration, XTO Energy (now part of Exxon-Mobil), and Whiting Petroleum. 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 of Eastern Canada there are several specialized competitors who have been pursuing their respective strategies for a number of years.  These companies include Contact, Stealth Ventures Ltd. and Corridor Resources Inc.  These companies have gained technical expertise in the area as they have continued to advance their respective exploration programs.

GOVERNMENTAL REGULATIONS

Our business is affected by numerous laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the oil and gas industry. We plan to develop 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 current and 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 energy industry. Our future expenditures to comply with environmental requirements have been estimated in the consolidated financial statements, under the caption of asset retirement obligations.

Pricing and Marketing Natural Gas
 
In Canada, the price of natural gas sold in interprovincial and international trade is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the National Energy Board of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain criteria prescribed by the National Energy Board of Canada. Natural gas export contracts for a term of less than two years, or for a term of two to 20 years if in quantities of not more than 30,000 m3/day (1,060 mcf/day), may be made pursuant to a National Energy Board of Canada order. Natural gas export contracts for a term of greater than 20 years or for a term of greater than two years and in quantities of greater than 30,000 m3/day (1,060 mcf/day) requires an exporter to obtain an export license from the National Energy Board of Canada and the issuance of such a license requires the approval of the Governor in Council. The export of natural gas pursuant to an order or license shall be subject to the terms and conditions included by the National Energy Board of Canada in such order or license.
 
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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. Natural gas may not be removed from the Province of Alberta without a permit from the Energy Resources Conservation Board of the Province of Alberta. The Energy Resources Conservation Board of the Province of Alberta may grant a permit for the removal of less than three billion cubic meters of natural gas for a term not exceeding two years with the approval of the Minister. All other permits for the removal of natural gas to be granted by the Energy Resources Conservation Board of the Province of Alberta require the approval of the Lieutenant Governor in Council. The removal of natural gas from the Province of Alberta shall be subject to the terms and conditions included by the Energy Resources Conservation Board of the Province of Alberta in the permit granted for such removal.

In the U.S., historically, the sale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, or the NGA, the Natural Gas Policy Act of 1978, or the NGPA, and regulations promulgated thereunder by the Federal Energy Regulatory Commission, or the FERC. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, or 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. There can be no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

Pricing and Marketing 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 and the supply/demand balance. Oil exports may be made pursuant to export contracts with terms not exceeding two years in the case of heavy crude and not exceeding one year in the case of oil other than heavy crude, provided that an order approving any such export has been obtained from the National Energy Board of Canada. 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 National Energy Board of Canada 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 National Energy Board of Canada in such order or license.
 
In the U.S., sales of crude oil, condensate and 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
 
The royalty regime is a significant factor in the profitability of natural gas, natural gas liquids and oil production. In the U.S., all royalties are determined by negotiations between the mineral owner and the lessee.

In Canada, royalties payable on production from non-Crown lands (i.e. non-government lands) are determined by negotiations between the mineral owner and the lessee. However, crown royalties (i.e. government land 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. In addition to federal regulation, each province has legislation and regulations that govern land tenure, royalties, production rates, environmental protection and other matters. From time to time the governments of Canada, Alberta, and Nova Scotia have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging natural gas and oil exploration or enhanced planning projects.
 
Nova Scotia
 
In the Province of Nova Scotia, the royalty rate for onshore oil and gas production has been set at a flat rate of 10% of the petroleum that is produced 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 shall be deducted an allowance for the cost of processing or separation as determined in any particular case by the Minister. Notwithstanding the foregoing, no royalty shall be due with respect to any oil or 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.

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Land Tenure
 
In Canada, natural gas and oil deposits located in Nova Scotia are owned by that provincial government and natural gas and oil 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 natural gas and oil 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. Where natural gas and oil deposits are privately owned, such as in the U.S., rights to explore for and produce such natural gas and oil are granted by lease on such terms and conditions as may be negotiated.

The North American Free Trade Agreement
 
On January 1, 1994, NAFTA became effective among the governments of Canada, the United States and Mexico. NAFTA carries forward most of the material energy terms contained in the Canada - U.S. Free Trade Agreement. 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 domestic use (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 prohibited from imposing minimum export or 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

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 “responsible persons” remediation obligations on property designated as a contaminated site. Responsible persons 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 contained and administered by the Department of Environment.

In December, 2002, the Government of Canada ratified the Kyoto Protocol, or the Protocol. The Protocol calls for Canada to reduce its emissions of greenhouse gas, or 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 Government of Canada released a "Regulatory Framework for Air Emissions", or the Framework, which outlines proposed new requirements governing the emission of GHGs and other industrial air pollutants, including sulfur oxides, volatile organic compounds, particulate matter, and possibly additional sector-specific pollutants, in accordance with the Canadian Federal Government’s Notice of Intent to Develop and Implement Regulations and Other Measures to Reduce Air Emissions released on October 19, 2006.

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The proposed compliance mechanisms include an emissions credit trading system for GHGs and certain industrial air pollutants, and several options for companies to choose among to meet GHG emission intensity reduction targets and encourage the development of new emission reduction technologies, including the option of making payments into a technology fund, an emissions and offset trading system, limited credits for emission reductions created between 1992 and 2006, and international emission credits under the clean development mechanism under the Kyoto Protocol for up to 10% of each company’s regulatory obligation.

Environmental legislation in the Province of Alberta 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, the emission reduction requirements in the Climate Change and Emissions Management Act (Alberta) 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%.  Companies have four options to choose from in order to meet the reduction requirements outlined in this legislation, and these are: (i) by making improvement to operations that result in reductions; (ii) by purchasing emission credits from other sectors or facilities that have reduced their emissions below the required emission intensity reduction levels; (iii) by 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) by contributing to the Climate Change and Emissions Management Fund.  Companies can choose one of these options or a combination thereof.

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 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 arguably 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 (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.

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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 (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 BLM, the TCEQ, the LDNR, the NDIC, the OCC, the WOGCC, the MBOGC 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.

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 greenhouse gas emissions (GHGs) which may ultimately pose a risk to society and the environment. Products produced by the oil and natural gas exploration and production industry is 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.

EMPLOYEES

As of April 6, 2010, we had five full time employees. We consider our relations with our employees to be good.

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, Which May Negatively Impact Our Ability to Achieve Our Business Objectives.

We incurred net losses of $2,140,101 and $13,770,485 for the years ended January 31, 2010 and 2009, 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 establishment of a business enterprise. There can be no assurance that future operations will be profitable. Revenues and profits, if any, will depend upon various factors, including whether we will be able to continue expansion of our revenue. We may not achieve our business objectives and the failure to achieve such goals would have an adverse impact on us.

Natural gas and oil 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 in North America. Oil and 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.
 
 
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We depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future.

Acquisitions of crude oil and natural gas issuers and crude oil and natural gas 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 crude oil and natural gas, future prices of crude 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 use for our year-end reserve evaluations. Because each of these firms may have different evaluation methods and approaches, these initial assessments may differ significantly from the assessments of the firm used by us.

In addition, our review of records and properties of potential acquisitions may not necessarily reveal existing or potential problems, nor will we necessarily become sufficiently familiar with the properties before we acquire them to assess fully their deficiencies and potential. Environmental problems, such as soil or ground water contamination, are not necessarily observable even when an inspection on a well is undertaken and even when problems are identified, we may often assume certain environmental and other risks and liabilities in connection with acquired properties.

As most of our properties are in the exploration stage, there can be no assurance that we will establish commercial discoveries on our properties.

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

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

We do not operate some of the properties in which we have an interest. 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 ways that are 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 depend 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.

We have a limited operating history in the Bakken Shale play 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 play in North Dakota. Our success is significantly dependent on a successful acquisition, drilling, completion and production program. Our operations in the Bakken Shale play 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 exploration stage and potential investors should be aware of the difficulties normally encountered by enterprises in the exploration 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.
 
10

 
Our lack of diversification will increase the risk of an investment in us, and our financial condition and results of operations may deteriorate if we fail to diversify.

Our current business focus is on the oil and gas industry in a limited number of properties, initially 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 play, than we would if our business were more diversified, enhancing our risk profile.

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, including our obligations to Slawson under the Slawson Agreement. If we have insufficient revenues, we may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance 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 financial condition, results of operations or prospects.

Because we are small 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. Accordingly, we must limit our exploration activity. As such, we may not be able to complete an exploration program that is as thorough as our management would like. In that event, existing reserves may go undiscovered. Without finding reserves, we cannot generate revenues and investors may lose their investment.

We face strong competition from other oil and gas companies.

We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Our competitors include major oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of our competitors have been engaged in the oil and 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 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 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 and financial condition.

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. There can be no assurance 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 and financial condition.

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

The potential profitability of oil and gas properties is dependent upon many factors beyond our control. For instance, world prices and markets for oil and gas are unpredictable, highly volatile, potentially subject to governmental fixing, pegging, controls, or any combination of these and other factors, and respond to changes in domestic, international, political, social, and economic environments. Additionally, due to worldwide economic uncertainty, the availability and cost of funds for production and other expenses have become increasingly difficult, if not impossible, to project. These changes and events may materially affect our financial performance. In addition, a productive well may become uneconomic in the event that water or other deleterious substances are encountered which impair or prevent the production of oil and/or 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.
 
11

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

Our operations could be adversely affected by seasonal weather conditions and wildlife restrictions on federal leases. In some areas, certain drilling and other oil and gas activities can only be conducted during limited times of the year, typically during the summer months. This would limit our ability to operate in these areas and could intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs, which could have a material adverse effect upon us and our results of operations.

If we are unable to retain the services of Messrs. Hill and Samuels or if we are unable to successfully recruit qualified managerial and field personnel having experience in oil and 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 and Corporate Secretary. Loss of the services of Messrs. Hill and 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 gas exploration business. Competition for qualified individuals is intense. There can be no assurance that we will be able to find, attract and 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 gas depend on numerous factors beyond our control. These factors include demand for oil and gas, which fluctuate with changes in market and economic conditions, and other factors, including:

 
·
worldwide and domestic supplies of oil and gas;
 
·
actions taken by foreign oil and gas producing nations;
 
·
political conditions and events (including instability or armed conflict) in oil-producing or gas-producing regions;
 
·
the level of global and domestic oil and 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;
 
·
domestic and foreign governmental regulations and taxes; and
 
·
the overall worldwide and domestic economic environment.

Significant declines in oil and 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.
 
 
12

 

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

In order to sell the oil and gas that we are able to produce, 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 particularly problematic 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 gas production and 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 gas and in turn diminish our financial condition or ability to maintain our operations.

Our significant shareholders may have substantial influence over our business and affairs.

As of April 6, 2010, Cambrian Capital, Palo Alto Investors, and Sprott Asset Management each own greater than 10% of our issued and outstanding shares of common stock. As a result, each these three investors individually will have substantial influence over the outcome of certain matters requiring shareholder approval, including the power to, among other things:

 
·
amend our articles of incorporation;
 
·
elect and remove our directors and control the appointment of our senior management; and
 
·
prevent our ability to be acquired and complete other significant corporate transactions.

Oil and 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 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 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 bodies are required for drilling operations to be conducted; no assurance can be given that such permits will be received.  Further, hydraulic fracturing, the process used for releasing 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.

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

With the introduction of the Kyoto Protocol, oil and gas producers may be required to reduce greenhouse gas emissions. This could result in, among other things, increased operating and capital expenditures for those producers. This could also make certain production of crude oil or natural gas by those producers uneconomic, resulting in reductions in such production. We are unable to predict the effect on our future earnings of the ratification of the Kyoto Protocol by the Canadian Federal Government. However, in order to mitigate this risk, we are committed to maximizing shareholder value in an environmentally, socially responsible and safe manner.

13

 
We believe that our operations comply, in all material respects, with all applicable environmental regulations. Our operating partners generally maintain insurance coverage customary to the industry; however, we are not fully insured against all possible environmental risks.

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.

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 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 U.S. 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. 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 operations.

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

Title to natural gas and oil interests is often not possible to determine without incurring substantial expense. An independent title review was completed with respect to certain of the more valuable natural gas and oil rights acquired by us and the interests in natural gas and oil rights owned by us. Also, legal opinions have been obtained with respect to the spacing units for the wells which have been drilled to date and which have been operated 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.

Risks Relating to our Common Stock

If we fail to remain current in our reporting requirements, we could be removed from the OTC Bulletin Board and/or the TSX Venture Exchange which would limit the ability of broker-dealers to sell our securities and the ability of stockholders to sell their securities in the secondary market.

Companies trading on the OTC Bulletin Board, such as us, must be reporting issuers under Section 12 of the Securities Exchange Act of 1934, as amended, and must be current in their reports under Section 13, in order to maintain price quotation privileges on the OTC Bulletin Board. We are also listed on the TSX Venture Exchange.  In order to remain listed on the TSX Venture Exchange, we must remain a reporting issuer in good standing in each jurisdiction in which we are a reporting issuer.  We are a reporting issuer in each of British Columbia, Alberta and Ontario and have continuous disclosure obligations under securities laws and regulations in those jurisdictions (arising primarily under National Instrument 51-102). If we fail to remain current on our reporting requirements, we could be removed from the OTC Bulletin Board and/or the TSX Venture Exchange. As a result, the market liquidity for our securities could be severely adversely affected by limiting the ability of broker-dealers to sell our securities and the ability of stockholders to sell their securities in the secondary market.
 
 
14

 

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 shareholders;
 
·
changes in oil and natural gas prices;
 
·
changes in our cash flows from operations or earnings estimates;
 
·
publication of research reports about us or the 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 increased indebtedness we incur in the future;
 
·
additions or departures of key management personnel;
 
·
actions by our shareholders;
 
·
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;
 
·
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 operating results, 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.

We do not anticipate paying dividends on our common stock in the foreseeable future.

We 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.

Our common stock is subject to the “penny stock” rules of the SEC and the trading market in our securities is limited, which makes transactions in our common stock cumbersome and may reduce the value of an investment in our common stock.

The SEC has adopted Rule 3a51-1 which establishes the definition of a “penny stock,” for the purposes relevant to us, as any equity security that (i) has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, or (ii) is not registered on a national securities exchange or listed on an automated quotation system sponsored by a national securities exchange. For any transaction involving a penny stock, unless exempt, Rule 15g-9 of the Exchange Act requires:

 
·
that a broker or dealer approve a person’s account for transactions in penny stocks; and
 
·
the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.

In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:

 
·
obtain financial information and investment experience objectives of the person; and
 
·
make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.
 
15

 
The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form:

 
·
sets forth the basis on which the broker or dealer made the suitability determination; and
 
·
attests that the broker or dealer received a signed, written agreement from the investor prior to the transaction.

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading, and about the commissions payable to both the broker-dealer and the registered representative. Current quotations for the securities and the rights and remedies and to be available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks. Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of the Common Shares and cause a decline in the market value of the Common Shares.

Investors may be unable to enforce Canadian statutory remedies against us.

Securities legislation in certain of the Provinces and Territories of Canada provides investors with various rights and remedies where a public disclosure contains a misrepresentation. We are incorporated under the laws of the State of Nevada. It may be difficult for investors to collect from us judgments obtained in courts in Canada predicated on the civil liability provisions of Canadian securities legislation.

Investors may be unable to enforce judgments against us and certain of our directors and officers.

Certain of our directors and officers, as well as our independent auditors, reside principally in Canada. Because a portion of our assets and all or substantially all of the assets of these persons are located outside the U.S., it may not be possible for you to effect service of process within the U.S. upon us or those persons. Furthermore it may not be possible for you to enforce judgments obtained in U.S. courts based upon the civil liability provisions of the U.S. federal securities laws or other laws of the U.S. against us or those persons. There is doubt as to the enforceability in original actions in Canadian courts of liabilities based upon the U.S. federal securities laws, and as to the enforceability in Canadian courts of judgments of U.S. courts obtained in actions based upon the civil liability provisions of the U.S. federal securities laws. Therefore, it may not be possible to enforce those actions against us and certain of our directors and officers.

ITEM 1B.  UNRESOLVED STAFF COMMENTS.

None.

ITEM 2.  PROPERTIES.

We maintain our principal office at Suite 750, 521 – 3rd Ave SW, Calgary, Alberta, Canada T2P 3T3.  Our telephone number at that office is (403) 262-4471 and our facsimile number is (403) 262-4472. Our current office space consists of approximately 1,944 square feet.  The lease runs until April 30, 2010 at a cost of $1 per month.  We have paid our share of building operating costs and taxes, and are currently seeking new office space in the Calgary market. We do not anticipate any difficulty securing alternative space on terms acceptable to us.

All of our oil and gas properties are located in the United States and Canada. We are currently participating in oil and 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 gas opportunity located in the Maritimes Basin in the province of Nova Scotia. We intend to execute our 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. We are also in the process of evaluating a potential secondary shale gas project in Western Canada. Our remaining four project areas (Fayetteville Shale, Rocky Mountain Program, Barnett Shale and Alberta Deep Basin) are currently designated as non-core due to our desire to focus our limited manpower resources on one core and one secondary project.
 
16

 
United States

 
Williston Basin - Bakken Shale play
 
We have entered into the Slawson Agreement to acquire and develop acreage in known areas of production from the Middle Bakken Shale and Three Forks formations. Our acreage is located in the Rough Rider area of the play, primarily McKenzie and Williams Counties, North Dakota and consists of several drill ready locations. Under the terms of the Slawson Agreement, we have agreed to participate with a 30% working interest in the Project.

 
As part of the Slawson Agreement, we have agreed to pay our participation interest share of all costs incurred in the Project, plus (i) an additional amount equal to 20% to 60% of our costs directly attributable to lease acquisitions, which amount depends on the bonus cost of a lease per net acre, (ii) an additional amount equal to 50% of our share of brokerage costs and other leasehold costs except those direct lease costs set out above and except those included in an applicable authorization for expenditure, and (iii) an additional 10% of our share in costs proposed in the applicable authorizations for expenditure for wells drilled under the Slawson Agreement.

 
The Slawson Agreement also provides that Slawson will generally be responsible for initiating well proposals, provided that we may recommend the drilling of a well upon land which we own an interest in the leases. If a party to the Slawson Agreement elects not to participate in a proposed well, then, subject to certain condition, it forfeits all rights within the spacing unit boundaries for such well, plus all contiguous sections. The Slawson Agreement also sets out a form of joint operating agreement, pursuant to which all wells initiated under the Slawson Agreement are to be operated.

 
Through the signing of the Slawson Agreement, awards at a recent North Dakota state lease sale, and the on-going success of our joint leasing program, we have acquired approximately 13,000 gross (4,000 net) acres at a total cost to us of $2.9 million. We are currently budgeting an additional minimum $7.0 million to acquire additional leases in the Bakken Shale play in the Williston Basin over the remainder of 2010. Under the terms of the Slawson Agreement, we have the ability to limit our participation to no more than $25 million in any 12-month period for total gross acreage acquisition capital, of which we are 30%. However, this limitation may be exceeded at our option.

Canada
 
Maritimes Basin - Eastern Canadian Shale Gas Projects
 
Windsor Block We have an 87% working interest in 474,625 gross acres (412,924 net acres) in the Windsor Sub-Basin of the Maritimes Basin located in the Province of Nova Scotia, Canada and serve as operator of the Windsor Block; Zodiac Exploration Corp. has earned a 13% working interest in the Windsor Block. We acquired an additional 30% working interest in the Windsor Block in June 2009 from Contact in exchange for agreeing to provide Contact a 5.75% non-convertible gross overriding royalty interest. Contact also received a cash payment of Cdn $270,000 (approximately US$254,000) and we assumed the liabilities related to Contact's former working interest. Until April 15, 2009, the land was governed by an exploration agreement. On April 15, 2009, the Windsor Block exploration agreement was transferred to a 10-year production lease. Under the terms of this lease:

 
·
The production lease grants rights to 474,625 gross acres (412,924 net acres), covering substantially all of the land which we had leased previously under the terms of the exploration agreement. Fringe acreage deemed non-prospective was voluntarily surrendered;
 
·
We hold rights to conventional oil and gas within the lease, which includes shale gas, in the Windsor and Horton Groups, 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, which was estimated to cost Cdn $12.7 million gross (approximately US$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;
 
 
17

 

 
·
During the first year of the lease, we agreed to complete the three exploration wells that were drilled in the prior year and acquire seismic, which was estimated to cost Cdn $2 million gross (approximately US$1.9 million). A Cdn $200,000 (US$188,000) gross refundable deposit was posted related to the first year commitment; should the work not be competed, a portion or all of the deposit could be forfeited.
 
·
Current royalty rates are set at 10% in Nova Scotia; and
 
·
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 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.

During the first quarter of fiscal 2010, we tested the N-14-A well, which was completed in early December 2008 with a four-stage perforation and fracture treatment. The frac flowback operations were suspended in April 2009 after the well recovered 15% of load fluid but negligible gas production.  Subsequent analysis indicated an unusually high insitu stress regime in the immediate vicinity of the well, which contributed to fracture ineffectiveness. Completion operations on the O-61-C well commenced in March 2009 and continued into early May. Several tight sand and carbonate intervals were perforated but have not yet been fracture-treated. No hydrocarbons flowed from the well.

During the second and third quarters of fiscal 2010, three intervals in the E-38-A well were perforated and treated with diagnostic “micro-fracs.”  The two lower intervals appeared to have high insitu stress and a tendency to fracture horizontally.  The upper tested interval indicated lower stress and the likelihood of desirable vertical fracturing. As this was a diagnostic frac in a very low permeability zone, no gas flow was expected, and none was detected. We are continuing to work with these results to determine future completion operations as well looking for future drilling locations and completion strategies.

Also during the second quarter of fiscal 2010, the two wells drilled in 2007, Kennetcook #1 and Kennetcook #2, were re-entered to isolate and test individual zones to try to identify the “gassiest” intervals in each well and eliminate water inflow. From these tests, it appears the fracture treatments undertaken previously had commingled multiple zones together, making it difficult to determine which zone is contributing to the water inflow.

All three of our most recent wells (N-14-A, O-61-C, and E-38-A) still have a variety of completion and testing opportunities.  Our technical team is in the process of evaluating and ranking these opportunities with a goal of demonstrating hydrocarbon production and providing further direction to the ongoing exploration drilling program in the Windsor Block.

In October 2009, we acquired 30 kilometers of 2D seismic on the Windsor Block. The seismic program assessed a geologic structure in the west-central area of the Windsor Block, where no seismic had yet been acquired. We believe that the best potential for both Horton Bluff gas shales and conventional reservoirs exists in areas with geologic structure. This seismic program, combined with the three completion operations on previously drilled vertical exploration wells, satisfied the first-year requirements of our 10-year production lease.

Non-Core Properties

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

 
·
our 25% working interest in 4,327 non-operated net acres in the U.S. 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 3,380 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

 
18

 

 
·
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.

Our remaining non-core producing properties include one well in the Alberta Deep Basin of Canada and three low working interest shale gas wells in the Barnett Shale trend. Our remaining non-core acreage holdings includes 5,165 net acres in the Alberta Deep Basin of Canada, 4,747 non-operated net acres in the U.S. Rocky Mountains, and 61 non-operated net acres in the Barnett Shale trend.

Information with regard to oil and gas producing activities follows:

Net Reserves of Crude Oil and Natural Gas Liquids and Natural Gas at Fiscal Year-End 2010

At January 31, 2010, our proved reserves estimates and future discounted cash flow at 10% was valued at an inconsequential amount. We did not obtain a reserve report at January 31, 2010 as the reserve were not material. Our 12 month production for the year ended January 31, 2010 for these wells was:

   
Alberta Deep
Basin, Canada
   
Texas Barnett
Shale, U.S.A
   
Total
 
Fiscal 2010 Working Interest Production (MMcfe)
    22       18       40  
MMcfe – Millions cubic feet equivalent

We refer you to Note 5 in the consolidated financial statements for a more detailed discussion of our proved natural gas and oil reserves as well as our standardized measure of discounted future cash flows related to our proved natural gas and oil reserves.  We also refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for a discussion of the risks inherent in utilization of standardized measures and estimated reserve data.

In 2008, the SEC adopted major revisions to its required oil and gas reporting disclosures which became effective as of January 1, 2010.  Among other things, the amendments provide for the use of the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period for purposes of both the disclosure and full-cost accounting rules. The use of new technologies to determine proved reserves is permitted under the new rules, and allows companies to disclose probable and possible reserves to investors unlike previous rules which limit disclosure to only proved reserves. The new disclosure requirements also require companies to report the independence and qualifications of the auditor of the reserve estimates and file reports when a third party is relied upon to prepare reserve estimates. The requirements were effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009 and have been included throughout this Form 10-K.

ITEM 3.  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 operating results.

ITEM 4.  RESERVED

 
19

 

PART II

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

MARKET INFORMATION

Our common stock is quoted on the OTC Bulletin Board under the symbol “TPLM” and, starting on December 8, 2008, the TSX Venture Exchange under the symbol “TPE”.

For the periods indicated, the following table sets forth the high and low bid prices per share of common stock on the OTC Bulletin Board. These prices represent inter-dealer quotations without retail markup, markdown, or commission and may not necessarily represent actual transactions.

   
Fiscal Year 2010
 
   
TPLM
 
   
High
   
Low
 
First Quarter
  $ 0.25     $ 0.11  
Second Quarter
  $ 0.21     $ 0.15  
Third Quarter
  $ 0.18     $ 0.07  
Fourth Quarter
  $ 0.40     $ 0.08  

   
Fiscal Year 2009
 
   
TPLM
 
   
High
   
High
 
First Quarter
  $ 1.63     $ 1.63  
Second Quarter
  $ 2.40     $ 2.40  
Third Quarter
  $ 1.08     $ 1.08  
Fourth Quarter
  $ 0.35     $ 0.35  

HOLDERS

As of March 29, 2010, we had approximately 43 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 the Board of Directors and will be dependent upon our financial condition, results of operations, capital requirements, and such other factors as the Board of Directors deem relevant.

RECENT SALE OF UNREGISTERED SECURITIES AND EQUITY PURCHASES BY THE COMPANY

None.

 
20

 

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, 2010.

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 shareholders
    5,700,000     $ 0.52       1,292,604  
Equity compensation plans not approved by shareholders
    -     $ -       -  
Total
    5,700,000     $ 0.52       1,292,604  

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 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 Securities and Exchange Commission. 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 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

We are an oil and gas exploration company focused on emerging shale oil reserves. We have recently undertaken a new strategic investment strategy in the Bakken Shale play with our Slawson Agreement involving 4,000 net acres in McKenzie and Williams Counties of North Dakota. The Bakken Shale formation in the Williston Basin underlies much of North Dakota and eastern Montana. In addition, we have interests in the Maritimes Basin in the Province of Nova Scotia.

 
21

 

Plan of Operations

Williston Basin

The Bakken Shale play in the Williston Basin is our core area of operations in the United States. Having identified what we believe is the prime Bakken Shale fairway, we are continuing to explore further opportunities in the region. We are constantly reviewing potential transactions and are actively pursuing the acquisition of additional leases and acreage in North Dakota in furtherance of our new strategic direction, with an ongoing acreage acquisition program targeting 1,000 acres per month.

Eastern Canadian Shale Gas Project (Windsor Block)

We have an 87% working interest in 474,625 gross acres (412,924 net acres) in the Windsor Block and serve as operator of the Windsor Block. We are continuing to evaluate the anticipated performance and viability of our working interest in the Windsor Block. In moving forward with such property, we intend to consider a range of options pursuant to our existing production lease.

Results of operations for the year ended January 31, 2010 compared to the year ended January 31, 2009

Daily Sales Volumes, Working Interest before royalties

     
2010
   
2009
 
Barnett Shale in Texas, USA
Mcfpd
    50       65  
Deep Basin in Alberta, Canada
Mcfpd
    61       99  
Total Company
Mcfpd
    111       164  
Total Company
Boepd*
    19       27  

* Mcf converted into BOE on a basis of  6:1

Net Operating Results

     
2010
   
2009
 
Volumes
Mcf
    40,744       59,854  
Price
$/Mcf
    3.75       7.97  
Revenue
    $ 152,938     $ 476,996  
Royalties
      21,693       90,104  
Revenue, net of royalties
      131,245       386,892  
Production expenses
      95,852       125,777  
Net
    $ 35,393     $ 261,115  

For the year ended January 31, 2010, we realized $152,938 in revenue from sales of natural gas and natural gas liquids, as compared to $476,996 in the prior year. Revenue decreased mainly due to reduced natural gas prices, and to a lesser effect, due to reduced production volumes. Royalties as a percent of revenue were 14% for the year ended January 31, 2010 as compared to 19% in the prior year. The decrease in royalty rates is due to the sliding scale of royalty rates as gas prices decrease. Production expenses related to this revenue were $14.12/BOE for the year ended January 31, 2010 compared to $12.61/BOE in the prior year; the increase in the per BOE rate was mainly the effect of fixed production costs being spread over reduced production volumes.

 
22

 

Depletion, Depreciation and Accretion

   
2010
   
2009
 
Depletion – oil and gas properties
 
$
38,781
   
$
92,747
 
Accretion
   
150,007
     
107,303
 
Depletion and Accretion
   
188,788
     
200,050
 
Depreciation – property and equipment
   
26,198
     
39,448
 
Total
 
$
214,986
   
$
239,498
 
Depletion per BOE
 
$
5.71
   
$
9.30
 

Unproven property costs of $18,783,375 (2009 – $16,869,995) were excluded from costs subject to depletion at January 31, 2010. Depletion expense related to oil and gas properties decreased in the year ended January 31, 2010 compared to the prior year mainly as a result of the ceiling test write-downs on proved properties in the previous year which decreased the depletion base.

General and Administrative (“G&A”)

   
2010
   
2009
 
Salaries, benefits and consulting fees
 
$
1,844,226
   
$
1,728,907
 
Office costs
   
844,605
     
892,270
 
Professional fees
   
245,235
     
449,236
 
Public company costs
   
303,809
     
558,020
 
Operating overhead recoveries
   
(45,224
)
   
(180,709
)
Stock-based compensation
   
794,361
     
598,182
 
Total G&A
 
$
3,987,012
   
$
4,045,906
 

General and administrative expenses have decreased $58,894 in the year ended January 31, 2010 compared to the prior year primarily due management implementing cost reductions in the current year.

 
·
Salaries, benefits and consulting fees increased $115,319 in the year ended January 31, 2010 compared to the prior year partially due to severances paid to the officers in late 2009 of approximately $465,000 as part of our new strategic direction that was announced December 1, 2009, offset in part by lower salaries of $296,000 during the year due to reduced staff and no staff bonuses in the year ended January 31, 2010.
 
·
Office costs decreased $47,665 compared to the prior year partially due to reduced travel, software, insurance and telephone costs offset in part by higher rent since we bought out the remaining 3.5 year term of our Canadian head office lease for approximately $265,000.
 
·
Professional fees decreased $204,001 mainly due to reduced audit and accounting fees, which were higher in the prior year due to fees for the restatements of our 10-K and 10-Q filings with the SEC, and due to a fee paid in the prior year to market our Fayetteville acreage for sale.
 
·
Public company costs decreased $254,211 in the year ended January 31, 2010 compared to the prior year mainly due to reduced investor relation costs related to management implementing cost reductions. Public company costs consist mainly of fees for investor relations and also include directors' fees, press release and SEC and Toronto Stock Exchange filing costs, printing costs and transfer agent fees.
 
·
Stock-based compensation increased $196,179 mainly due to the granting of stock options in January 2009.

Accretion of Discounts on Convertible Debentures
 
Agreement Date
 
2010
   
2009
 
December 8, 2005
 
$
-
   
$
815,337
 
December 28, 2005
   
-
     
2,107,572
 
Total accretion of discounts
 
$
-
   
$
2,922,909
 


 
23

 
 
The accretion of discounts was fully recognized in the year ended January 31, 2009 since the December 8, 2005 debentures were fully converted and repaid June 5, 2008 and the December 28, 2005 debentures were settled December 18, 2008.

Interest Expense

Agreement Date
 
2010
   
2009
 
December 8, 2005
 
-
   
91,360
 
December 28, 2005
   
-
     
661,644
 
Total interest expense
 
$
-
   
$
753,004
 
 
There was no interest expense in the year ended January 31, 2010 since the December 8, 2005 debentures were fully converted and repaid June 5, 2008 and the December 28, 2005 debentures were settled December 18, 2008.

Gain on Debt Extinguishment

On December 8, 2005, we issued $15,000,000 principal face amount of convertible debentures that were convertible at the lower of (i) $5.00 or (ii) 90% of the average of the three lowest daily volume weighted average prices of our common stock of the 10 trading days immediately preceding the date of conversion. Through June 2008, $11,000,000 of the debentures were converted into shares of common stock. In June 2008, we repaid the $4,000,000 in remaining debt, which was subject to a 20% early redemption fee of $800,000. A loss of $160,662 was recorded on this debt extinguishment.

On December 28, 2005, we issued $10,000,000 principal face amount of convertible debentures that were convertible at the option of the holder at $4.00 per share. In December 2008, the debentures were settled by (i) reducing the conversion price to $1.40 per share and $3,500,000 of the debentures was converted into 2,500,000 shares of common stock and (ii) the convertible debenture holders accepted cash of $6,500,000 to settle the remaining debt plus $2,204,792 in accrued interest. A gain of $4,083,375 was recorded on this debt extinguishment.

Oil and Gas Properties

   
Net Book Value
January 31,
2009
   
Additions
   
Depletion
   
Dispositions
   
Gain
(Loss)
   
Net Book Value
January 31,
2010
 
                                     
Unproven
                                   
Windsor Block Maritimes Shale – Nova Scotia, Canada
  $ 16,818,586     $ 1,964,789     $ -     $ -     $ -     $ 18,783,375  
Western Canadian Shale – Alberta and B.C., Canada
    51,409       171,508       -       -       (222,917 )     -  
Fayetteville and Rocky Mountains
    -       4,500       -       (1,117,860 )     1,113,360       -  
Proved
                                               
Canada
    72,869       2,207       (24,327 )     (426,600 )     375,851       -  
U.S.A.
    -       14,454       (14,454 )     -       -       -  
                                                 
Net
  $ 16,942,864     $ 2,157,458     $ (38,781 )   $ (1,544,460 )   $ 1,266,294     $ 18,783,375  

During the year ended January 31, 2010, we focused on the Windsor Block and spent $1,964,789 primarily for:

 
·
completing the second phase of the Windsor Block exploration program consisting of testing the N-14-A well (approximately $164,000), completion operations on the O-61-C well (approximately $208,000), and completion operations on the E-38-A well (approximately $208,000);
 
·
retesting the Kennetcook #1 and #2 wells (approximately $250,000) and increasing the related non-cash asset retirement costs (approximately $213,000);

 
24

 

 
·
acquiring Contact’s 30% working interest in the Windsor Block for cash of $245,000 and the assumption of future estimated non-cash asset retirement costs of $144,750. We also agreed to provide Contact a 5.75% non-convertible gross overriding royalty interest on our resulting 87% working interest; and
 
·
acquiring 2D seismic (approximately $476,000).

During the year ended January 31, 2010, we sold our:

 
·
25% working interest 4,327 non-operated net acres in the U.S. Rocky Mountains for gross proceeds of $83,325 in June 2009;
 
·
50% working interest in 5,900 non-operated net acres in the Fayetteville Shale and all the related seismic data for net cash proceeds of $744,408 in September 2009. Furthermore, a $50,000 drilling deposit was refunded related to the Fayetteville Shale properties;
 
·
50% working interest in the remaining 3,880 non-operated net acres in the Fayetteville Shale for net cash proceeds of $240,127 in November 2009; and
 
·
18% working interest in one well and 12% working interest in 896 gross acres of undeveloped land in Alberta for cash proceeds of $426,600.

Net Cash Oil and Gas Additions:

   
Year Ended
January 31,
2010
   
Year Ended
January 31,
2009
 
Net additions, per above table
  $ 2,157,458     $ 4,448,883  
Non-cash ARO net additions
    (326,600 )     (360,544 )
Changes in investing working capital
    1,202,396       1,976,950  
Net oil and gas additions, per Statement of Cash Flows
  $ 3,033,254     $ 6,065,289  

Liquidity and Capital Resources

As at January 31, 2010, we had working capital of $4,841,074, resulting primarily from our cash of $4,878,601, prepaid expenses of $342,635 and other receivables of $313,785, offset by payables and accrued liabilities of $693,947. For the year ended January 31, 2010, we had a net cash outflow from operating activities before changes in working capital of $3,187,203, mainly related to $3,192,651 of cash general and administrative expenses, which is equal to general and administrative expenses net of non-cash stock based compensation expense.

We expect significant capital expenditures during the next 12 months for land acquisitions and drilling programs on our U.S. oil shale program, overhead and working capital purposes. We believe we have sufficient cash to fund budgeted capital expenditures in fiscal 2011.  However, if during that period, or thereafter, we are not successful in generating sufficient liquidity from operations or in raising sufficient capital resources, on terms acceptable to us, this could have a material adverse effect on our business, results of operations, liquidity and financial condition. We presently do not have any available credit, bank financing or other external sources of liquidity. Due to our brief history and historical operating losses, our operations have not been a source of liquidity. We will need to obtain additional capital in order to expand operations and become profitable. In order to obtain capital, we may need to sell additional shares of our common stock or borrow funds from private lenders. There can be no assurance that we will be successful in obtaining additional funding. Additional capital is being sought, but we cannot guarantee that we will be able to obtain such investments. Financing transactions may include the issuance of equity or debt securities, obtaining credit facilities, or other financing mechanisms. However, the trading price of our common stock and a downturn in the North American stock and debt markets could make it more difficult to obtain financing through the issuance of equity or debt securities. Even if we are able to raise the funds required, it is possible that we could incur unexpected costs and expenses, fail to collect significant amounts owed to us, or experience unexpected cash requirements that would force us to seek alternative financing. Furthermore, if we issue additional equity or debt securities, stockholders may experience additional dilution or the new equity securities may have rights, preferences or privileges senior to those of existing holders of our common stock. If additional financing is not available or is not available on acceptable terms, we will have to curtail our operations.
 
 
25

 

On April 15, 2009 we converted the Windsor Block exploration agreement to a 10 year production lease for 474,625 gross acres (412,924 net acres) of land. At the end of the second year of the lease, a technical report is due and the Nova Scotia government may request the surrender of certain lands they deem not adequately evaluated. During the first five years of the lease, we agreed to continue to evaluate the Windsor Block by drilling seven wells, completing three exploration wells previously drilled and acquiring seismic at a total gross estimate cost of Cdn $12.7 million (US$11.7 million). 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 the three exploration wells drilled in the 2009 and acquired the seismic 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 would 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 programs and, while we have been successful in doing so in the past, there can be no assurance that we will be able to do so in the future. There is a risk that we may not obtain the necessary additional funds or new joint venture 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.

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.

Investment in Oil and Gas Properties

We utilize the full cost method to account for our investment in oil and gas properties. Accordingly, all costs associated with acquisition and exploration of oil and gas reserves, including such costs as leasehold acquisition costs, interest costs relating to unproven properties, geological expenditures and direct internal costs are capitalized into the full cost pools. We have two full costs pools (Canada and U.S.). The full costs pools capitalized costs, including estimated future costs to develop the reserves and estimated abandonment costs, net of salvage, are depleted on the units-of-production method using estimates of proved reserves. Investments in unproven properties and major development projects including capitalized interest, if any, are not amortized until proved reserves associated with the projects can be determined or, if the future exploration of unproven properties is determined uneconomical, the amounts of such properties are added to the capitalized cost to be amortized. The capitalized costs included in the full cost pool are subject to a ceiling test.

Asset Retirement Obligations

We recognize a liability for future retirement obligations associated with our oil and 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.

Stock-Based Compensation

We record compensation expense in the consolidated financial statements for stock options granted to employees, consultants and directors using the fair value method. Fair values 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. Compensation costs are recognized over the vesting period.

 
26

 
 
Recently Issued Accounting Pronouncements

Refer to Note 2(q) of the Financial Statements.                                                                                                

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

 
27

 

ITEM 8.  FINANCIAL STATEMENTS.

TRIANGLE PETROLEUM CORPORATION

INDEX TO FINANCIAL STATEMENTS
   
Page
     
Report of Independent Registered Public Accounting Firm
 
F-2
     
Consolidated Balance Sheets as of January 31, 2010 and 2009
 
F-3
     
Consolidated Statements of Operations for each of the years ended January 31, 2010 and 2009
 
F-4
     
Consolidated Statements of Cash Flows for each of the years ended January 31, 2010 and 2009
 
F-5
     
Consolidated Statement of Stockholders' Equity for each of the years ended January 31, 2010 and 2009
 
F-6
     
Notes to the Consolidated Financial Statements
 
F-7 to F-20

 
F–1

 
 
Report of Independent Registered Public Accounting Firm
 
The Board of Directors and Stockholders
Triangle Petroleum Corporation
 
We have audited the accompanying consolidated balance sheets of Triangle Petroleum Corporation and its subsidiaries as of January 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended. 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 misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
 
In our opinion the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company and its subsidiaries as of January 31, 2010 and 2009, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.
 
/s/ KPMG LLP
Calgary, Canada
April 8, 2010

 
F–2

 

Triangle Petroleum Corporation
Consolidated Balance Sheets
(Expressed in U.S. dollars)

   
January 31,
2010
$
   
January 31,
2009
$
 
             
ASSETS
           
             
Current Assets
           
             
Cash
    4,878,601       8,449,471  
Prepaid expenses
    342,635       339,839  
Other receivables
    313,785       998,511  
                 
Total Current Assets
    5,535,021       9,787,821  
                 
Property and Equipment (Note 3)
    39,296       39,765  
                 
Oil and Gas Properties (Note 4)
    18,783,375       16,942,864  
                 
Total Assets
    24,357,692       26,770,450  
                 
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
                 
Current Liabilities
               
                 
Accounts payable
    574,723       2,123,079  
Accrued liabilities
    119,224       90,539  
                 
Total Current Liabilities
    693,947       2,213,618  
                 
Asset Retirement Obligations (Note 6)
    1,180,515       727,862  
                 
Total Liabilities
    1,874,462       2,941,480  
                 
Commitments (Note 12)
               
Subsequent Events (Note 14)
               
                 
Stockholders’ Equity
               
                 
Common Stock (Note 9)
Authorized: 150,000,000 shares, par value $0.00001
Issued: 69,926,043 shares (2009 – 69,926,043 shares)
    699       699  
                 
Additional Paid-In Capital (Note 9)
    81,950,076       81,155,715  
                 
Warrants (Note 10)
    4,237,100       4,237,100  
                 
Deficit
    (63,704,645 )     (61,564,544 )
                 
Total Stockholders’ Equity
    22,483,230       23,828,970  
                 
Total Liabilities and Stockholders’ Equity
    24,357,692       26,770,450  
 
The accompanying notes are an integral part of these consolidated financial statements
 
 
F-3

 

Triangle Petroleum Corporation
Consolidated Statements of Operations
(Expressed in U.S. dollars)

   
Year
Ended
January 31,
   
Year
Ended
January 31,
 
   
2010
   
2009
 
   
$
   
$
 
             
Revenue, net of royalties
    131,245       386,892  
                 
Operating Expenses
               
                 
Oil and gas production
    95,852       125,777  
Depletion and accretion
    188,788       200,050  
Depreciation – property and equipment
    26,198       39,448  
General and administrative
    3,987,012       4,045,906  
Foreign exchange (gain) loss
    (753,950 )     2,682,873  
Gain on sale of assets (Note 4)
    (1,266,294 )     (126,314 )
Ceiling test write-down on oil and gas properties (Note 4)
    -       8,308,229  
                 
      2,277,606       15,275,969  
                 
Loss from Operations
    (2,146,361 )     (14,889,077 )
                 
Other Income (Expense)
               
                 
Accretion of discounts on convertible debentures (note 7)
    -       (2,922,909 )
Amortization of debt issue costs
    -       (182,637 )
Interest expense
    -       (753,004 )
Gain on debt extinguishment (Note 7)
    -       3,922,713  
Interest and royalty income
    6,260       260,840  
Unrealized gain on fair value of derivatives (Note 8)
    -       793,589  
                 
Total Other Income
    6,260       1,118,592  
                 
Loss for the Year
    (2,140,101 )     (13,770,485 )
                 
Loss Per Share – Basic and Diluted
    (0.03 )     (0.23 )
                 
Weighted Average Number of Shares Outstanding – Basic and Diluted
    69,926,043       61,113,000  
 
The accompanying notes are an integral part of these consolidated financial statements
 
 
F-4

 

Triangle Petroleum Corporation
Consolidated Statements of Cash Flows
(Expressed in U.S. dollars)
 
   
Year Ended
January 31,
   
Year Ended
January 31,
 
   
2010
   
2009
 
   
$
   
$
 
Operating Activities
           
Loss for the year
    (2,140,101 )     (13,770,485 )
                 
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
               
                 
Accretion of discounts on convertible debentures (Note 7)
    -       2,922,909  
Amortization of debt issue costs
    -       182,637  
Depletion and accretion
    188,788       200,050  
Depreciation – property and equipment
    26,198       39,448  
Ceiling test write-down on oil and gas properties (Note 4)
    -       8,308,229  
Stock-based compensation (Note 11)
    794,361       598,182  
Gain on sale of assets (Note 4)
    (1,266,294 )     (126,314 )
Gain on debt extinguishments (Note 7)
    -       (3,922,713 )
Unrealized gain on fair value of derivatives (Note 8)
    -       (793,589 )
Foreign exchange changes
    (766,200 )     3,183,463  
                 
Asset retirement costs (Note 6)
    (23,956 )     (743,338 )
                 
Changes in operating assets and liabilities
               
                 
Foreign exchange changes
    (8,652 )     (70,443 )
Prepaid expenses
    (22,146 )     129,982  
Other receivables
    706,517       691,648  
Accounts payable
    364,383       (134,401 )
Accrued interest on convertible debentures
    -       (546,302 )
Accrued liabilities
    47,162       (47,058 )
                 
Cash Used in Operating Activities
    (2,099,940 )     (3,898,095 )
                 
Investing Activities
               
Purchase of property and equipment
    (25,729 )     (13,090 )
Oil and gas property expenditures
    (3,033,254 )     (6,065,289 )
Cash advanced on behalf of partners for oil and gas property expenditures
    (677,842 )     677,842  
Proceeds received from sale of oil and gas properties (Note 4)
    1,544,460       4,210,306  
                 
Cash Used in Investing Activities
    (2,192,365 )     (1,190,231 )
                 
Financing Activities
               
Proceeds from issuance of common stock (Note 9)
    -       25,560,500  
Common stock issuance costs (Note 9)
    -       (2,257,959 )
Convertible debenture repayment (Note 7)
    -       (11,300,000 )
                 
Cash Provided by Financing Activities
    -       12,002,541  
                 
Foreign exchange change on cash
    721,435       (3,046,333 )
                 
Increase (Decrease) in Cash
    (3,570,870 )     3,867,882  
                 
Cash– Beginning of Year
    8,449,471       4,581,589  
                 
Cash– End of Year
    4,878,601       8,449,471  
                 
Non-cash Investing and Financing Activities
               
                 
Common stock issued for conversion of debentures (Note 9)
    -       2,600,140  
                 
Supplemental Disclosures:
               
                 
Interest paid (Note 7)
    -       1,299,860  
 
The accompanying notes are an integral part of these consolidated financial statements
 
 
F-5

 

Triangle Petroleum Corporation
Statement of Stockholders’ Equity
Years ended January 31, 2010 and 2009
(Expressed in U.S. dollars)

               
Additional
                   
   
Common Stock
   
Paid-in
                   
   
Shares
   
Amount
   
Capital
   
Warrants
   
Deficit
   
Total
 
   
#
   
$
   
$
   
$
   
$
   
$
 
                                     
Balance – January 31, 2008
    46,794,530       468       57,852,277             (47,794,059 )     10,058,686  
                                                 
Issuance of common stock and warrants for cash pursuant to private placement at $1.40 per unit in June 2008 (Notes 9 and 10)
    18,257,500       182       21,323,218       4,237,100             25,560,500  
                                                 
Share issuance costs (Note 9)
                (2,257,959 )                   (2,257,959 )
                                                 
Issuance of common stock on conversion of convertible debentures at a weighted average price of $0.53 per share (Note 9)
    4,874,013       49       2,600,091                   2,600,140  
                                                 
Fair value of conversion features of convertible debentures converted  (Note 9)
                1,039,906                   1,039,906  
                                                 
Stock based compensation (Note 11)
                598,182                   598,182  
                                                 
Net loss for the year
                            (13,770,485 )     (13,770,485 )
                                                 
Balance – January 31, 2009
    69,926,043       699       81,155,715       4,237,100       (61,564,544 )     23,828,970  
                                                 
Stock based compensation (Note 11)
                794,361                   794,361  
                                                 
Net loss for the year
                            (2,140,101 )     (2,140,101 )
                                                 
Balance – January 31, 2010
    69,926,043       699       81,950,076       4,237,100       (63,704,645 )     22,483,230  
 
The accompanying notes are an integral part of these consolidated financial statements
 
 
F-6

 

Triangle Petroleum Corporation
Notes to the Consolidated Financial Statements
(Expressed in U.S. dollars, except as noted)
 
Triangle Petroleum Corporation, together with its consolidated subsidiaries (“Triangle” or the “Company”), is an independent oil and gas company focused primarily on the acquisition, exploration and development of resource properties consisting mainly of shale gas reserves.  The Company’s primary exploration and development acreage is located in the Horton Bluff formation of the Maritimes Basin in Canada. The Company also has minor producing properties in the Fort Worth Basin and in the Alberta Deep Basin.
 
1.
Nature of Operations
 
The Company is primarily engaged in the acquisition, exploration and development of oil and gas resource properties and has a limited number of producing wells that generate cash flows from operations. The Company has not generated significant revenues from operations. The Company expects that significant additional exploration and development activities will be necessary to established proved reserves and to commercialize the oil and gas properties.

The Company believes that it has sufficient funds, including those raised subsequent to year end (note 14), to maintain its interest in the existing properties and to maintain core operating, exploration and development activities through to January 31, 2011. The Company monitors its expenditure budgets and adjusts its expenditure plans to conform to available funding. However, additional funding will be required to complete exploration and development activities. The Company plans to fund future exploration and development activities by offering debt or equity securities, farm-out arrangements or other means.
 
2.
Summary of Significant Accounting Policies
 
a)
Basis of Presentation
 
These financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States, 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.

The Company’s oil and gas operations are generally conducted jointly with others as such these financial statements reflect the Company’s proportionate share of these operations.

b)
Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company regularly evaluates estimates and assumptions related to the recoverability of proved and unproven oil and gas expenditures, asset retirement obligations and stock-based compensation. The Company bases its estimates and assumptions on current facts, historical experience and various other factors that it believes 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 the Company may differ materially and adversely from the Company’s estimates. To the extent there are material differences between the estimates and the actual results, future results of operations will be affected.

c)
Foreign Currency Translation

The Company's functional currency is the United States dollar. 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.

 
F-7

 
 
Triangle Petroleum Corporation
Notes to the Consolidated Financial Statements
(Expressed in U.S. dollars, except as noted)

d)
Cash and Cash Equivalents

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

e)
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)
Oil and Gas Properties

The Company utilizes the full-cost method of accounting for petroleum and natural gas properties.  Under this method, the Company capitalizes all costs associated with acquisition, exploration and development of oil and natural gas reserves, including leasehold acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling productive and non-productive wells into the full cost pool on a country by country basis. When the Company obtains proved oil and gas reserves, capitalized costs, including estimated future costs to develop the proved reserves and estimated abandonment costs, net of salvage, will be depleted on the units-of-production method using estimates of proved reserves.

The Company applies a ceiling test to the capitalized costs in the full cost pool. The ceiling test limits such costs to the estimated present value, using a ten percent discount rate, of the future net revenue from proved reserves, based on current economic and operating conditions. Specifically, the Company computes the ceiling test so that capitalized cost, less accumulated depletion and related deferred income tax, do not exceed an amount (the ceiling) equal to the sum of: (A) the present value of estimated future net revenue computed by applying prices of oil and gas reserves as prescribed by U.S. standards (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current cost) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; plus (B) the cost of property not subject to depletion; plus (C) the lower of cost or estimated fair value of the unproven properties included in the costs subject to depletion; less (D) income tax effects related to differences between the book and tax basis of the property.

For unproven properties, the Company excludes from capitalized costs subject to depletion, all costs directly associated with the acquisition and evaluation of the unproven property until it is determined whether or not proved reserves can be assigned to the property. Until such a determination is made, the Company assesses the property to ascertain whether impairment has occurred. In assessing impairment the Company considers factors such as historical experience and other data such as primary lease terms of the property, average holding periods of unproven property, and geographic and geologic data. The Company adds the amount of impairment assessed to the costs that are subject to depletion and the ceiling test.

g)
Asset Retirement Obligations

The Company recognizes a liability for future retirement obligations associated with the Company’s oil and gas properties.  The estimated fair value of the asset retirement obligation is based on the estimated cost escalated at 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.

 
F-8

 

Triangle Petroleum Corporation
Notes to the Consolidated Financial Statements
(Expressed in U.S. dollars, except as noted)

h) 
Debt Issue Costs

The Company recognizes debt issue costs on the balance sheet as deferred charges, and amortizes the balance over the term of the related debt using the effective interest rate method.

i) 
Revenue Recognition

The Company recognizes oil and gas revenue when production is sold at a fixed or determinable price, persuasive evidence of an arrangement exists, delivery has occurred and title has transferred, and collectability is reasonably assured. Gas-balancing arrangements are accounted for using the sales method.

j) 
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, 2010 and 2009, 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 three 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 2006 to 2010. 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, 2005. 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, 2010 and 2009, there were no charges for interest or penalties.

k)
Basic and Diluted Net Loss 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, and convertible securities, using the if-converted 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.

l)
Financial Instruments

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

m)
Concentration of Risk

The Company maintains its cash accounts predominately in one commercial bank located in Calgary, Alberta, Canada. The Company's cash accounts consist of uninsured and insured business checking accounts and deposits maintained in Canadian and U.S. dollars. Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash in excess of insured amounts. To date, the Company has not incurred a loss relating to this concentration of credit risk.

 
F-9

 

Triangle Petroleum Corporation
Notes to the Consolidated Financial Statements
(Expressed in U.S. dollars, except as noted)

n)
Derivative Liabilities

The Company records derivatives at their fair values on the date that they meet the requirements of a derivative instrument and at each subsequent balance sheet date.  Any change in fair value is recorded as non-operating, non-cash income or expense at each reporting date. As at January 31, 2010, the Company has not engaged in any transactions that would be considered derivative instruments or hedging activities.

o)
Comprehensive Loss

As at January 31, 2010 and 2009, the Company has no items that would be included in comprehensive loss other than the net loss and, therefore, has not included a statement of comprehensive loss in the financial statements.

p)
Stock-Based Compensation

The Company records stock based compensation based on the estimated fair values of all share-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 share-based awards is estimated on the date of grant using an option-pricing model and for consultants each period until the award is vested. The Company uses the Black-Scholes option-pricing model to estimate the fair value of stock-based awards. 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.

No tax benefits were attributed to stock-based compensation expense because a full valuation allowance was maintained for all net deferred tax assets.

q)
Recently Adopted Accounting Pronouncements

U.S. accounting standards setters have implemented new standards in December 2007 with respect to accounting for business combinations. These new standards require an acquirer to be identified for all business combinations and applies the same method of accounting for business combinations – the acquisition method – to all transactions. In addition, transaction costs associated with acquisitions are required to be expensed. The revised statement was effective to business combinations after February 1, 2009. No business combinations were completed in fiscal 2010. There was no impact that arose from adopting the new business combination standard.

In December 2007, new accounting standards were issued with respect to non-controlling interests in consolidated financial statements. These new standards require the Company to report non-controlling interest in subsidiaries as equity in the consolidated financial statements; and all transactions between equity and non controlling interests as equity. These new standards were effective for the Company commencing on February 1, 2009. The adoption of these standards did not affect the Company's financial statements.

In March 2008, new accounting standards were issued with respect to disclosures about derivative instruments and hedging activities, which require disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. These new standards were effective on February 1, 2009. No business combinations were completed in fiscal 2010; therefore, there was no impact that arose from adopting the new business combination standard.

 
F-10

 

Triangle Petroleum Corporation
Notes to the Consolidated Financial Statements
(Expressed in U.S. dollars, except as noted)

In May 2009, new accounting standards were issued with respect to subsequent events, which are intended to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued.  In particular, these standards set forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. These standards are effective for interim and annual periods ending after June 15, 2009. The adoption of this standard did not significantly impact the disclosures in the Company’s financial statements.

The Securities and Exchange Commission adopted major revisions to its required oil and gas reporting disclosures which became effective as of December 31, 2009.  Among other things, the amendments provide for the use of the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period for purposes of both the disclosure and full-cost accounting rules.  These amendments did not have a significant impact on the Company’s financial statements.

3.
Property and Equipment

   
January 31, 2010
   
January 31, 2009
 
   
Cost
$
   
Accumulated
Depreciation
$
   
Net
Carrying
Value
$
   
Cost
$
   
Accumulated
Depreciation
$
   
Net
Carrying
Value
$
 
                                     
Computer hardware
    81,280       73,805       7,475       80,748       65,706       15,042  
Furniture and equipment
    50,398       38,296       12,102       49,674       28,289       21,385  
Computer software
    37,010       17,291       19,719       12,537       9,199       3,338  
Leasehold Improvements
    7,927       7,927             7,927       7,927        
                                                 
      176,615       137,319       39,296       150,886       111,121       39,765  
 
4.
Oil and Gas Properties

All of the Company’s oil and gas properties are located in the United States and Canada. The following table summarizes information regarding the Company's oil and gas acquisition, exploration and development activities:

   
January 31, 2010
   
January 31, 2009
 
   
Canada
   
US
   
Total
   
Canada
   
US
   
Total