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, 2009

Commission File Number 000-51321

TRIANGLE PETROLEUM CORPORATION

(Exact name of issuer as specified in its charter)

Nevada	98-0430762
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

Suite 1250, 521 - 3 Avenue SW Calgary, Alberta, Canada	T2P 3T3 (403) 262-4471
(Address of principal executive office)	(Postal Code) (Issuer's telephone number)

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 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, 2008, based on the closing sales price of the Common Stock as quoted on the Over-the-Counter Bulletin Board was $28,421,381. 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 7, 2009, there were 69,926,043 shares of issuer’s common stock outstanding.

TRIANGLE PETROLEUM CORPORATION

FORM 10-K

For the Fiscal Year Ended January 31, 2009

Part I	Page

Item 1. Business	3

Item 1A. Risk Factors	10

Item 1B. Unresolved Staff Comments	16

Item 2. Properties	16

Item 3. Legal Proceedings	20

Item 4. Submission of Matters to a Vote of Security Holders	20

Part II	Page

Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21

Item 6. Selected Financial Data	22

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	23

Item 7A. Quantitative and Qualitative Disclosures about Market Risk	30

Item 8. Financial Statements and Supplementary Data	F-1

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	31

Item 9A. Controls and Procedures	31

Item 9B. Other Information	32

Part III	Page

Item 10. Directors, Executive Officers and Corporate Governance	33

Item 11. Executive Compensation	38

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	42

Item 13. Certain Relationships and Related Transactions, and Director Independence	43

Item 14. Principal Accounting Fees and Services	43

Part IV	Page

Item 15. Exhibits; Financial Statement Schedules	45

Signatures.	47

PART I

FORWARD-LOOKING INFORMATION

This Annual Report of Triangle Petroleum Corporation on Form 10-K contains forward-looking statements, particularly those identified with the words, "anticipates," "believes," "expects," "plans," “intends”, “objectives” and similar expressions. These statements reflect management's best judgment based on factors known at the time of such statements. The reader may find discussions containing such forward-looking statements in the material set forth under "Legal Proceedings" and "Management's Discussion and Analysis and Plan of Operations," generally, and specifically therein under the captions "Liquidity and Capital Resources" as well as elsewhere in this Annual Report on Form 10-K. Actual events or results may differ materially from those discussed herein.

ITEM 1. BUSINESS.

OVERVIEW

We were incorporated in the State of Nevada on December 11, 2003 under the name Peloton Resources Inc. In December 2003, we purchased six mineral claims situated in the Greenwood Mining Division in the Province of British Columbia, Canada. Our principal business plan was to acquire, explore and develop mineral properties and to ultimately seek earnings by exploiting the mineral claims. Subsequent to the period, we abandoned our mineral property as a result of poor exploration results, and decided to change our principal business to that of acquisition and exploration of oil and gas resource properties. On May 10, 2005, we changed our name to Triangle Petroleum Corporation. We have two wholly-owned subsidiaries: Triangle USA Petroleum Corporation, which was incorporated under the laws of the State of Colorado on October 27, 2005 and Elmworth Energy Corporation, which was incorporated under the laws of the province of Alberta, Canada on June 1, 2005. We conduct our operations through our subsidiaries, Triangle USA in the U.S. and Elmworth in Canada.

We are an exploration company focused on emerging shale gas opportunities in the Maritimes Basin of Eastern Canada through our 57% working interest in 516,000 gross acres (294,000 net acres) on the Windsor Block in Nova Scotia where, in 2007 and 2008, we acquired 2D and 3D seismic, drilled and completed two vertical test wells and drilled three vertical exploration wells, of which, we completed one. In addition, we have non-core interests in the Fayetteville Shale trend in Arkansas (20,344 gross acres, 10,172 net acres), the Barnett Shale trend in Texas (three producing wells), and conventional oil and gas properties in Alberta (two producing wells), Colorado (18,987 gross acres and 4,747 net acres) and Wyoming (17,307 gross acres and 4,327 net acres). Our corporate strategy is to exploit our Canadian shale gas assets based upon experience we have gained in the U.S. shale gas market since November 2005.

THE SHALE GAS INDUSTRY

Shale gas is natural gas that is typically produced from “continuous” gas accumulations where thick shale rock formations extend over a large area and are characterized by high levels of organic carbon or kerogen, the source of the gas. Shale plays can hold an enormous amount of natural gas and are capable of producing gas at a steady rate for decades.

Although shale is a very common sedimentary rock and is known as a source for unconventional natural gas reservoirs, the energy industry has not pursued widespread commercial development of shale plays until the last 20 years. As an unconventional resource, shale gas has traditionally been difficult to extract economically. Shale gas plays are characterized by low permeability that causes gas to flow more slowly than conventional gas resources and generally requires fracturing to allow gas to flow to well bores.

As the price of natural gas climbed due to increasing demand and the flow rates significantly improved due to improved and cost-effective hydraulic fracturing technology, shale gas production became economically viable in the 1990s and led to the development of successful shale gas plays such as the Barnett and Fayetteville Shales in the United States. Significant shale plays, such as the Montney and Horn River in Western Canada, and the Utica in Quebec, are now also being developed in Canada.

In order for a shale play to produce, the rock must have geochemical attributes that indicate that the organic content (kerogen) has been sufficiently heated to produce natural gas in the formation. If the shale does not reach a high enough temperature over the millions of years that it was buried, then it is not prospective for thermogenic gas generation. Conversely, if the rock reaches too high a temperature, the natural gas (methane) that is produced can break down into non-combustible gases such as carbon dioxide.

To understand the geochemical (maturity, organic content), mechanical (stress, brittleness) and in-situ rock properties (permeability, porosity, water saturation, reservoir pressure, gas content), wells are drilled, and rock samples from core and cuttings are recovered and sent to specialized laboratories. Traditional logging tools do not provide sufficient information for evaluating shale prospectivity, and can be misleading unless calibrated to lab results from actual rock samples.

Because shale has such low permeability, gas will generally not flow unless the rock has been fractured. This involves injecting high volumes of water, mixed with sand, at high pressure into the targeted shales. This fractures and props open the rock, thus allowing the gas trapped in the reservoir rock to flow to the wellbore.

Generally, vertical wells are used to explore the shale resource and determine the best places for development, then horizontal wells are drilled for commercial production.

Horizontal well drilling and multi-stage fracture stimulations have been the key to obtaining economic productivity in most shale reservoirs. Horizontal wells can be drilled over 1,000 meters laterally through the productive shale and then 5-10 individual intervals are fracture stimulated. This technique connects larger volumes of the resource into a single wellbore, resulting in higher rates and reserves, and ultimately, a commercially viable project.

We believe that shale gas production in North America will continue to grow for many years to come. The long-life nature of shale gas plays, the substantial advances in technology in recent years and the economics of shale gas have improved significantly over the last few years.

OUR OPERATIONS

During fiscal 2009, we had exploration operations in the Maritimes Basin of Eastern Canada on our Windsor Block. In the first half of fiscal 2009, we finished the first phase of our Windsor Block exploration program by testing two wells (1.14 net) that we drilled and completed in fiscal 2008. In the second half of fiscal 2009, we executed the second phase of our Windsor Block exploration program by drilling three exploration wells (1.71 net) and completing one of these wells (0.57 net). We have established the following objectives for the 2009/2010 third stage of exploration on the Windsor Block:

•

Continue the technical evaluation of the results of the five wells drilled to date, including executing new completions on the two remaining uncompleted wells;

•

Add one or more new partners to accelerate the drilling program and mitigate exploration risk;

•

Resume drilling a multi-well program by mid-2009, preceded by targeted seismic, and followed by state-of-the-art completions; and

•

Continuously seek signposts for commercial production.

During fiscal 2009, we had two producing wells in the Alberta Deep Basin, Canada, and four 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.

COMPETITORS

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 Exploration Inc., 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.

In the Fayetteville Shale area located in the Arkoma Basin in Arkansas, we compete with several large and well known public and private companies such as Southwestern Energy Corporation, Chesapeake Energy Resources, and Hallwood Petroleum. This is one of a half dozen new emerging shale gas areas and is attracting a great deal of industry interest. Competition for equipment, personnel and services is expected to be similar to the Barnett Shale area.

In the Barnett Shale area located in the Greater Fort Worth Basin of Texas, we compete with a number of larger well known oil and gas exploration companies such as Burlington Resources, Devon Energy, EOG Resources, Encana, Murphy Oil and Quicksilver Resources. Each of these companies has significant financial resources as well as specialized engineering expertise in the area which makes them formidable competitors. Due to the area’s significant potential upside, the Barnett Shale has attracted a great deal of interest from numerous other companies and it is expected that the competition for land, personnel and equipment will continue to be more intense over the years ahead.

In the Deep Basin area of Western Canada, we have several competitors and many potential competitors, including public and private oil and gas exploration companies in North America as well as companies from China and Europe. Some of the larger and well capitalized companies that are actively exploring and producing from the Deep Basin area include BP Canada Energy Company, Devon Canada Corporation, and Talisman Energy Inc. Each of these companies has significant existing cash flow, capital budgets and in-house expertise to continue seeking additional oil and gas reserves in the Deep Basin.

In the Rocky Mountain region of the United States, we compete with a combination of larger exploration companies and focused regional players. Some of the key competitors in this area include Encana, EOG Resources, Anadarko Petroleum and Ultra Petroleum. These companies all share key attributes that have led to their collective success in the area. These attributes include significant financial resources and excellent technical staff who specialize in the complexities associated with extracting natural gas from these formations.

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.

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 3 billion cubic meters of natural gas for a term not exceeding 2 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.

Alberta

In the Province of Alberta, the crown royalty rates on conventional oil and natural gas fluctuate, depending on when a well was drilled, well depth, well production volumes and the price of oil and natural gas. On October 25, 2007 the government of Alberta announced that a new royalty regime would be implemented commencing January 1, 2009 and is applicable to all existing conventional oil and natural gas wells in Alberta. This new royalty regime assesses the applicable royalty rate on a well by well basis using a sliding scale which takes into account the price of oil and/or natural gas and the well’s production volumes.

Under the new Alberta royalty regime, the royalty reserved to the Alberta Crown on conventional oil production ranges from 0% to 50% and is capped at 51% once the price of conventional oil reaches Cdn$120 per barrel. The royalty applicable to natural gas production under the new royalty regime ranges from 5% to 50% and is capped once natural gas reaches Cdn$16.589 per gigajoule. The new royalty regime also sets royalties for natural gas liquids at 40% for pentanes and 30% for butanes and propane.

As royalties under the new Alberta royalty regime are sensitive to both commodity prices and production levels, the estimated corporate royalty rate under the new Alberta regime will fluctuate with commodity prices, well production rates, production decline of existing wells, and performance and location of new wells drilled. As a result of these changes to royalties, we expect our royalty rates will increase in fiscal 2010 given similar commodity prices in fiscal 2010 as fiscal 2009.

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.

On March 10, 2008, the Government of Canada released "Turning the Corner – Taking Action to Fight Climate Change", or Turning the Corner, which provides some additional guidance with respect to the Government of Canada's plan to reduce GHG emissions by 20% by 2020 and by 60% to 70% by 2050. Turning the Corner is primarily directed towards industrial emissions from certain specified industries including the oil and gas industries. Turning the Corner is intended to force industries to reduce GHG emissions and to create a carbon emissions trading market, including an offset system, to provide incentives to reduce GHG emission and establish a market price for carbon. For the upstream oil and gas industry, Turning the Corner provides for a company threshold of 10,000 boe/day and facility threshold of 3,000 tonnes of CO2. It is contemplated that new regulations will take effect January 1, 2010. Draft regulations were expected to be available for public comment in the Fall of 2008 but are now expected in mid 2009.

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

Operations on properties in which we have an interest are subject to extensive federal, state and local environmental laws that regulate the discharge or disposal of materials or substances into the environment and otherwise are intended to protect the environment. Numerous governmental agencies issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial administrative, civil and criminal penalties and in some cases injunctive relief for failure to comply.

Some laws, rules and regulations relating to the protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination. These laws render a person or company liable for environmental and natural resource damages, cleanup costs and, in the case of oil spills in certain states, consequential damages without regard to negligence or fault. Other laws, rules and regulations may require the rate of oil and gas production to be below the economically optimal rate or may even prohibit exploration or production activities in environmentally sensitive areas. In addition, state laws often require some form of remedial action, such as closure of inactive pits and plugging of abandoned wells, to prevent pollution from former or suspended operations.

Legislation has been proposed in the past and continues to be evaluated in Congress from time to time that would reclassify certain oil and gas exploration and production wastes as “hazardous wastes.” This reclassification would make these wastes subject to much more stringent storage, treatment, disposal and clean-up requirements, which could have a significant adverse impact on operating costs. Initiatives to further regulate the disposal of oil and gas wastes are also proposed in certain states from time to time and may include initiatives at the county, municipal and local government levels. These various initiatives could have a similar adverse impact on operating costs.

The regulatory burden of environmental laws and regulations increases our cost and risk of doing business and consequently affects our profitability. The federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault, on certain classes of persons with respect to the release of a “hazardous substance” into the environment. These persons include the current or prior owner or operator of the disposal site or sites where the release occurred and companies that transported, disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for the federal or state government to pursue such claims.

It is also not uncommon for neighboring landowners and other third parties to file claims for personal injury or property or natural resource damages allegedly caused by the hazardous substances released into the environment. Under CERCLA, certain oil and gas materials and products are, by definition, excluded from the term “hazardous substances.” At least two federal courts have held that certain wastes associated with the production of crude oil may be classified as hazardous substances under CERCLA. Similarly, under the federal Resource, Conservation and Recovery Act, or RCRA, which governs the generation, treatment, storage and disposal of “solid wastes” and “hazardous wastes,” certain oil and gas materials and wastes are exempt from the definition of “hazardous wastes.” This exemption continues to be subject to judicial interpretation and increasingly stringent state interpretation. During the normal course of operations on properties in which we have an interest, exempt and non-exempt wastes, including hazardous wastes, that are subject to RCRA and comparable state statutes and implementing regulations are generated or have been generated in the past. The federal Environmental Protection Agency and various state agencies continue to promulgate regulations that limit the disposal and permitting options for certain hazardous and non-hazardous wastes.

We have established guidelines and management systems to ensure compliance with environmental laws, rules and regulations. The existence of these controls cannot, however, guarantee total compliance with environmental laws, rules and regulations. We believe that the operator of the properties in which we have an interest is in substantial compliance with applicable laws, rules and regulations relating to the control of air emissions at all facilities on those properties. Although we maintain insurance against some, but not all, of the risks described above, including insuring the costs of clean-up operations, public liability and physical damage, there is no assurance that our insurance will be adequate to cover all such costs, that the insurance will continue to be available in the future or that the insurance will be available at premium levels that justify our purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and operations. Compliance with environmental requirements, including financial assurance requirements and the costs associated with the cleanup of any spill, could have a material adverse effect on our capital expenditures, earnings or competitive position. We do believe, however, that our operators are in substantial compliance with current applicable environmental laws and regulations. Nevertheless, changes in environmental laws have the potential to adversely affect operations. At this time, we have no plans to make any material capital expenditures for environmental control facilities.

EMPLOYEES

As of April 7, 2009, we had five full time employees - our Chief Executive Officer, President/Chief Operations Officer, Chief Financial Officer, Vice President Exploration and Vice President Operations, and two part time employees – an Office Manager and Accounting Clerk. 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 $13,770,485 and $29,600,747 for the years ended January 31, 2009 and 2008, 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.

Our Independent Auditor Has Expressed Substantial Doubt About Our Ability to Continue As a Going Concern, Which May Hinder Our Ability to Obtain Future Financing.

In their report dated April 7, 2009, our independent auditor stated that our financial statements for the year ended January 31, 2009 were prepared assuming that we would continue as a going concern. Our ability to continue as a going concern is an issue raised as a result of recurring losses from operations. We continue to experience net operating losses. Our ability to continue as a going concern is subject to our ability to generate a profit and/or obtain necessary funding from outside sources, including obtaining additional funding from the sale of our securities, increasing sales or obtaining loans and grants from various financial institutions where possible. Our continued net operating losses increase the difficulty in meeting such goals and there can be no assurances that such methods will prove successful.

We Have a Limited Operating History 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 received a limited amount of revenues from operations and have limited assets. We have yet to generate positive earnings and there can be no assurance that we will ever operate profitably. We have a limited operating history. Our success is significantly dependent on a successful acquisition, drilling, completion and production program. Our operations 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.

Because We Are Small and Do Not Have Much Capital, We May Have to Limit Our Exploration Activity Which May Result in a Loss of Your Investment.

Because we are small and do not have much capital, we must limit our exploration activity. As such we may not be able to complete an exploration program that is as thorough as we would like. In that event, existing reserves may go undiscovered. Without finding reserves, we cannot generate revenues and you will lose your investment.

If Our Partners Fail to Fund their Portion of Costs on the Windsor Block, We May Have to Curtail or Cease Exploration.

Our current exploration program in the Windsor Block is dependent on our joint operating agreement partners funding their agreed portion of exploration costs. A partner could elect to not participate in the drilling or completion of future wells, which could hinder the timing and execution of the program and may significantly slow down or stop exploration.

If We Do Not Secure Additional Funds or a New Partner on the Windsor Block, We May Have to Curtail or Cease Exploration.

At January 31, 2009 we had $7,574,203 of working capital, which should be sufficient to complete our current exploration program consisting of the continued technical evaluation of the results of the five wells drilled to date on the Windsor Block, including executing new completions on the two uncompleted wells. However, if we are not successful in raising additional funds or securing a new joint operating partner, we will not be able to drill or complete wells on the Windsor Block in the future which would significantly slow down or stop exploration.

If We Are Unable to Retain the Services of Messrs. Gustafson and Anderson 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 Mr. Mark Gustafson, our Chief Executive Officer and a director, and Mr. Howard Anderson, our President and Chief Operating Officer. Loss of the services of Messrs. Gustafson or Anderson could have a material adverse effect on our growth, revenues, and prospective business. 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.

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 proven reserves of gas, we may not establish commercial discoveries on any of our properties.

Although our Estimated Natural Gas and Oil Reserve Data has been Prepared by an Independent Third Party, the Estimates may Prove to be Inaccurate.

There are numerous uncertainties inherent in estimating quantities of oil and natural gas reserves and the future cash flows attributed to such reserves. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditure, marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves will vary from estimates thereof and such variations could be material.

The Potential Profitability of Oil and Gas Ventures 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.

Adverse weather conditions can also hinder drilling operations. A productive well may become uneconomic in the event water or other deleterious substances are encountered which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is impregnated with water or other deleterious substances. The marketability of oil and gas which may be acquired or discovered will be affected by numerous factors beyond our control. These factors include the proximity and capacity of oil and gas pipelines and processing equipment, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection. These factors cannot be accurately predicted and the combination of these factors may result in us not receiving an adequate return on invested capital.

The Oil And Gas Industry Is Highly Competitive And There Is No Assurance That We Will Be Successful In Acquiring and Continuing Leases/Permits.

The oil and gas industry is intensely competitive. We compete with numerous individuals and companies, including many major oil and gas companies, which have substantially greater technical, financial and operational resources and staffs. Accordingly, there is a high degree of competition for desirable oil and gas leases, suitable properties for drilling operations and necessary drilling equipment, as well as for access to funds. We cannot predict whether the necessary funds can be raised or that any projected work will be completed.

The Marketability of Natural Resources Will be Affected by Numerous Factors Beyond Our Control Which May Result in Us not Receiving a Return on Invested Capital Sufficient to be Profitable or Viable.

The marketability of natural resources which may be acquired or discovered by us will be affected by numerous factors beyond our control. These factors include market fluctuations in oil and gas pricing and demand, the proximity and capacity of natural resource markets and processing equipment, governmental regulations, land tenure, land use, regulation concerning the importing and exporting of oil and gas and environmental protection regulations. The exact effect of these factors cannot be accurately predicted, but the combination of these factors may result in us receiving a return on invested capital that is insufficient to be profitable or viable.

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, and local laws relating to the protection of the environment, including laws regulating removal of natural resources from the ground and the discharge of materials into the environment. Oil and gas operations are also subject to federal, state, and local laws and regulations which seek to maintain health and safety standards by regulating the design and use of drilling methods and equipment. Various permits from government bodies are required for drilling operations to be conducted; no assurance can be given that such permits will be received. Environmental standards imposed by federal, provincial, or local authorities may be changed and any such changes may have material adverse effects on our activities. Moreover, compliance with such laws may cause substantial delays or require capital outlays in excess of those anticipated, thus causing an adverse effect on us. Additionally, we may be subject to liability for pollution or other environmental damages. We generally maintain insurance coverage customary to the industry; however, we are not fully insured against all possible environmental risks. To date we have not been required to spend any material amount on compliance with environmental regulations. However, we may be required to do so in future and this may affect our ability to expand or maintain our operations. Due to the high salinity of our frac fluid that has flowed back from the Kennetcook #1 and #2 wells and that the Nova Scotia government has not set standards for this fluid disposal, we can provide no assurance that the estimated amounts in the financial statements will not be significantly higher.

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, land disturbance, 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.

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 Our Profitability.

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

Stakeholder Consultation and Approvals Are Required and, if Not Obtained, May Result in the Corporation's Inability to Obtain the Necessary Licenses and Permits.

Each singular exploration and development, and each phase of exploration and development, are subject to participant involvement (stakeholder consultation and notification, including with aboriginal peoples) and regulation pursuant to a variety of laws and regulations in the areas in which Triangle does business. These regulations apply to the Corporation's business as they apply to other companies or enterprises in the energy industry.

Stakeholder consultation and notification regulations impose, among other things, suggested and prescribed stakeholder consultation and notification and communication planning methodology, stakeholder audiences, minimum radii of personal contact and notification, communication quality and effectiveness, communication mediums, tools and content, contact timing, co-operation methodology and communication audit documentation.

Participant involvement compliance can require significant expenditures and may involve considerable effort that may impact the timing of exploration, production and development activities. However, failure to comply with participant involvement legislation may result in the Corporation's inability to obtain the necessary licenses and permits required to carry out the Corporation's exploration and development programs. At the same time, even though the Corporation routinely conducts effective participant involvement programs that meet or exceed regulatory requirements, there can be no assurance that Triangle will be able to obtain all of the necessary licenses and permits required for its exploration and development programs.

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 we acquired and the interests in natural gas and oil rights we own. Also, legal opinions have been obtained with respect to the spacing units for the wells which have been drilled to date and which we have operated. 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.

Our Officers, Directors and Principal Shareholders own a Controlling Interest in our Voting Stock and Investors Will Not Have Any Voice in Our Management.

Our officers, directors and principal shareholders, in the aggregate, beneficially own or control the votes of approximately 49.7% of our outstanding common stock. As a result, these stockholders, acting together or in conjunction with other stockholders, will have the ability to control substantially all matters submitted to our stockholders for approval, including:

	•	election of our board of directors;
	•	removal of any of our directors;
	•	amendment of our certificate of incorporation or bylaws; and
	•	adoption of measures that could delay or prevent a change in control or impede a merger, takeover or other business combination involving us.

As a result of their ownership and positions, our directors, executive officers and principal shareholders collectively are able to influence all matters requiring stockholder approval, including the election of directors and approval of significant corporate transactions. In addition, sales of significant amounts of shares held by our directors, executive officers or principal shareholders, or the prospect of these sales, could adversely affect the market price of our common stock. The large blocks of stock ownership may discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of us, which in turn could reduce our stock price or prevent our stockholders from realizing a premium over our stock price.

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 Stock Cumbersome and May Reduce the Value of an Investment in Our Stock.

The Securities and Exchange Commission has adopted Rule 15g-9 which establishes the definition of a "penny stock," for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require:

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.

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the Commission 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

that the broker or dealer received a signed, written agreement from the investor prior to the transaction.

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 our common stock and cause a decline in the market value of our stock.

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 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2. PROPERTIES.

We maintain our principal office at 1250, 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 5,192 square feet. The lease runs until April 30, 2013 at a cost of $169,000 per year. We must also pay our share of building operating costs and taxes.

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 province of Nova Scotia. Our core project is a 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.

Canada

Maritimes Basin - Eastern Canadian Shale Gas Projects

During fiscal 2007 and early fiscal 2008, a multi-disciplined geoscience team screened prospective basins in Eastern Canada. The screening process included an assessment of the geological history for a given area, estimates of pressure and temperature profiles and a determination of the ability to fracture stimulate a prospective shale package. As a direct result of implementing this strategy we executed two farm-in agreements in May 2007 with a Canadian company to pursue two shale gas opportunities in the Maritimes Basin on the Windsor Block and the Beech Hill Block.

Windsor Block

In May 2007, we entered into the Windsor Block farm-in agreement with Contact Exploration Inc., or Contact, which covers approximately 516,000 gross acres (294,000 net) in the Windsor Sub-Basin of the Maritimes Basin located in the Province of Nova Scotia, Canada. The agreement committed us to pay 100% of the costs to drill and complete a vertical test well on the Windsor Block whereby we would earn, at Contact’s election at the end of the program, either (a) a 70% working interest or (b) a 100% working interest with a 5% gross over-riding royalty payable to Contact.

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), thus fulfilling the earning commitment, which cost approximately $17.5 million (net $14.2 million). In July 2008, our joint venture partner, Contact, elected to maintain their 30% working interest instead of converting to a 5% gross over-riding royalty and paid us 30% of the gross costs ($2.9 million) for the second well and seismic program that was expended in this first stage of the drilling program that was not a part of the earning parameter. The vertical test wells, seismic and geological studies provided us with sufficient valuable technical information for us to believe that this is a significant shale gas resource project and allowed us to plan for a second phase Windsor Block shale gas exploration program.

In May 2008, we entered into a Joint Venture Agreement with Zodiac Exploration Corp., or Zodiac., to drill as many as six new delineation wells on the Windsor Block in the second phase of our Windsor Block exploration program. The joint venture provided for an initial commitment by Zodiac to pay 50% of drilling costs, up to Cdn$7.5 million (Cdn$15 million gross), to earn a 12.5% working interest in the entire Windsor Block. Within 30 days of fulfilling this expenditure commitment, Zodiac had the option to commit another Cdn$7.5 million (Cdn$15 million gross) for an additional 12.5% working interest.

From July 2008 to March 2009, we executed the second phase of the Windsor Block shale gas exploration program to test the gas content and productivity of the Horton Bluff shales in various locations across the Windsor Block, and also to evaluate potential overlying conventional oil and gas reservoirs. The program consisted of drilling three vertical exploration wells and completing one of these wells, which cost approximately $15.3 million (net $3.1 million).

The first vertical exploration well in this program, N-14-A, spud in mid July 2008 and cased in August 2008. N-14-A is located approximately eight kilometers (five miles) north of our two 2007 vertical test wells. N-14-A was drilled to a depth of 2,600 meters (8,500 feet). Log, core, and lab analysis indicates a potential gas-bearing Horton Bluff shale and sand interval, approximately 1,000 meters (3,300 feet) thick.

Completion operations commenced on the N-14-A well at the end of October 2008, with a four-stage perforation and fracture treatment taking place in early December 2008. The completion consisted of a four-stage, 200 tonne (440,000 pounds) fracture treatment within a 120 meter (400 foot) interval at an approximate depth of 1,800 meters (5,900 feet). After recovering about 15% of the injected frac fluid and CO2, but measuring negligible burnable gas, frac flowback operations were suspended. The well is now shut in for a pressure build-up. We are also evaluating completion options in other intervals within this well.

Geomechanical work indicated that, at the depth evaluated in N-14-A, due to prevailing insitu stress, the fracture treatment propagated horizontally rather than in the preferred vertical orientation. This may explain the poor flowback results, despite the apparent large gas-in-place resource. We are now undertaking a basin analysis study that incorporates the new data with the goal being to further identify optional stress regimes.

The second vertical exploration well, O-61-C, spud in August 2008, and was cased in October 2008. This well is located approximately 22 kilometers (14 miles) west of N-14-A, in a separate fault block. Total depth drilled was 2,960 meters (9,700 feet). In this well, we encountered a 300 meter (1,000 foot) Horton Bluff shale interval, as well as multiple potential tight gas sands, conventional carbonates, sandstones and shallow gas intervals.

Completion operations at this well commenced in February 2009, starting with a perforation and test program on the potential hydrocarbon zone of interest at the bottom of the well. Once weather conditions improve, this program will continue up the wellbore, specific zones of interest. Additional testing and possible fracture treatments will depend on the results obtained from each interval. We operate this well and are proceeding with the completion at a 100% working interest.

The third vertical exploration well, E-38-A, spud in late October 2008, and was cased in November 2008. The well is located in the Kennetcook area near N-14-A, but in a separate fault block. Total depth drilled was 1,700 meters (5,600 feet), and casing was run to 1,500 meters (4,900 feet). A shale section of approximately 1,000 meters (3,300 feet) is being evaluated for completion. A preliminary completion program is being designed to incorporate all the latest available technical information. Our working interest in this well is a minimum 45%.

Operations will move forward on the basis of the technical evaluation, equipment availability, government approvals, and partner concurrence. In February of 2009, Zodiac elected not to commit to the additional 12.5% working interest. Therefore, effective February 14, 2009, we have retained a 57% working interest and continue as operator; Zodiac has earned a 13% working interest in the Windsor Block and Contact retained a 30% working interest.

Over the last year, we have also been working to convert the Windsor Block Exploration Agreement to a Production Lease. In December 2008, we received approval in principle from the Nova Scotia government for a 10-year production lease in the Windsor Block. We have been in discussions with Energy Department officials to finalize the terms of this lease. We expect that we will be required to drill at least seven more wells in the Windsor Block over the next three to five years in order to retain rights over the entire Windsor Block. Areas of the Windsor Block that are not adequately evaluated over that time may be subject to relinquishment. A revised work program and budget will be prepared, which will be based on the specific work commitments once they are confirmed.

Beech Hill Block

In May 2007, we entered into the Beech Hill farm-in agreement with Contact in the Moncton Sub-Basin of the Maritimes Basin located in the Province of New Brunswick, Canada. We were entitled to earn a 70% working interest in the block subsequent to the acquisition and evaluation of a minimum Cdn$250,000 seismic program and then electing no later than December 31, 2008 to drill a test well by mid-2009. During June and July 2008, approximately $345,000 gross ($95,000 net) expenditures were incurred to complete the acquisition phase of approximately 30 kilometers (19 miles) of 2D seismic on the Beech Hill Block and another $33,000 gross ($33,000 net) was spent to interpret the seismic. In December 2008, we elected to not drill the test well, thus forfeiting our right to earn in the Beech Hill Block.

Western Canadian Shale Program

We continue to actively position ourselves for an entry into potential shale gas plays in Alberta and British Columbia. Our objective is to potentially establish an initial land position and to commence an exploration program in 2009 or 2010. To date, we have participated in a multi-company geological study, which we tailored using our proprietary shale knowledge and experience, and have identified prospective shale areas where we believe we may have a technical and business advantage. A joint venture partner will be added at the appropriate time to provide funding and mitigate exploration risk. This approach is consistent with the strategy we successfully employed to establish our position in the Windsor Block in Nova Scotia.

Alberta Canada Deep Basin - Western Canadian Conventional Program (non-core project)

In fiscal 2009 there was no exploration activity planned on this project and there continues to be no exploration activity planned for this project in fiscal 2010. We are producing from two wells. The first well is located in the Kakwa Area and we have an 18% interest before payout (12% after payout). The second well is located in the Wapiti Area and we have an approximate 35% working interest.

United States

Arkoma Basin Arkansas - Fayetteville Shale Program (non-core project)

Due to the lack of success in the exploration program, which was operated by another company, we decided in 2008 to sell our 10,400 non-operated net acres. In June 2008, we entered into a brokerage agreement with Tristone Capital to market the property. In September and November 2008, 260 of the net acres were sold for $301,000 and the remaining land was considered impaired and included in the net loss.

States of Colorado, Montana and Wyoming - Rocky Mountain Program (non-core project)

In fiscal 2009, there was no exploration activity planned on this project and there continues to be no exploration activity planned for this project in fiscal 2010. We drilled initial test wells in Colorado and Wyoming in fiscal 2007 and fiscal 2008 that were not successful in the primary targets. In June 2008, we sold our Montana prospect, consisting of 9,692 net acres of land, for proceeds of approximately $800,000.

Greater Fort Worth Basin Texas - Barnett Shale Program (non-core project)

In fiscal 2009, there was no exploration activity planned on this project and there continues to be no exploration activity planned for this project in fiscal 2010. At the beginning of 2009, we had six low working interest shale gas wells pipeline connected (5.75%-15% working interest), of which four were producing. During 2008 we sold our interest in one well in an auction of the operator's assets, who was in voluntary bankruptcy proceedings, for proceeds of approximately $165,000. As such, we currently have three low working interest shale gas wells (11%-15% working interest) currently producing.

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 2009

The following table summarizes our January 31, 2009 reserves estimates and future discounted cash flow at 10%, plus our 12 month production for the year ended January 31, 2009 for these wells.

	Alberta Deep Basin, Canada		Texas Barnett Shale, U.S.A		Total
Estimated Proved Developed Producing Reserves:
Total Working Interest Reserves (MMcfe)		59		75		134
Total Company Net Reserves (MMcfe)		49		56		105
Discounted Cash Flow-10%	$	73,290	$	83,123	$	156,413

Fiscal 2009 Working Interest Production (MMcfe)		36		24		60
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 the risk factor “Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate” in Item 1A of Part I of this Form 10-KSB and 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.

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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

None.

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 2008
	TPLM
	High		Low
First Quarter	$	3.14	$	2.10
Second Quarter	$	2.40	$	1.75
Third Quarter	$	2.08	$	0.88
Fourth Quarter	$	1.55	$	0.95

	Fiscal Year 2009
	TPLM
	High		Low
First Quarter	$	1.63	$	0.72
Second Quarter	$	2.40	$	0.85
Third Quarter	$	1.08	$	0.09
Fourth Quarter	$	0.35	$	0.15

HOLDERS

As of March 30, 2009, we had approximately 36 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

Unless otherwise noted, the issuances noted below are all considered exempt from registration by reason of Section 4(2) of the Securities Act of 1933, as amended.

In December 2008, we issued 2,500,000 shares of common stock upon conversion of $3,500,000 of a previously issued convertible debenture. The shares were issued pursuant to an exemption under Section 4(2) of the Securities Act of 1933.

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 April 7, 2009.

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	2,435,000	$	2.08	-
Equity compensation plans not approved by shareholders	2,550,000	$	0.24	2,007,604
Total	4,985,000	$	1.14	2,007,604

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

Prior to May 2005, we were known as Peloton Resources Inc., a mining exploration company. Peloton was actively searching for ore bodies containing gold in British Columbia. A consultant was hired to assess the economic viability of exploring for and developing gold reserves on Peloton’s properties. Based upon his report, Peloton decided to abandon all mining activities and to change its focus towards oil and gas exploration. In connection with the shift in operational focus, we changed our name to Triangle Petroleum Corporation.

We are an exploration company focused on emerging shale gas opportunities. Our corporate strategy is to utilize our U.S. shale gas experience to secure early stage shale gas projects in Canada. In conjunction with this strategy, we have screened and participated in various projects in North America with numerous potential joint venture partners. These project areas include the Barnett Shale trend in Texas (three producing wells), the Fayetteville Shale trend in Arkansas, the Beech Hill Block in New Brunswick and the Windsor Block in Nova Scotia. We have also participated in conventional oil and gas plays in the province of Alberta (two producing wells) and the states of Montana, Colorado and Wyoming.

We have selected the Windsor Block in Nova Scotia as our core project, which is focused on a shale gas opportunity located in the Maritimes Basin of Eastern Canada. 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. We are also in the process of evaluating a potential secondary shale gas project in Western Canada. All other projects are currently designated as non-core due to our desire to focus our limited manpower resources on the one core and one secondary project.

Plan of Operations

During the first half of fiscal 2010, we plan to finalize the Windsor Block production lease, continue the technical evaluation of the results of the five wells drilled to date on the Windsor Block, including executing new completions on the two uncompleted wells, and search for one or more new joint venture partners to join us in the next phase of our Windsor Block exploration program. This should lead us to a revised work program and budget for the period from July 2009 to July 2010, once we have more certainty on the terms of a new joint venture partner and production lease. We intend to allocate our available working capital to the Windsor Basin as described above. However, there may be circumstances where, for sound business reasons, a reallocation of the funds may be necessary. Furthermore, while we intend to use our working capital as described above, our current working capital is not sufficient to complete the anticipated exploration program.

Results of operations for the year ended January 31, 2009 compared to the year ended January 31, 2008

Daily Sales Volumes, Working Interest before royalties

		2009		2008
Barnett Shale in Texas, USA	Mcfpd		65		177
Deep Basin in Alberta, Canada	Mcfpd		99		152
Total Company	Mcfpd		164		329
Total Company	Boepd*		27		55

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

Net Operating Results

		2009		2008
Volumes	Mcf		59,854		119,927
Price	$/Mcf		7.97		6.52
Revenue		$	476,996	$	781,696
Royalties			90,104		194,892
Revenue, net of royalties			386,892		586,804
Production expenses			125,777		304,537
Net		$	261,115	$	282,267

For the year ended January 31, 2009, we realized $476,996 in revenue from sales of natural gas and natural gas liquids compared to $781,696 in the prior year. Revenue decreased mainly due to reduced production volumes as a result of us selling a Barnett Shale well. Royalties as a percent of revenue was 19% for the year ended January 31, 2009 compared to 25% in the prior year; the royalty rate decreased mainly as a result of lower royalty rates in Canada as a result of the Gas Cost Allowance credit received monthly from the Alberta government starting in fiscal 2009. Production expenses related to this revenue were $12.61/Boe in the year ended January 31, 2009 compared to $15.24/Boe in the prior year.

Depletion, Depreciation and Accretion

	2009		2008
Depletion – oil and gas properties	$	92,747	$	393,143
Accretion		107,303		48,738
Depletion and Accretion		200,050		441,881
Depreciation – property and equipment		39,448		40,429
Total	$	239,498	$	482,310
Depletion per BOE	$	9.30	$	19.67

Unproven property costs of $16,869,995 (2008 – $24,565,040) were excluded from costs subject to depletion at January 31, 2009. Depletion expense related to oil and gas properties decreased in the year ended January 31, 2009 compared to the prior year primarily as a result of the U.S. properties having no depletion starting in the second quarter of fiscal 2009 as the related proved property costs were nil since a well was sold for more than net book value of the U.S. proved property pool.

General and Administrative (“G&A”)

	2009			2008
Salaries, benefits and consulting fees	$	1,728,907		$	1,576,145
Office costs		892,270			800,839
Professional fees		449,236			281,096
Public company costs		558,020			608,792
Operating overhead recoveries		(180,709	)		(162,899	)
Stock-based compensation		598,182			2,696,143
Total G&A	$	4,045,906		$	5,800,116

General and administrative expenses have decreased $1,754,210 in the year ended January 31, 2009 compared to the prior year primarily due to a decrease in stock-based compensation expense of $2,097,961, mainly as a result of shares issued to our executives that have now been fully expensed.

Salaries, benefits and consulting fees increased $152,762 in the year ended January 31, 2009 compared to the prior year due to increased staff and the payment of bonuses to employees in July 2008. Office costs increased $91,431 in the year ended January 31, 2009 compared to the prior year due to increased office rent associated with the increase of office space starting the second half of fiscal 2008. Professional fees increased $168,140 in the year ended January 31, 2009 compared to the prior year due to increased year-end audit and reserve evaluation fees, and increased audit and accounting fees for the restatements of our 10-K and 10-Q filings with the SEC. Public company costs consist mainly of fees for investor relations and also include directors' fees, press release and SEC filing costs, printing costs and transfer agent fees. Public company costs decreased $50,772 in the year ended January 31, 2009 compared to the prior year mainly due to reduced investor relation costs related to management implementing cost reductions, which is partially offset by increased director fees.

Accretion of Discounts on Convertible Debentures

Agreement Date	2009		2008
June 14, 2005	$	-	$	515,626
December 8, 2005		815,337		4,773,326
December 28, 2005		2,107,572		3,236,669
Total accretion of discounts	$	2,922,909	$	8,525,621

Accretion of discounts on convertible debentures decreased $5,602,712 in the year ended January 31, 2009 compared to the prior year due primarily to the accretion base being reduced as a result of conversions and repayment. Moreover, the June 14, 2005 debentures were fully converted prior to fiscal 2009, the remaining December 8, 2005 debentures were partially converted through fiscal 2008 and fiscal 2009, the December 8, 2005 debentures were repaid on June 5, 2008, the maturity date of the December 28, 2005 debentures were extended in January 2008 resulting in the lengthening of the accretion period, and the December 28, 2005 debentures were repaid in December 2008.

Interest Expense

Agreement Date	2009		2008
June 14, 2005	$	-	$	18,918
December 8, 2005		91,360		514,247
December 28, 2005		661,644		750,000
Total interest expense	$	753,004	$	1,283,165

Interest expense decreased $530,161 for the year ended January 31, 2009 compared to the prior year due primarily to the conversion and repayment of the December 8, 2005 convertible debentures.

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 conversion price was amended to $1.40 per share and $3,500,000 of the debentures were converted into 2,500,000 shares of common stock. Subsequent to the amendments, we entered into settlement agreements for the $6,500,000 in remaining debt plus $2,204,792 in accrued interest, whereby the convertible debentures holders agreed to accept $6,500,000 in cash for the final settlement of the debentures and interest. A gain of $4,083,375 was recorded on this debt extinguishment.

Oil and Gas Properties

	Net Book Value January 31, 2008		Additions			Depletion and Impairment			Disposition				Gain (Loss)		Net Book Value January 31, 2009
Unproven
Windsor Block Maritimes Shale – Nova Scotia, Canada	$	15,441,144	$	4,320,952		$	-		$	(2,943,510	)	$	-		$	16,818,586
Beech Hill Block Maritimes Shale – New Brunswick, Canada		21,975		107,802			(129,777	)		-			-			-
Western Canadian Shale – Alberta and B.C., Canada		-		51,409			-			-			-			51,409
Arkoma Basin, Arkansas – Fayetteville Shale		8,289,901		(104,202	)		(8,000,000	)		(301,308	)		115,609			-
U.S. Rocky Mountains – Colorado, Montana, Wyoming		812,020		18,488			-			(800,503	)		(30,005	)		-
Proved
Alberta Deep Basin – Western Canada		324,162		13,984			(265,277	)		-			-			72,869
Greater Fort Worth Basin, Texas – Barnett Shale		89,747		40,450			(5,922	)		(164,985	)		40,710			-
Net	$	24,978,949	$	4,448,883		$	(8,400,976	)	$	(4,210,306	)	$	126,314		$	16,942,864

During the year ended January 31, 2009, we spent $4,320,952 on the Windsor Block of Nova Scotia, split between the first and second phases of the Windsor Block exploration program.

During the first half of fiscal 2009, we focused on completing the first phase of the Windsor exploration program whereby we fulfilled our farm-in commitment on the Windsor Block to pay 100% of the drill and test costs for one well to earn a 70% working interest. We spent $1,400,000 on this phase during the year mainly for testing Kennetcook #1 and #2. Total gross expenditures on the first phase were $16,824,000 (net – $13,829,000). In July 2008, we received $2,943,510 in cash from our joint venture partner for their share of 30% of the first phase exploration costs associated with the second non-earning well that we drilled during the first phase and the 2D and 3D seismic we acquired.

During the second half of fiscal 2009, we focused on the second phase of the Windsor exploration program. During the second phase, we paid 20% of the costs, our partner paid 30% and our farm-out partner paid the remaining 50% of the costs to earn a 13% working interest (pre farm-out working interest – 70%; post farm-out working interest –57%). We had net expenditures of $2,921,000 during the year on the second phase Windsor Block exploration program mainly as follows:

•	$860,000 drilling the N-14-A well in the Kennetcook area;
•	$868,000 drilling the 0-61-C well in the Stanley area;
•	$483,000 drilling the E-38-A well in the Kennetcook area;
•	$591,000 completing the N-14-A well in the Kennetcook area; and
•	$119,000 for geological, geophysical and land costs.

In September 2008, we sold 20 net acres of the 10,437 net acres of Fayetteville shale land for $13,000. As a result of this partial sale, and as result of reduced interest in land sales and reduced gas prices attributable to the slowdown in the economy, we recorded an impairment of $8,000,000 on the land value at October 31, 2008, resulting in a carrying value of $299,395. In November 2008, we sold an additional 240 of the 10,437 net acres for $288,308 and recorded a gain on the sale of $115,609.

During June and July 2008, we completed the acquisition phase of approximately 30 kilometers (19 miles) of 2D seismic on the Beech Hill Block. In December 2008, we elected to not drill the test well thus forfeiting our right to earn in the Beech Hill Block. As such, we recorded an impairment of $129,777 for the carrying value of the Beech Hill Block costs.

In June 2008, we sold our 25% working interest in 9,692 gross acres in the Phat City area of Montana (Rocky Mountains project) for gross cash proceeds of $800,503. The net book value of the Rocky Mountains project at the time of the sale was $830,508, which related to U.S. Rocky Mountain leasehold acquisition costs. As such, we recorded a loss on the sale of assets of $30,005.

In June 2008, we sold our interest in a Barnett shale well for gross proceeds of $164,985. The net book value of the U.S. proved property costs at the time of the sale was $131,820 and the related properties had an asset retirement obligation of $7,545. As such, we recorded a gain on the sale of assets of $40,710.

Net Cash Oil and Gas Additions:

	Year Ended January 31, 2009			Year Ended January 31, 2008
Net additions, per above table	$	4,448,883		$	23,989,712
Non-cash ARO additions		(360,544	)		-
Changes in investing working capital		1,976,950			(766,127	)
Net oil and gas additions, per Statement of Cash Flows	$	6,065,289		$	23,223,585

Liquidity and Capital Resources

To date, we have generated minimal revenues and have incurred operating losses in every quarter. We are an early stage production company, have not generated significant revenues from operations and have incurred significant losses since inception. These factors among others raise substantial doubt about our ability to continue as a going concern.

As at January 31, 2009, we had working capital of $7,574,203, resulting primarily from our cash of $8,449,471 and other receivables of $998,511, offset by payables and accrued liabilities of $2,213,618. For the year ended January 31, 2009, we had net cash outflow from operating activities of $3,898,095, mainly related to cash general and administrative expenses of $3,447,724 and cash abandonment liability settlements of $743,338.

Over the last year, we have been working to convert the Windsor Block exploration agreement to a production lease. In December 2008, we received approval in principle from the Nova Scotia government for a 10-year production lease in the Windsor Block. We have been in discussions with Energy Department officials to finalize the terms of this lease. We expect that we will be required to drill at least seven more wells in the Windsor Block over the next three to five years in order to retain rights over the entire Windsor Block. Areas of the Windsor Block that are not adequately evaluated during that time may be subject to relinquishment. A revised work program and budget will be prepared, which will be based on the specific work commitments once they are confirmed.

We expect significant capital expenditures during the next 12 months for drilling programs on our Canadian shale program, overhead and working capital purposes. There is a risk that neither of our 13% or 30% joint venture partners in the Windsor Block will be able to pay for their portion of the well costs, which would slow down or stop exploration on the Windsor Block. There is also a risk we may not secure a new joint operating partner in the Windsor Block, which would slow down or stop exploration on the Windsor Block. To partially fund these expenditures, we closed a private placement on June 3, 2008 for aggregate gross proceeds of $25,560,500. Also, to partially fund the remaining expenditures, we sold 240 of our 10,000 net undeveloped acres in the Fayetteville Shale Program of the Arkoma Basin in November 2008 for $288,000. We will have to raise additional funds 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. Our continuation as a going concern for a period longer than the 2010 fiscal year is dependent upon our ability to obtain necessary additional funds to continue operations and to determine the existence, discovery and successful exploitation of economically recoverable reserves in our resource properties, earning of our interests in the underlying properties, and the attainment of profitable operations.

By adjusting our operations to the current level of capitalization, we believe we have sufficient capital resources to meet projected cash flow deficits in the near term. 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.

We will still need additional capital in order to continue operations until we are able to achieve positive operating cash flow. 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.

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 pool. We had properties in two countries with proved reserves. For our proved oil and gas reserves, capitalized costs, including estimated future costs to develop the reserves and estimated abandonment costs, net of salvage, will be 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. 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 the Company’s stock price volatility and the options expected life. Compensation costs are recognized over the vesting period.

Recently Issued Accounting Pronouncements

In December 2007, the Financial Accounting Standard Board (FASB) revised the Statement of Financial Accounting Standard (SFAS) No. 141, “Business Combinations”. SFAS No. 141R requires 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 is effective to business combinations in years beginning on or after December 31, 2008. The adoption of this statement will impact business combinations, if any, after the effective date.

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements”. SFAS No. 160 requires the Company to report the non-controlling interest in subsidiaries as equity in the consolidated financial statements; and all transactions between equity and non controlling interests as equity. SFAS No. 160 is effective for us commencing on February 1, 2009 and it will not impact our current financial statements.

In March 2008, the FASB has issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities”, which requires disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective on February 1, 2009 and is not anticipated to significantly affect our financial statements.

In 2008, the SEC adopted major revisions to its required oil and gas reporting disclosures which become 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. With respect to accounting pronouncements that currently make reference to a single-day pricing regime with respect to oil and gas reserves, the SEC indicated that it was communicating with the FASB staff to align the standards used in the FASB’s pronouncements with the new 12-month average price and that it will consider whether to delay the compliance date based on its discussions with the FASB. The SEC expressed the view that the change from using single-day year-end price to an average price should be treated as a change in accounting principle, or a change in the method of applying an accounting principle, that is inseparable from a change in accounting estimate and that the change would be considered a change in accounting estimate pursuant to Statement of Financial Accounting Standard No. 154 “Accounting Changes and Error Corrections” (SFAS 154) and accounted for prospectively. The SEC further expressed the view that any accounting change resulting from the changes in definitions and required pricing assumptions in Rule 4-10 of Regulation S-X should be treated as a change in accounting principle that is inseparable from a change in accounting estimate, not requiring retroactive revision but requiring recognition in the independent auditor’s report through the addition of an explanatory paragraph. We will not be able to determine the impact of these amendments on our results of operation or financial condition until the FASB issues its pronouncements.

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

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

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, 2009 and 2008		F-3

Consolidated Statements of Operations for each of the years ended January 31, 2009 and 2008		F-4

Consolidated Statements of Cash Flows for each of the years ended January 31, 2009 and 2008		F-5

Consolidated Statement of Stockholders' Equity for each of the years ended January 31, 2009 and 2008		F-6

Notes to the Consolidated Financial Statements		F-7 to F-23

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

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 as of January 31, 2009 and 2008, 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 audit.

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 as of January 31, 2009 and 2008, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

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

/s/ KPMG LLP

Calgary, Canada

April 7, 2009

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

F-2

Triangle Petroleum Corporation

Consolidated Balance Sheets

(Expressed in U.S. dollars)

	January 31, 2009 $			January 31, 2008 $

ASSETS

Current Assets

Cash and cash equivalents		8,449,471			4,581,589
Prepaid expenses		339,839			797,307
Other receivables		998,511			1,689,391

Total Current Assets		9,787,821			7,068,287

Debt Issue Costs, net		–			465,833

Property and Equipment (Note 3)		39,765			66,121

Oil and Gas Properties (Note 4)		16,942,864			24,978,949

Total Assets		26,770,450			32,579,190

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities

Accounts payable		2,123,079			3,533,833
Accrued interest on convertible debentures		–			2,751,096
Accrued liabilities		90,539			420,384
Derivative liabilities (Note 8)		–			3,262,846
Convertible debentures, current portion, less unamortized discount of $nil and $1,321,869, respectively (Note 7)		–			4,778,271

Total Current Liabilities		2,213,618			14,746,430

Asset Retirement Obligations (Note 6)		727,862			1,003,353

Convertible Debentures, less unamortized discount of $nil and $3,229,279, respectively (Note 7)		–			6,770,721

Total Liabilities		2,941,480			22,520,504

Going Concern (Note 1)
Commitments (Note 12)

Stockholders’ Equity

Common Stock (Note 9) Authorized: 100,000,000 shares, par value $0.00001 Issued: 69,926,043 shares (2008 – 46,794,530 shares)		699			468

Additional Paid-In Capital (Note 9)		81,155,715			57,852,277

Warrants (Note 10)		4,237,100			–

Deficit		(61,564,544	)		(47,794,059	)

Total Stockholders’ Equity		23,828,970			10,058,686

Total Liabilities and Stockholders’ Equity		26,770,450			32,579,190

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,
	2009			2008
	$			$

Revenue, net of royalties		386,892			586,804

Operating Expenses

Oil and gas production		125,777			304,537
Depletion and accretion		200,050			441,881
Depreciation – property and equipment		39,448			40,429
General and administrative		4,045,906			5,800,116
Foreign exchange loss		2,682,873			317,656
Gain on sale of assets (Note 4)		(126,314	)		–
Impairment loss on oil and gas properties (Note 4)		8,308,229			19,598,916

		15,275,969			26,503,535

Loss from Operations		(14,889,077	)		(25,916,731	)

Other Income (Expense)

Accretion of discounts on convertible debentures (note 7)		(2,922,909	)		(8,525,621	)
Amortization of debt issue costs		(182,637	)		(450,521	)
Interest expense		(753,004	)		(1,283,165	)
Gain on debt extinguishment (Note 7)		3,922,713			–
Interest and royalty income		260,840			622,497
Unrealized gain on fair value of derivatives (Note 8)		793,589			5,952,794

Total Other Income (Expense)		1,118,592			(3,684,016	)

Loss for the Year		(13,770,485	)		(29,600,747	)

Loss Per Share – Basic and Diluted		(0.23	)		(0.80	)

Weighted Average Number of Shares Outstanding – Basic and Diluted		61,113,000			37,192,000

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,
	2009			2008
	$			$
Operating Activities
Loss for the year		(13,770,485	)		(29,600,747	)

Adjustments to reconcile net loss to net cash provided by (used in) operating activities:

Accretion of discounts on convertible debentures		2,922,909			8,525,621
Amortization of debt issue costs		182,637			450,521
Depletion and accretion		200,050			441,881
Depreciation – property and equipment		39,448			40,429
Impairment loss on oil and gas properties		8,308,229			19,598,916
Stock-based compensation		598,182			2,696,143
Gain on sale of assets		(126,314	)		–
Gain on debt extinguishments		(3,922,713	)		–
Unrealized gain on fair value of derivatives		(793,589	)		(5,952,794	)
Unrealized foreign exchange changes		3,183,463			–

Asset retirement costs		(743,338	)		–

Changes in operating assets and liabilities

Unrealized foreign exchange changes		(70,443	)		–
Prepaid expenses		129,982			(103,837	)
Other receivables		691,648			(1,139,216	)
Accounts payable		(134,401	)		88,049
Accrued interest on convertible debentures		(546,302	)		655,107
Accrued liabilities		(47,058	)		53,669

Cash Used in Operating Activities		(3,898,095	)		(4,246,258	)

Investing Activities
Purchase of property and equipment		(13,090	)		(39,458	)
Oil and gas property expenditures		(6,065,289	)		(23,223,585	)
Cash advances from partners		677,842
Proceeds received from sale of oil and gas properties		4,210,306			983,902

Cash Used in Investing Activities		(1,190,231	)		(22,279,141	)

Financing Activities
Proceeds from issuance of common stock		25,560,500			26,824,000
Common stock issuance costs		(2,257,959	)		(1,515,994	)
Convertible debenture repayment		(11,300,000	)		–

Cash Provided by Financing Activities		12,002,541			25,308,006

Unrealized foreign exchange change on cash and cash equivalents		(3,046,333	)		–

Increase (Decrease) in Cash and Cash Equivalents		3,867,882			(1,217,393	)

Cash and Cash Equivalents – Beginning of Year		4,581,589			5,798,982

Cash and Cash Equivalents – End of Year		8,449,471			4,581,589

Cash		8,449,471			1,334,635
Cash equivalents		–			3,246,954

Non-cash Investing and Financing Activities

Common stock issued for conversion of debentures and warrants		2,600,140			16,851,576

Supplemental Disclosures:

Interest paid		1,299,860			628,058

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

F-5

Triangle Petroleum Corporation

Statement of Stockholders’ Equity

Period from January 31, 2007 to January 31, 2008

(Expressed in U.S. dollars)

					Additional
	Common Stock				Paid-in
	Shares		Amount		Capital			Warrants		Deficit			Total
		#	$		$			$		$			$

Balance – January 31, 2007		22,475,866		225		13,088,795			–		(18,193,312	)		(5,104,292	)

Issuance of common stock for cash pursuant to private placement at $2.00 per unit in February 2008		10,412,000		104		20,823,896			–		–			20,824,000

Share issuance costs		–		–		(1,515,994	)		–					(1,515,994	)

Issuance of common stock on conversion of convertible debentures at a weighted average price of $1.268 per share		7,806,664		78		9,899,782			–		–			9,899,860

Fair value of conversion features of convertible debentures converted		–		–		3,372,110			–		–			3,372,110

Change in fair value of conversion features on modification		–		–		82,500			–		–			82,500

Issuance of common stock on exercise of warrants at $1.00 per share in November 2007		6,000,000		60		5,999,940			–		–			6,000,000

Fair value of warrants exercised in November 2007		–		–		3,405,106			–		–			3,405,106

Investor relations services		100,000		1		173,499					–			173,500

Stock based compensation		–		–		2,522,643			–		–			2,522,643

Net loss for the year		–		–		–			–		(29,600,747	)		(29,600,747	)

Balance – January 31, 2008		46,794,530		468		57,852,277			–		(47,794,059	)		10,058,686

Issuance of common stock for cash pursuant to private placement at $1.40 per unit in June 2008		18,257,500		182		21,323,218			4,237,100		–			25,560,500

Share issuance costs		–		–		(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		4,874,013		49		2,600,091			–		–			2,600,140

Fair value of conversion features of convertible debentures converted		–		–		1,039,906			–		–			1,039,906

Stock based compensation		–		–		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

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 valued producing properties in the Fort Worth Basin and in the Alberta Deep Basin.

1.	Going Concern

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 will have to raise additional funds through equity or debt offerings, dispositions of assets or other means to fund general and administrative expenses and to complete the exploration and development phase of its programs. While the Company has been successful in raising funds in the past, there can be no assurance that it will be able to do so in the future. The continuation of the Company as a going concern is dependent upon its ability to obtain necessary additional funds to continue operations and to determine the existence, discovery and successful exploitation of economically recoverable reserves in its resource properties, confirmation of the Company’s interests in the underlying properties, and the attainment of profitable operations.

Failure to obtain additional financing will result in the going concern assumption being inappropriate and adjustments would be required to the carrying values of assets and liabilities, the reported revenues and expenses, and the balance sheet classifications used.

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.

F-7

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

2.	Summary of Significant Accounting Policies (continued)

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.

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 current prices of oil and gas reserves (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 being amortized; plus (C) the lower of cost or estimated fair value of the unproven properties not included in the costs being amortized; 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 cost to be amortized and these costs are subject to the ceiling test.

F-8

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

2. Summary of Significant Accounting Policies (continued)

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.

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.

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 income tax losses are not recognized in the accounts until realization is more likely than not.

On February 1, 2007, the Company adopted the provision of the FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes” (FIN No. 48”), an interpretation of the FASB Statement No. 109, “Accounting for Income Taxes”. FIN No. 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation requires the Company recognize the impact of a tax position in the financial statements if that position is more likely than not of being sustained on audit, based on the technical merits of the position. FIN No. 48 also provides guidance on de-recognition, classification, interest and penalties, and accounting in interim periods and disclosure. In accordance with the provisions of FIN No. 48, any cumulative effect resulting from the change in accounting principle was recorded as an adjustment to the opening deficit balance. As of January 31, 2008 and 2007, the Company did not have any amounts recorded pertaining to uncertain tax positions. The adoption of FIN No. 48 did not impact the Company’s tax provision or the amounts recorded in the financial statements.

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 2009. 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, 2009 and 2008, there were no charges for interest or penalties.

F-9

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

2. Summary of Significant Accounting Policies (continued)

k) Basic and Diluted Net Loss Per Share (“EPS”)

Basic EPS is computed by dividing net loss available to common shareholders (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 all dilutive 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 principally in Canadian dollars. Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash in excess of insured amounts. As at January 31, 2009, the Company has not engaged in any transactions that would be considered derivative instruments or hedging activities. To date, the Company has not incurred a loss relating to this concentration of credit risk.

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.

o)	Comprehensive Loss

As at January 31, 2009 and 2008, the Company has no items that would be included in comprehensive loss other than the net loss and, therefore, has not included a schedule 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. 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.

F-10

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

2. Summary of Significant Accounting Policies (continued)

q)	Recently Adopted Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards ("SFAS") No. 157, "Fair Value Measurements” ("SFAS 157"). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. On February 12, 2008, the FASB issued Staff Position No. FAS 157-2 ("FSP 157-2") which provided for a one year deferral for the implementation of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually).

On February 1, 2008 Triangle elected to implement SFAS 157 with the one-year deferral for certain non-financial assets and liabilities. Beginning February 1, 2009, the Company will adopt the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis.

SFAS 157 (as amended), defines fair value, establishes a framework for measuring fair value, outlines a fair value hierarchy based on inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

Beginning February 1, 2008, assets and liabilities recorded at fair value in the consolidated balance sheets are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels—defined by SFAS 157 and directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities—are as follows:

Level I—Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level II—Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level III—Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

The fair value of the Company’s derivative liabilities was measured using Level III inputs. The significant unobservable inputs to the fair value measurement included estimates of volatility of the share price and term of the contract. The inputs were calculated based on historical data as well as current estimated amounts.

The estimated fair values of derivative liabilities, that was comprised of the conversion feature of the December 8, 2005 convertible debenture is summarized below. The decrease in the derivative liability from January 31, 2008 to January 31, 2009 is primarily attributable to the settlement of derivatives as a result of the repayment of the underlying debentures.

F-11

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

2. Summary of Significant Accounting Policies (continued)

	Significant Unobservable Inputs (Level III) January 31, 2009 $		Significant Unobservable Inputs (Level III) January 31, 2008 $

Derivative liability – conversion feature		-		3,262,846

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115”. This statement permits entities to choose to measure many financial instruments and certain other items at fair value. Most of the provisions of SFAS No. 159 apply only to entities that elect the fair value option. However, the amendment to SFAS No. 115 “Accounting for Certain Investments in Debt and Equity Securities” applies to all entities with available-for-sale and trading securities. Effective February 1, 2008, the Company adopted SFAS No. 159. The adoption of this statement did not have a material effect on the Company's current financial statements.

r)	Recently Issued Accounting Pronouncements

In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements”. SFAS no. 160 requires 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. SFAS No. 160 is effective for the Company commencing on February 1, 2009 and it will not impact the Company's current financial statements.

F-12

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

2. Summary of Significant Accounting Policies (continued)

In 2008, the Securities and Exchange Commission adopted major revisions to its required oil and gas reporting disclosures which become 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. With respect to accounting pronouncements that currently make reference to a single-day pricing regime with respect to oil and gas reserves, the SEC indicated that it was communicating with the FASB staff to align the standards used in the FASB’s pronouncements with the new 12-month average price and that it will consider whether to delay the compliance date based on its discussions with the FASB. The SEC expressed the view that the change from using single-day year-end price to an average price should be treated as a change in accounting principle, or a change in the method of applying an accounting principle, that is inseparable from a change in accounting estimate and that the change would be considered a change in accounting estimate pursuant to Statement of Financial Accounting Standard No. 154 “Accounting Changes and Error Corrections” (SFAS 154) and accounted for prospectively. The SEC further expressed the view that any accounting change resulting from the changes in definitions and required pricing assumptions in Rule 4-10 of Regulation S-X should be treated as a change in accounting principle that is inseparable from a change in accounting estimate, not requiring retroactive revision but requiring recognition in the independent auditor’s report through the addition of an explanatory paragraph. The Company will not be able to determine the impact of these amendments on our results of operation or financial condition until the FASB issues its pronouncements.

s)	Reclassifications

Certain reclassifications have been made to the prior period’s financial statements to conform to the current period’s presentation.

3.	Property and Equipment

	January 31, 2009						January 31, 2008
	Cost $		Accumulated Depreciation $		Net Carrying Value $		Cost $		Accumulated Depreciation $		Net Carrying Value $

Computer hardware		80,748		65,706		15,042		71,712		39,250		32,462
Furniture and equipment		49,674		28,289		21,385		48,464		17,826		30,638
Computer software		12,537		9,199		3,338		9,691		6,670		3,021
Leasehold Improvements		7,927		7,927		–		7,927		7,927		–

		150,886		111,121		39,765		137,794		71,673		66,121

4.	Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas operations whereby all costs of exploring for and developing oil and gas reserves are initially capitalized on a country-by-country (cost center) basis. Capitalized costs, less estimated salvage value, are depleted using the units-of-production method whereby historical costs and future development costs are amortized over the total estimated proved reserves. Costs of acquiring and evaluating unproven properties and major development projects are initially excluded from the depletion and depreciation calculation until it is determined whether or not proved reserves can be assigned to such properties. These costs are assessed periodically to ascertain whether impairment has occurred (i.e., "impairment tests”). 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:

F-13

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

4.	Oil and Gas Properties (Continued)

Year Ended January 31, 2009:

	Costs									Accumulated Depletion and Impairments
												Depletion &							Net Book
	Opening		Additions		Dispositions			Closing		Opening		Impairment		Gain			Closing		Value
	$		$		$			$		$		$		$			$		$

Proved Properties		12,886,510		54,434		(164,985	)		12,775,959		12,472,601		271,199		(40,710	)		12,703,090		72,869
Unproven Properties		34,397,768		4,394,449		(4,045,321	)		34,746,896		9,832,728		8,129,777		(85,604	)		17,876,901		16,869,995

Total		47,284,278		4,448,883		(4,210,306	)		47,522,855		22,305,329		8,400,976		(126,314	)		30,579,991		16,942,864

Year Ended January 31, 2008:

	Costs									Accumulated Depletion and Impairments								Net Book
	Opening $		Additions $		Dispositions $			Closing $		Opening $		Depletion $		Impairment $		Closing $		Value $

Proved Properties		1,764,853		12,105,559		(983,902	)		12,886,510		1,134,874		370,972		10,966,755		12,472,601		413,909
Unproven Properties		21,672,083		12,725,685		-			34,397,768		1,200,567		-		8,632,161		9,832,728		24,565,040

Total		23,436,936		24,831,244		(983,902	)		47,284,278		2,335,441		370,972		19,598,916		22,305,329		24,978,949

Proved Properties

The Company's proved acquisition and exploration costs net of accumulated depletion were distributed in the following geographic areas:

	January 31, 2009 $		January 31, 2008 $

Alberta Deep Basin – Canada		72,869		324,162
Barnett Shale (Texas) – United States		-		89,747

Total proved acquisition and exploration costs		72,869		413,909

In Canada, depletion and depreciation expense for the year ended January 31, 2009 was $86,825 (2008 - $127,816). In the U.S., depletion and depreciation expense for the year ended January 31, 2009 was $5,922 (2008 - $243,156).

During the year ended January 31, 2009:

·	the Company’s proved properties in Alberta exceeded their estimated realizable value which resulted in a $178,452 non-cash impairment loss being recognized; and

the Company sold its interests in a Barnett shale well in June 2008 for gross proceeds of $164,985. The net book value of the US proved property costs at the time of the sale was $131,820 and the related properties had an asset retirement obligation of $7,545. As such the Company recorded a gain on the sale of assets of $40,710.

During the year ended January 31, 2008:

·	the Company’s proved properties in Alberta exceeded their estimated realizable value which resulted in a $6,939,006 non-cash impairment loss being recognized;

·	the Company’s proved properties in Texas exceeded their estimated realizable value which resulted in a $3,082,346 non-cash impairment loss being recognized; and

F-14

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

4.	Oil and Gas Properties (Continued)

·	the Company sold its 27% interest in 12,100 gross acres in northeast Hill County of Texas for gross proceeds of $983,902 (proven land and geological and geophysical costs of $1,929,305) which resulted in a $945,403 non-cash impairment being recognized.

Unproven Properties

All of the Company’s unproven properties are not subject to depletion. The Company's unproven acquisition and exploration costs were distributed in the following geographic areas:

	January 31, 2009 $		January 31, 2008 $

Windsor Block of Maritimes Basin (Nova Scotia)		16,818,586		15,441,144
Beech Hill Block of Maritimes Basin (New Brunswick)		-		21,975
Western Canadian Shale (Alberta and B.C.)		51,409		-
Canada		16,869,995		15,463,119

Fayetteville Shale (Arkansas)		-		8,289,901
Rocky Mountains (Colorado, Montana, Wyoming)		-		812,020
United States		-		9,101,921

Total unproven acquisition and exploration costs		16,869,995		24,565,040

Canada

·	In Canada, $16,869,995 (2008 - $15,463,119) of unproven property costs were excluded from costs subject to depletion which relate to Canadian shale gas exploration costs mainly in the Windsor Block of the Maritimes Basin.

·	The Company anticipates that these costs will be subject to depletion in fiscal 2011, when the Company anticipates having pipelines built and commissioned to market potential gas from the Windsor Block.

·	In July 2008, the Company received cash of $2,943,510 for a partner’s share of its 30% working interest in exploration costs associated with the Windsor Block of Nova Scotia.

·	In December 2008, the Company elected to not drill a test well on the Beech Hill Block thus forfeiting its right to earn on the Block. An impairment of $129,777 was recorded for the full carrying value of the property costs.

United States

·	In the U.S., $nil (2008 - $9,101,921) of unproven property costs were excluded from costs subject to depletion.

In June 2008, the Company sold its 25% working interest in 9,692 net acres in the Phat City area of Montana (Rocky Mountains project) for cash of $800,503. The net book value of the Rocky Mountains project at the time of the sale was $830,508, which related to U.S. Rocky Mountain leasehold acquisition costs. As such the Company recorded a loss on the sale of assets of $30,005.

In September 2008, the Company sold 20 of its 10,437 net Fayetteville acres for $13,000. The Company recorded an $8,000,000 impairment charge on the remaining land at October 31, 2008. In November 2008, the Company sold 240 of its 10,417 net acres for cash of $288,308 and a gain on the sale of assets of $115,609 was recorded.

During the year ended January 31, 2008, the Company’s unproven property costs in the US Rocky Mountains (Colorado and Wyoming) were considered impaired resulting in a $2,104,663 non-cash impairment loss and the Company’s unproven property costs in the Fayetteville Shale Project were considered impaired resulting in a $6,527,498 non-cash impairment loss.

F-15

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

5.	Natural gas and oil reserves (unaudited)

The following table summarizes the changes in the Company’s proved natural gas and oil reserves for the years ended January 31, 2008 and 2009. The Company had two producing wells at the beginning of fiscal 2008 that were not assigned proved reserves. The gas and oil reserve quantities owned by the Company were prepared by the independent petroleum engineering firm of Ryder Scott, Inc.

	Gas (MMcf)									Liquids (Bbls)									Total (MMcfe)
	Canada			US			Total			Canada			US			Total			Canada			US			Total

Proved reserves, February 1, 2007		-			-			-			-			-			-			-			-			-
Extensions, discoveries and other additions		143			52			195			2,603			57			2,660			158			52			210
Production		(40	)		(45	)		(85	)		(757	)		(57	)		(814	)		(44	)		(45	)		(89	)
Proved reserves, February 1, 2008		103			7			111			1,846			-			1,846			114			7			122
Revisions of previous estimates		(34	)		66			32			(29	)		12			(17	)		(34	)		66			32
Production		(27	)		(17	)		(44	)		(639	)		(12	)		(651	)		(31	)		(17	)		(48	)
Proved reserves, February 1, 2009		42			56			98			1,178			-			1,178			49			56			105
Proved developed reserves:
Beginning of year		103			7			111			1,846			-			1,846			114			7			122
End of year		42			56			98			1,178			-			1,178			49			56			105

MMcf – Millions of cubic feet Bbls – Barrels

MMcfe – Millions of cubic feet equivalent (1 Bbls = 6 Mcfoe = 0.006 MMcfe)

The “Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves” (standardized measure) is a disclosure required by Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities” (FAS 69). The standardized measure does not purport to present the fair market value of a company’s proved gas and oil reserves. In addition, there are uncertainties inherent in estimating quantities of proved reserves.

Following is the standardized measure relating to proved gas and oil reserves at January 31, 2009 and 2008:

	Year Ended January 31, 2009						Year Ended January 31, 2008
	Canada		US		Total		Canada		US		Total

Future cash inflows	$	257,474	$	331,049	$	588,523	$	908,391	$	55,070	$	963,461
Future production costs		179,509		236,863		416,372		503,919		37,976		541,895
Future net cash flows		77,965		94,186		172,151		404,472		17,094		421,566
10% annual discount for estimated timing of cash flows		4,675		11,063		15,738		74,493		383		74,876
Standardized measure of discounted future net cash flows	$	73,290	$	83,123	$	156,413	$	329,979	$	16,711	$	346,690

Under the standardized measure, future cash inflows were estimated by applying year-end prices, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Year-end market prices used for the standardized measures above were $5.62 per Mcf (2008 - $7.38 per Mcf) for Canadian gas, $5.78 per Mcf (2008 - $8.10 per Mcf) for U.S. gas and $30.52 per barrel (2008 - $94.22 per barrel) for liquids in 2009. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the year-end statutory rate, after consideration of permanent differences, to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved gas and oil properties. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the standardized measure.

F-16

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

5.	Natural gas and oil reserves (unaudited) (Continued)

Following is an analysis of changes in the standardized measure during the year ended January 31, 2009. The Company had two producing wells at the beginning of fiscal 2008 that were not assigned proved reserves.

	Canada			US			Total

Standardized measure, January 31, 2008	$	329,979		$	16,711		$	346,690
Sales and transfers of gas and oil produced, net of production costs		(185,499	)		(75,617	)		(261,116	)
Accretion of discount		32,998			1,671			34,669
Other		(104,188	)		140,358			36,170
Standardized measure, January 31, 2009	$	73,290		$	83,123		$	156,413

6.	Asset Retirement Obligations

The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and natural gas properties is recorded when a liability is incurred, generally through a lease construction or acquisition or completion of a well. The current estimated costs are escalated at an inflation rate and discounted to present value at a credit adjusted risk-free rate over the estimated economic life of the properties. Such costs are capitalized as part of the basis of the related asset and are depleted as part of the applicable full cost pool. The associated liability is recorded initially as a long-term liability. Subsequent adjustments to the initial asset and liability are recorded to reflect revisions to estimated future cash flow requirements. In addition, the liability is adjusted to reflect accretion expense as well as settlements during the period. A reconciliation of the changes in the asset retirement obligations is as follows:

	January 31, 2009 $			January 31, 2008 $

Balance, beginning of year		1,003,353			90,913
Revision of prior year estimate		-			70,078
Liabilities incurred		548,312			793,624
Liabilities settled as part of disposition		(187,768	)		-
Liabilities settled in cash		(743,338	)		-
Accretion		107,303			48,738
Total asset retirement obligations		727,862			1,003,353

The asset retirement obligations were estimated based on a discount rate of 15%, an inflation rate of 2.5%-3.3% and settlement from 1 to 24 years (mainly 14 years). The total cost estimate prior to discounting was $1,099,000 at January 31, 2009.

F-17

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

7.	Convertible Debentures

Agreement Date	June 14, 2005 $			December 8, 2005 $			December 28, 2005 $			Total $

Balance, January 31, 2007		2,234,375			7,154,806			3,616,551			13,005,732

Modification		-			-			(82,500	)		(82,500	)
Converted		(2,750,000	)		(7,149,859	)		-			(9,899,859	)
Accretion		515,625			4,773,326			3,236,670			8,525,621

Balance, January 31, 2008		-			4,778,271			6,770,721			11,548,992

Converted		-			(2,100,140	)		(3,500,000	)		(5,600,140	)
Accretion – expensed					815,052			2,107,857			2,922,909
Repaid		-			(4,000,000	)		(6,500,000	)		(10,500,000	)
Accretion – settled on repayment		-			506,817			1,121,422			1,628,239
Balance, January 31, 2009		-			-			-			-
Interest rate		8	%		5	%		7.5	%

December 8, 2005 Debentures

On June 5, 2008, the Company repaid the remaining unconverted convertible debentures that were issued on December 8, 2005 of $4,000,000 plus an early redemption fee of $800,000 and accrued interest of $1,299,860. The carrying value of the debentures at the time of repayment, including the conversion feature of the debenture that was accounted for as a derivative, was $4,639,338, which is equal to the face value of $4,000,000, less unamortized discounts of $506,817 and deferred financing costs of $283,196, plus the derivative liability of $1,429,351. The Company paid $4,800,000 on settlement ($4,000,000 face value plus a 20% early redemption fee of $800,000); therefore a $160,662 loss was recorded on the extinguishment of the debenture.

December 28, 2005 Debentures

On January 29, 2008, the Company amended the terms of the December 28, 2005 convertible debentures whereby the maturity date was extended from the third anniversary date from issuance (December 28, 2008 and January 23, 2009) to June 1, 2009. The maturity extension resulted in a change in the fair value of the conversion feature of $82,500.

In December 2008, the Company amended the terms of the December 28, 2005 convertible debentures whereby the conversion price was reduced from $4.00 per share to $1.40 per share and $3,500,000 of the debentures were converted into 2,500,000 common shares, which had a fair value on the date of conversion of $500,000. Subsequent to the amendments, the Company entered into settlement agreements for the remaining debenture of $6,500,000 plus $2,204,792 in accrued interest, whereby the convertible debentures holders agreed to accept $6,500,000 in cash for the final settlement of the debentures and the accrued interest. A gain of $4,083,375 was recorded on this debt extinguishment.

8.	Derivative Liabilities

The Company was required to bifurcate and separately account for the embedded conversion feature contained in the December 8, 2005 convertible debenture as a derivative. In addition, when detachable warrants meet certain requirements they are also required to be recorded as derivative liabilities. The Company was required to record the derivative at the estimated fair value on each balance sheet date with changes in fair values reflected in the statement of operations.

F-18

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

8.	Derivative Liabilities (Continued)

	Warrants
				Exercise price			Fair Value			Conversion Feature Fair Value			Total Fair Value
		#		$			$			$			$

January 31, 2007		6,000,000			1.00			10,451,400			5,541,457			15,992,857
-Exercised/Converted		(6,000,000	)		(1.00	)		(3,405,107	)		(3,372,110	)		(6,777,217	)
-Change in fair value		-			-			(7,046,293	)		1,093,499			(5,952,794	)
January 31, 2008		-			-			-			3,262,846			3,262,846

-Conversion features settled		-			-			-			(1,039,906	)		(1,039,906	)
-Change in fair value		-			-			-			(793,589	)		(793,589	)
-Conversion features settled on repayment		-			-			-			(1,429,351	)		(1,429,351	)
January 31, 2009		-			-			-			-			-

The Company uses the Black-Scholes valuation model to calculate the fair value of derivative liabilities. The following table shows the assumptions used in the calculation of the conversion feature and warrants:

	Strike Price		Volatility			Risk Free Rate			Dividend Yield		Term in Years

Weighted Average Assumptions at:
January 31, 2008 – Conversion feature	$	0.88		72.8	%		2.11	%		–		0.87
June 3, 2008 – Conversion feature on redemption	$	1.66		110.5	%		1.99	%		–		0.51

9.	Common Stock

	Shares		Common Stock		Additional Paid-In Capital
		#	$		$

January 31, 2007		22,475,866		225		13,088,795
Conversion of debentures (b)
-Face value		7,806,664		78		9,899,782
-Fair value of embedded conversion		-		-		3,372,109
Private placement (c)		10,412,000		104		20,823,896
Issuance costs (c)		-		-		(1,515,994	)
Exercise of warrants (d)		6,000,000		60		9,405,047
Investor relations services (e)		100,000		1		173,499
Change in fair value of conversion feature on modification (Note 7)		-		-		82,500
Stock-based compensation ((a) and Note 11)		-		-		2,522,643
January 31, 2008		46,794,530		468		57,852,277
Private Placement, net of share issuance costs of $2,257,959 (f)		18,257,500		182		19,065,259
Conversion of debentures (g)		4,874,013		49		3,639,997
Stock Based Compensation (Note 11)		-		-		598,182
January 31, 2009		69,926,043		699		81,155,715

F-19

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

9.	Common Stock (Continued)

(a)

On May 16, 2005, the Company issued 4,000,000 shares of common stock to the Chief Executive Officer of the Company at $0.01 per share for proceeds of $40,000. On June 2, 2005, the Company issued 2,000,000 shares of common stock to the then President of the Company’s subsidiary at $0.01 per share for proceeds of $20,000. As the shares were issued for below fair value, a discount on the issuance of shares of $6,860,000 was recorded as deferred compensation. During the year ended January 31, 2009, $nil (2008 - $1,056,667) was charged to operations.

(b)

During the year ended January 31, 2008, the Company issued 7,806,664 shares of common stock upon the conversion of $9,899,860 of convertible notes. The fair value of the conversion feature related to the converted debentures was $3,372,109, which was transferred from the derivative liability to additional paid-in capital upon conversion.

(c)

On February 26, 2007, the Company issued 10,412,000 shares of common stock pursuant to a private placement for net proceeds of $19,308,006 after issue costs of $1,515,994. In connection with the financing the Company paid the placement agents of the offering a cash fee of 6.5% of the proceeds of the offering. On March 14, 2007, a registration statement was declared effective for these shares of common stock.

(d)	During the year ended January 31, 2008, the Company issued 6,000,000 shares of common stock upon the exercise of 6,000,000 warrants for $1.00 per warrant. The Company received $6,000,000 in cash proceeds. The fair value of the warrants at the time of exercise was $9,405,047.

(e)	During the year ended January 31, 2008, the Company issued 100,000 shares of common stock at a fair value of $173,500 for investor relation services rendered.

(f)

On June 3, 2008, 18,257,500 units were issued in a private placement for gross proceeds of $25,560,500. The net proceeds after deducting expenses were $23,302,541. The Company paid the placement agents of the offering a cash fee of 7% of the gross proceeds of the offering. Each unit was priced at $1.40 per unit and consists of one share of common stock (relative fair value of $21,323,400 or $1.168 per share) and one-half share purchase warrant (relative fair value of $4,237,100 or $0.232 per unit – see Note 10). One full warrant can be exercised into one share of common stock for a period of two years at a price of $2.25 per share. Pursuant to the terms of the sale, the Company was required, on a best efforts basis, to file a registration statement with the SEC, and to cause such registration statement to be declared effective by the SEC, within 150 days after closing, to permit the public resale of the shares underlying the warrants. The registration statement was declared effective by the SEC on July 14, 2008. Also, pursuant to the terms of the sale, the Company was required, on a best efforts basis, to list the Company’s shares on the Toronto Stock Exchange (which includes the TSX Venture Exchange) on or before December 31, 2008. The Company’s shares of common stock commenced trading on the TSX Venture Exchange on December 5, 2008.

(g)

During the year ended January 31, 2009, $2,100,140 convertible debentures that were issued December 8, 2005 were converted into 2,374,013 shares of common stock. The fair value of the conversion feature related to the converted debentures was $1,039,906, which was transferred from the derivative liability to additional paid-in capital upon conversion. Also, during the year ended January 31, 2009, $3,500,000 convertible debentures that were issued December 28, 2005 were converted into 2,500,000 shares of common stock, which had a fair value on the date of conversion of $500,000 and was recorded to additional paid-in capital.

10.

Warrants

As at January 31, 2009, the Company had 9,128,750 warrants outstanding that can be exercised into 9,128,750 shares of common stock at a price of $2.25 per share, which expire on June 3, 2010. The warrants were granted on June 3, 2008, at which time they had a relative fair value compared to the common stock issued of $4,237,100.

F-20

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

11. Stock Options

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

Effective January 28, 2009, the Company’s Board of Directors approved a Stock Option Plan (the “Rolling Plan”) whereby the number of authorized but unissued Common Shares that may be issued upon the exercise of stock options granted under the Rolling Plan at any time plus the number of Common Shares reserved for issuance under the outstanding 2005 Plan and the 2007 Plan shall not exceed 10% of the issued and outstanding Common Shares on a non-diluted basis at any time, and such aggregate number of Common Shares shall automatically increase or decrease as the number of issued and outstanding common shares change. Pursuant to the Rolling Plan, stock options become exercisable as to one-third on each of the first, second and third anniversaries of the date of the grant, and allow for the granting of stock options at a price of not less than fair value of the common shares and for a term not to exceed ten years. As at January 31, 2009, the Company had 2,007,604 stock options available for granting pursuant to the Rolling Plan.

The weighted average grant date fair value of the 3,800,000 stock options granted during the year ended January 31, 2009 was $0.35 per share (2008 – $1.06 per share). No stock options were exercised during the years ended January 31, 2009 and 2008. During the year ended January 31, 2009, the Company granted, to non-executives/directors, 775,000 stock options under the Rolling Plan (“New Options”) to replace 950,000 forfeited stock options under the 2005 Plan and 2007 Plan (“Old Options”), which was treated as a modification. Under the modification rules, the remaining fair value of the Old Options at modification date, along with the incremental fair value of the New Options over the Old Options at modification date, will be expensed over the New Options vesting period of three years. During the year ended January 31, 2009 and 2008, the Company recorded stock-based compensation related to stock option grants of $598,182 and $2,696,143, respectively, as general and administrative expense.

A summary of the Company’s stock option activity is as follows:

	Options #			Weighted Average Exercise Price $		Aggregate Intrinsic Value $
Outstanding, January 31, 2007		1,630,000			3.31
Granted		1,550,000			2.02
Forfeited		(600,000	)		2.99

Outstanding, January 31, 2008		2,580,000			2.54
Granted		3,800,000			0.67
Forfeited		(1,395,000	)		2.44

Outstanding, January 31, 2009		4,985,000			1.14		-

Exercisable, January 31, 2009		1,460,000			2.29		-

F-21

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

11. Stock Options (Continued)

The weighted average remaining contractual life of stock options outstanding as of January 31, 2009 and 2008 was 4.27 years and 3.13 years, respectively. As at January 31, 2009, there are 460,000 stock options outstanding with an weighted average exercise price of $3.26 and a weighted average remaining contractual life of 1.77 years, 1,350,000 stock options outstanding with an weighted average exercise price of $2.00 and a weighted average remaining contractual life of 3.69 years, 625,000 stock options outstanding with an weighted average exercise price of $1.40 and a weighted average remaining contractual life of 4.42 years, and 2,550,000 stock options outstanding with an weighted average exercise price of $0.24 and a weighted average remaining contractual life of 4.99 years.

The fair value of each option grant was estimated on the date of the grant using the Black-Scholes option pricing model with the following weighted average assumptions:

	Year Ended January 31, 2009			Year Ended January 31, 2008
Expected dividend yield		0	%		0	%
Expected volatility		104	%		71	%
Expected life (in years)		3.5			3.5
Risk-free interest rate		1.71	%		4.23	%

As at January 31, 2009, there was $1,082,880 of total unrecognized compensation costs related to non-vested share-based compensation arrangements granted under the 2005 Plan, 2007 Plan and Rolling Plan which are expected to be recognized over a weighted-average period of 3.2 years. The total fair value of shares vested during the years ended January 31, 2009 and 2008 was $1,079,397 and $1,465,986, respectively.

A summary of the status of the Company’s non-vested shares as of January 31, 2009, and changes during the year ended January 31, 2009, is presented below:

Non-vested shares	Shares #			Weighted-Average Grant-Date Fair Value $

January 31, 2007		782,000			2.80
Granted		1,550,000			0.78
Vested		(902,000	)		2.08
Forfeited		(180,000	)		1.96

January 31, 2008		1,250,000			0.93
Granted		3,800,000			0.33
Vested		(1,165,000	)		0.93
Forfeited		(360,000	)		0.70

January 31, 2009		3,525,000			0.31

F-22

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

(Expressed in U.S. dollars, except as noted)

12. Commitments

Triangle is obligated to incur certain capital to maintain 100% of the 516,000 gross acres for the Windsor Basin Production Lease (57% working interest) before the end of 2014 or acreage may be required to be forfeited. Furthermore, over the last year, the Company has been working to convert the Windsor Block Exploration Agreement to a Production Lease. In December 2008, the Company received approval in principle from the Nova Scotia government for a 10-year production lease in the Windsor Block. The Company has been in discussions with Energy Department officials to finalize the terms of this lease and expects that it will be required to drill at least seven more wells in the Windsor Block over the next three to five years in order to retain rights over the entire Block. Areas of the Block which are not adequately evaluated over that time may be subject to relinquishment.

On February 28, 2007, the Company entered into a lease agreement commencing May 1, 2007 for office premises for a 6 year term expiring May 1, 2013. Annual rent under the new lease is approximately $169,000. The Company must also pay its share of building operating costs and taxes. During the year ended January 31, 2009, the Company paid rent expense of $277,710 (2008 - $202,826).

13. Income Taxes

Income tax expense differs from the amount that would result from applying the U.S federal, state and Canadian income tax rates to earnings (loss) before income taxes. The reconciliation of the provision for income taxes attributable to continuing operations computed at the weighted average statutory tax rate of 37.52% (2008 – 37.22%) to income tax expense as reported is as follows:

	2009		2008
	$		$
Expected income tax benefit	5,058,194		11,038,396
Non-deductible stock-based compensation	(227,309	)	(557,071	)
Non-deductible interest and accretion for convertible debentures	(1,396,847	)	(3,727,339	)
Non-taxable gain on change in fair value of derivatives	301,564		2,262,062
Non-taxable portion of gain on debt extinguishment	762,355		-
Change in tax rates	(680,014	)	213,367
Other and changes in valuation allowance	(3,817,943	)	(9,229,415	)

Provision for income taxes	–		–

The significant components of the Company’s deferred tax assets and liabilities as at January 31, 2009 and 2008 are as follows:

	2009		2008
	$		$
Deferred income tax assets
Resource properties	8,659,221		7,308,000
Net losses carried forward (expire from 2023 to 2028)	7,873,017		5,319,455

Gross deferred income tax assets	16,532,238		12,627,455
Valuation allowance	(16,532,238	)	(12,627,455	)

Net deferred income tax asset	–		–

The Company has recognized a valuation allowance for the deferred income tax asset since the Company cannot be assured that it is more likely than not that such benefit will be utilized in future years. The valuation allowance is reviewed annually. When circumstances change and which cause a change in management's judgment about the realizability of deferred income tax assets, the impact of the change on the valuation allowance is generally reflected in earnings.

F-23

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

None.

ITEM 9A – CONTROLS AND PROCEDURES

MANAGEMENT’S EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is collected and communicated to the management to allow timely decisions regarding required disclosures. The Chief Executive Officer and the Chief Financial Officer have concluded, based on their evaluation as of January 31, 2009 that, as a result of the material weaknesses described below, disclosure controls and procedures were ineffective in providing reasonable assurance that material information is made known to them by others within the Corporation.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with US GAAP. Management has assessed the effectiveness of internal control over financial reporting based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework. A material weakness, as defined by SEC rules, is a control deficiency, or combination of control deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weaknesses in internal control over financial reporting that were identified are:

We did not have sufficient personnel in our accounting and financial reporting functions. Specifically as a result, the Company was not able to achieve adequate segregation of duties and were not able to provide adequate reviews of the financial statements. This control deficiency, which is pervasive in nature, results in a reasonable possibility that material misstatements of the financial statements will not be prevented or detected on a timely basis.

We did not maintain sufficient personnel with an appropriate level of technical accounting knowledge, experience, and training in the application of US GAAP commensurate with our complexity and our financial accounting and reporting requirements. This control deficiency is pervasive in nature and specifically resulted in us restating previously filed annual and quarterly financial statements as a result of errors in the accounting for convertible debentures and warrants. Further, there is a reasonable possibility that material misstatements of the consolidated financial statements including disclosures will not be prevented or detected on a timely basis as a result.

As a result of the existence of these material weaknesses as of January 31, 2009, management has concluded that we did not maintain effective internal control over financial reporting as of January 31, 2009, based on the criteria set forth by COSO in Internal Control-Integrated Framework.

This Annual Report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission.

Changes to Internal Controls and Procedures Over Financial Reporting

Our internal control over financial reporting has been modified during our most recent fiscal year by adding additional advisors to address deficiencies in the financial closing, review and analysis process, which has improved our internal control over financial reporting.

Management’s Remediation Plans

Senior management will monitor the number of personnel employed in the accounting and financial reporting functions. Senior management will consult with external experts to assist with the accounting for complex and non-routine accounting transactions.

ITEM 9B – OTHER INFORMATION

None.

PART III.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Names:	Ages	Titles:	Board of Directors
Mark G. Gustafson	49	Chairman of the Board and Chief Executive Officer; Chief Executive Officer – Elmworth Energy Corporation	Director
J. Howard Anderson	51	President, Chief Operating Officer and Vice-President Engineering; President, Chief Operating Officer and Vice-President Engineering – Elmworth Energy Corporation; President, Chief Operating Officer and Vice-President Engineering – Triangle USA Petroleum Corporation
Shaun Toker	30	Chief Financial Officer and Corporate Secretary; Chief Financial Officer and Corporate Secretary – Elmworth Energy Corporation; Chief Financial Officer and Corporate Secretary – Triangle USA Petroleum Corporation
Stephen A. Holditch (1)	62		Director
David L. Bradshaw (1)	54		Director
Randal Matkaluk (1)	50		Director

(1) Independent Director, Member of Audit Committee, Member of Compensation Committee

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

Officers are elected by the Board of Directors and serve until their successors are appointed by the Board of Directors. Biographical resumes of each officer and director are set forth below.

Mark Gustafson has been our Chief Executive Officer and a Director since May 2005. Between May 2005 and August 2008, Mr. Gustafson was our President and between August 2007 and August 2008, Mr. Gustafson was our Secretary. From September 2004 until January 2006, Mr. Gustafson had been the President and CEO of Torrent Energy Corporation, and between September 2004 and October 2006, Mr. Gustafson had been the Chairman and a director of Torrent, an Oregon based coalbed methane exploration and development company. Between April 1999 and August 2004, Mr. Gustafson was President of MGG Consulting, a private consulting firm. While at MGG Consulting, Mr. Gustafson provided consulting services to investment banks, oil and gas companies, and was a consultant Chief Financial Officer to several private companies. From August 1997 until March 1999, Mr. Gustafson was the President, Chief Executive Officer and a Director of Total Energy Services Ltd., a Calgary-based oilfield rental and gas compression company. Mr. Gustafson received his Chartered Accountant designation with Price Waterhouse in 1983 and received a Bachelor’s Degree in Business Administration from Wilfrid Laurier University in 1981.

J. Howard Anderson has been our President since August 15, 2008 and our Chief Operating Officer and Vice-President Engineering since February 1, 2008. Mr. Anderson is also the President, Chief Operating Officer and Vice-President Engineering for Elmworth Energy Corporation and Triangle USA Petroleum Corporation, our wholly-owned subsidiaries. Between July 2005 and January 2008, Mr. Anderson had been the Vice-President Engineering for Rockyview Energy Inc., an oil and gas production company. Between June 2004 and June 2005, Mr. Anderson was the Manager, Central Business Unit for APF Energy Inc., an oil and gas production company. Between April 2002 and April 2004, Mr. Anderson was the Vice-President Engineering & Development for Pioneer Natural Resources Canada Inc., a subsidiary of Pioneer Natural Resources, a NYSE oil production company. Between 1987 and 2002, Mr. Anderson worked for Canadian Hunter Exploration Ltd., starting as a district engineer and progressing to Manager, Northern Exploration & Development. Between 1979 and 1987, Mr. Anderson worked for Imperial Oil/Esso Resources Canada Ltd. as a Senior Reserve/Operations Engineer. Mr. Anderson received a Bachelor of Science in Engineering Physics (Mechanical/Nuclear) from Queen's University at Kingston in 1979.

Shaun Toker has been our Chief Financial Officer since August 2007 and our Secretary since August 2008. Mr. Toker is also the Chief Financial Officer and Secretary for Elmworth Energy Corporation and Triangle USA Petroleum Corporation, our wholly-owned subsidiaries. Between April 2004 and August 2007, Mr. Toker was the financial controller for Trans-Globe Energy Corp., a public international oil and gas exploration company listed on the American Stock Exchange and Toronto Stock Exchange. Between September 2001 and April 2004, Mr. Toker was a senior accountant with KPMG LLP, in Calgary, Canada. Mr. Toker received his Bachelor’s Degree in Commerce from the University of Alberta in 2001 and has been a Chartered Accountant (Canada) since 2003.

Stephen A. Holditch has been a director of Triangle Petroleum Corporation since February 2006. Since January 2004, Mr. Holditch has been the Head of the Department of Petroleum Engineering at Texas A&M University. Since 1976 through the present, Mr. Holditch has been a faculty member at Texas A&M University, as an Assistant Professor, Associate Professor, Professor and Professor Emeritus. Since its founding in 1977 until 1997, when it was acquired by Schlumberger Technology Corporation, Mr. Holditch was the Founder and President of S.A. Holditch & Associates, Inc., a petroleum technology consulting firm providing analysis of low permeability gas reservoirs and designing hydraulic fracture treatments. Mr. Holditch previously worked for Shell Oil Company and Pan American Petroleum Corporation. Mr. Holditch is a registered Professional Engineer in Texas, has received numerous honors, awards and recognitions and has authored or co-authored over 100 publications on the oil and gas industry. Mr. Holditch received his B.S., M.S. and Ph.D. in Petroleum Engineering from Texas A&M University in 1969, 1970 and 1976, respectively.

David L. Bradshaw has been a director of Triangle Petroleum Corporation since August 2007. Mr. Bradshaw is currently the owner of Waterton Resources, LLC, an oil and gas exploration investment company. Mr. Bradshaw was Managing Director of Comet Ridge Ltd. (Australian Stock Exchange) from September to November 2008 and Director from November 2007 to November 2008. Between August and November 2007, Mr. Bradshaw was interim Chief Executive Officer Trident Resources Corp. Between April and October 2006, Mr. Bradshaw was a director of Trident Resources Corp. Between January 1990 and October 2005, Mr. Bradshaw held several positions at Tipperary Corporation, a publicly listed company, including Director (January 1990 - October 2005), Chairman (1997 - 2005), Chief Financial Officer (1990 - 1996), Chief Operating Officer (1993-1996) and Chief Executive Officer (1996 - October 2005). Mr. Bradshaw has also worked for Price Waterhouse & Co. and Arthur Andersen & Co. Mr. Bradshaw has been a Certified Public Accountant since 1978. Mr. Bradshaw received his Bachelors Degree in Accounting in 1976 and his Masters of Business Administration in 1977, both from Texas A&M University.

Randal Matkaluk has been a director of Triangle Petroleum Corporation since August 2007. Mr. Matkaluk has been the Chief Financial Officer and Corporate Secretary of Vigilant Exploration Inc., a private oil and gas exploration company, since November 2008. From March 2006 to October 2008, Mr. Matkaluk was an independent businessman. Mr. Matkaluk has been a Director and Officer of Virtutone Networks Inc. (formerly "Sawhill Capital Ltd.") since October 2005. Between January 2003 and February 2006, Mr. Matkaluk was the co-founder and Chief Financial Officer of Relentless Energy Corporation, a private oil and gas exploration company. Between June 2001 and December 2002, Mr. Matkaluk was the Chief Financial Officer of Antrim Energy Inc., a public international oil and gas exploration company listed on the Toronto Stock Exchange. Mr. Matkaluk has also worked for Gopher Oil and Gas Company and Cube Energy Corp. Mr. Matkaluk has been a Chartered Accountant since 1983. Mr. Matkaluk received his Bachelors Degree in Commerce in 1980 from the University of Calgary.

The following is a summary of the committees on which our directors serve.

Compensation Committee

Our Compensation Committee currently consists of Messrs. David L. Bradshaw, Randal Matkaluk and Stephen Holditch, with Mr. Matkaluk elected as Chairman of the Committee. Our Board of Directors has determined that all of the members are “independent.” Our Board of Directors has adopted a written charter setting forth the authority and responsibilities of the Compensation Committee.

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

Audit Committee

Report of the Audit Committee

The Audit Committee of the Board of Directors of the Company is currently comprised of three directors, Messrs. David L. Bradshaw, Randal Matkaluk and Stephen Holditch, all of whom satisfy the requirements to serve as Independent Directors, as those requirements have been defined by The Securities and Exchange Commission and NASDAQ. The Board of Directors has determined that Mr. Bradshaw, who is a Certified Public Accountant, licensed in Texas, and having over 25 years of financial experience, qualifies as an "audit committee financial expert." Mr. Bradshaw is independent of management based on the independence requirements set forth in the Financial Industry Regulatory Authority’s definition of "independent director."

The Audit Committee has furnished the following report:

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

The Audit Committee is responsible for overseeing the Company’s overall financial reporting process. In fulfilling its oversight responsibilities for the financial statements for the Company’s fiscal year ended January 31, 2009, the Audit Committee:

-	Reviewed and discussed the annual audit process and the audited financial statements for the fiscal year ended January 31, 2009 with management and KPMG LLP, the Company’s independent auditor;

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

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

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

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

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

Based on the Audit Committee’s review of the audited financial statements and discussions with management and KPMG LLP, the Audit Committee recommended to the Board of Directors that the audited financial statements be included in the Company’s annual report on Form 10-K for the fiscal year ended January 31, 2009 for filing with the SEC.

Audit Committee

David L. Bradshaw, Chairman

Randal Matkaluk

Stephen A. Holditch

Audit Committee Pre-Approval Policy

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

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

Code of Ethics

We have adopted a Code of Ethics that is designed to deter wrongdoing and to promote honest and ethical conduct, full, fair, accurate, timely and understandable disclosure in our SEC reports and other public communications. The Code of Ethics promotes compliance with applicable governmental laws, rules and regulations.

Section 16(a) Compliance

Section 16(a) of the Securities and Exchange Act of 1934 requires our directors and executive officers, and persons who own beneficially more than ten percent (10%) of our Common Stock, to file reports of ownership and changes of ownership with the Securities and Exchange Commission. Copies of all filed reports are required to be furnished to us pursuant to Section 16(a). Based solely on the reports we received and on written representations from reporting persons, we believe that, during fiscal 2009, our directors, executive officers and 10% stockholders complied with all Section 16(a) filing requirements, with the exceptions noted below.

•

A late Form 4 report was filed for Stephen Holditch on June 9, 2008 to report the purchase of 108,000 units in a private placement at a price of $1.40 per unit, effective June 3, 2008. Each unit consisted of one share of common stock and one-half of a warrant, each whole warrant entitling the holder to purchase one share of common stock exercisable at a price of $2.25 for a period of two years.

•

A late Form 4 report was filed for Ron Hietala on July 3, 2008 to report that he retired as an officer and director and was thus no longer a reporting person pursuant to Section 16, effective June 30, 2008.

•

A late Form 4 report was filed for Randal Matkaluk on July 8, 2008 to report the granting of 75,000 stock options, effective July 2, 2008.

•

A late Form 4 report was filed for Stephen Holditch on January 5, 2009 to report the purchase of 50,000 shares of common stock, effective December 26, 2008.

•

A late Form 4 report was filed for Shaun Toker on February 2, 2009 to report the granting of 375,000 stock options, effective January 28, 2009.

•

A late Form 4 report was filed for Howard Anderson on February 2, 2009 to report the granting of 375,000 stock options, effective January 28, 2009.

•

A late Form 4 report was filed for Mark Gustafson on February 2, 2009 to report the granting of 500,000 stock options, effective January 28, 2009.

•

A late Form 4 report was filed for David Bradshaw on February 3, 2009 to report the granting of 150,000 stock options, effective January 28, 2009.

•

A late Form 4 report was filed for Randal Matkaluk on February 3, 2009 to report the granting of 150,000 stock options, effective January 28, 2009.

•

A late Form 4 report was filed for Stephen Holditch on February 17, 2009 to report the granting of 150,000 stock options, effective January 28, 2009.

ITEM 11. EXECUTIVE COMPENSATION.

Summary Compensation Table

The following tables set forth certain information regarding our CEO and each of our most highly-compensated executive officers whose total annual salary and bonus for the fiscal years ending January 31, 2009, 2008 and 2007 exceeded $100,000:

Name & Principal Position	Year	Salary ($)		Bonus ($)		Stock Awards($)		Option Awards ($)		All Other Compen- sation ($)		Total ($)
Mark Gustafson (a),	2009		201,000		29,000		-		47,481		835		278,316
CEO, Principal	2008		288,000		-		606,667		-		1,083		895,750
Executive Officer	2007		153,000		-		2,080,000		-		763		2,233,763

Howard Anderson (b),
President and COO	2009		156,000		-		-		93,798		2,326		252,124

Shaun Toker (c), CFO, Principal	2009		122,000		39,000		-		57,545		5,533		224,078
Financial Officer	2008		56,500		5,000		-		54,760		2,706		118,966

Ron Hietala (d), Former President of	2009		48,000		16,000		-		-		197		64,197
Elmworth Energy	2008		-		-		450,000		-		220,000		670,000
Corporation	2007		-		-		1,350,000		-		240,000		1,590,000

Aly Musani (e),
Former CFO, Principal	2008		78,000		-		-		121,678		3,724		203,402
Financial Officer	2007		120,000		17,500		-		243,356		6,278		387,134

Troy Wagner (f),	2008		133,333		-		-		145,395		12,777		291,505
Former COO	2007		96,282		-		-		282,283		3,294		381,859

Effective February 1, 2006, we agreed to pay a salary of Cdn$12,000 per month to Mr. Gustafson. On November 1, 2006, we agreed to pay a salary of Cdn$24,000 per month to Mr. Gustafson. Effective March 17, 2008, we agreed to pay a salary of Cdn$20,000 per month to Mr. Gustafson.

Effective February 1, 2008, we agreed to pay a salary of Cdn$15,000 per month to Mr. Anderson. On July 1, 2008, we agreed to pay a salary of Cdn$16,667 per month to Mr. Anderson.

Effective September 1, 2007, we agreed to pay an annual salary of Cdn$120,000 to Mr. Toker until December 31, 2007. Effective January 1, 2008, we agreed to pay an annual salary of Cdn$150,000 to Mr. Toker.

On June 23, 2005, we entered into a management consulting agreement with RWH Management Services Ltd. (RWH Management Serves Ltd. is owned by Mr. Hietala). Under the terms of the agreement, we agreed to pay US$20,000 per month for an initial term of two years. The agreement was extended to December 31, 2007. Effective March 17, 2008, we agreed to pay a salary of Cdn$16,667 per month to Mr. Hietala. Mr. Hietala resigned effective June 30, 2008.

Effective January 1, 2006, we agreed to pay a salary of Cdn$12,000 per month to Mr. Musani. Mr. Musani resigned effective August 15, 2007.

Effective August 8, 2006, we agreed to pay an annual salary of Cdn$200,000 to Mr. Wagner. Mr. Wagner resigned effective September 30, 2007.

Employment Agreements with Executive Officers

Mark Gustafson

Effective March 17, 2008, Elmworth Energy Corporation entered into a new employment agreement with Mark Gustafson as Chief Executive Officer, until such time as either party terminates the agreement. Pursuant to the agreement, Mr. Gustafson receives an annual salary of $240,000. In addition, Mr. Gustafson is entitled to receive an annual bonus based upon various criteria targets. Additionally, Mr. Gustafson is entitled to participate in any and all benefit plans, from time to time, in effect for executives, along with vacation, sick and holiday pay in accordance with Elmworth’s policies established and in effect from time to time. In the event that Mr. Gustafson’s employment is terminated by Elmworth without cause (as defined in the agreement), Mr. Gustafson is entitled to a severance payment of three months salary, plus an additional month of salary for every completed year of employment with Elmworth, subject to a maximum severance payment of 12 months salary.

Shaun Toker

Effective January 31, 2008, Elmworth entered into a new employment agreement with Shaun Toker as Chief Financial Officer, until such time as either party terminates the agreement. Pursuant to the agreement, Mr. Toker receives an annual salary of $150,000 and up to an additional $25,000 for filing the quarterly and annual reports of the Company within agreed upon time frames. In addition, Mr. Toker is entitled to receive an annual bonus based upon various criteria targets. Additionally, Mr. Toker is entitled to participate in any and all benefit plans, from time to time, in effect for executives, along with vacation, sick and holiday pay in accordance with Elmworth’s policies established and in effect from time to time. In the event that Mr. Toker’s employment is terminated by Elmworth without cause (as defined in the agreement), Mr. Toker is entitled to a severance payment of three months salary, plus an additional month of salary for every completed year of employment with Elmworth, subject to a maximum severance payment of 12 months salary.

J. Howard Anderson

Effective July 1, 2008, Elmworth entered into a new employment agreement with Mr. Anderson as Chief Operating Officer, until such time as either party terminates the agreement. Pursuant to the agreement, Mr. Anderson receives an annual salary of $200,000. In addition, Mr. Anderson is entitled to receive an annual bonus based upon various criteria targets. Additionally, Mr. Anderson is entitled to participate in any and all benefit plans, from time to time, in effect for executives, along with vacation, sick and holiday pay in accordance with Elmworth’s policies established and in effect from time to time. In the event that Mr. Anderson’s employment is terminated by Elmworth without cause (as defined in the agreement), Mr. Anderson is entitled to a severance payment of three months salary, plus an additional month of salary for every completed year of employment with Elmworth, subject to a maximum severance payment of 12 months salary.

GRANTS OF PLAN-BASED AWARDS

The following table sets forth information regarding the number of stock options granted to named executive officers during fiscal 2009.

Name	Grant Date	All Other Option Awards: Number of Securities Underlying Options (#)		Exercise or Base Price of Option Awards ($/Sh)		Grant Date Fair Value of Stock and Option Awards ($)
Mark Gustafson	July 2, 2008		200,000	$	1.40		155,940
	January 28, 2009		500,000	$	C0.30		88,454
Howard Anderson	February 1, 2008		300,000	$	2.00		138,540
	July 2, 2008		150,000	$	1.40		116,955
	January 28, 2009		375,000	$	C0.30		66,340
Shaun Toker	July 2, 2008		50,000	$	1.40		38,985
	January 28, 2009		375,000	$	C0.30		66,340

Outstanding Equity Awards at Fiscal Year-End Table.

The following table sets forth information for the named executive officers regarding the number of shares subject to both exercisable and unexercisable stock options, as well as the exercise prices and expiration dates thereof, as of January 31, 2009.

Option Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable	Option Exercise Price ($)		Option Expiration Date (mm/dd/yy)
Mark Gustafson		40,000	160,000	$	1.40	07/02/13
		0	500,000	$	C0.30	02/28/14
Howard Anderson		120,000	180,000	$	2.00	02/01/13
		30,000	120,000	$	1.40	07/02/13
		0	375,000	$	C0.30	02/28/14
Shaun Toker		150,000	100,000	$	2.00	08/16/12
		10,000	40,000	$	1.40	07/02/13
		0	375,000	$	C0.30	02/28/14

Director Compensation

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

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

Directors received compensation for their services for the fiscal year ended January 31, 2009 as set forth below:

Name	Fees Earned or Paid in Cash ($)		Stock Awards ($)		Option Awards ($)		Non-Equity Incentive Plan Compensation ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings		All Other Compensation ($)		Total ($)
Stephen A. Holditch	$	40,000	$	0	$	54,457	$	0	$	0	$	0	$	94,457
David L. Bradshaw	$	40,000	$	0	$	76,849	$	0	$	0	$	0	$	116,849
Randal Matkaluk	$	40,000	$	0	$	76,849	$	0	$	0	$	0	$	116,849

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

The following table sets forth certain information regarding beneficial ownership of our common stock as of April 7, 2009.

by each person who is known by us to beneficially own more than 5% of our common stock;

by each of our officers and directors; and

by all of our officers and directors as a group.

NAME AND ADDRESS OF OWNER	TITLE OF CLASS	NUMBER OF SHARES OWNED (1)			PERCENTAGE OF CLASS (2)

Mark Gustafson	Common Stock		2,907,500	(3)		4.15	%
Suite 1250, 521-3rd Avenue SW
Calgary, Alberta T2P 3T3 Canada

Howard Anderson	Common Stock		803,500	(4)		1.14
Suite 1250, 521-3rd Avenue SW
Calgary, Alberta T2P 3T3 Canada

Stephen A. Holditch	Common Stock		555,600	(5)		*
Suite 1250, 521-3rd Avenue SW
Calgary, Alberta T2P 3T3 Canada

Shaun Toker	Common Stock		220,000	(6)		*
Suite 1250, 521-3rd Avenue SW
Calgary, Alberta T2P 3T3 Canada

David L. Bradshaw	Common Stock		220,000	(7)		*
Suite 1250, 521-3rd Avenue SW
Calgary, Alberta T2P 3T3 Canada

Randal Matkaluk	Common Stock		190,000	(6)		*
Suite 1250, 521-3rd Avenue SW
Calgary, Alberta T2P 3T3 Canada

All Officers and Directors	Common Stock		4,896,600	(8)		6.85	%
As a Group (6 persons)

Palo Alto Investors, LLC	Common Stock		14,751,350	(9)		21.10	%
470 University Avenue
Palo Alto, California 94301

Sprott Asset Management	Common Stock		10,262,700	(10)		13.99	%
200 Bay Street, Suite 2700
Box 27 Toronto, Ontario M5J 2J1

Luxor Capital Group, LP	Common Stock		8,163,200	(11)		11.39	%
767 Fifth Avenue, 19th Floor
New York, New York 10153

* Less than 1%.

(1) Beneficial Ownership is determined in accordance with the rules of the Securities and Exchange Commission and generally includes voting or investment power with respect to securities. Shares of common stock subject to options or warrants currently exercisable or convertible, or exercisable or convertible within 60 days of April 7, 2009 are deemed outstanding for computing the percentage of the person holding such option or warrant but are not deemed outstanding for computing the percentage of any other person.

(2) Based upon 69,926,043 shares issued and outstanding on April 7, 2009.

(3) Represents 54,000 shares of common stock underlying warrants that are currently exercisable and 80,000 shares of common stock underlying options that are currently exercisable or exercisable within 60 days.

(4) Represents 54,000 shares of common stock underlying warrants that are currently exercisable and 240,000 shares of common stock underlying options that are currently exercisable or exercisable within 60 days.

(5) Represents 7,000 shares of common stock underlying warrants that are currently exercisable and 510,000 shares of common stock underlying options that are currently exercisable or exercisable within 60 days.

(6) Represents shares of common stock underlying options that are currently exercisable or exercisable within 60 days.

(7) Represents 10,000 shares of common stock underlying warrants that are currently exercisable and 190,000 shares of common stock underlying options that are currently exercisable or exercisable within 60 days.

(8) Represents 125,000 shares of common stock underlying warrants that are currently exercisable and 1,430,000 shares of common stock underlying options that are currently exercisable or exercisable within 60 days.

(9) As reported pursuant to a Schedule 13G filed with the Securities and Exchange Commission on February 17, 2009. Palo Alto Investors, LLC is a registered investment adviser and general partner of Micro Cap Partners, L.P., Palo Alto Global Energy Master Fund, L.P., Palo Alto Global Energy Fund, L.P., Palo Alto Small Cap Master Fund, L.P. and Palo Alto Small Cap Fund, L.P., who in the aggregate, own 14,751,350 shares of Triangle common stock. Palo Alto Investors is the manager of Palo Alto Investors, LLC. William L. Edwards is the controlling shareholder and President of Palo Alto Investors. Each of Mr. Edwards, PAI and Palo Alto Investors disclaims beneficial ownership of the common stock except to the extent of that person's pecuniary interest therein and each disclaims that it is, the beneficial owner, as defined in Rule 13d-3 under the Securities Exchange Act of 1934, of any of the common stock.

(10) As reported pursuant to a Schedule 13G/A filed with the Securities and Exchange Commission on February 13, 2009. Includes 3,420,900 shares of common stock issuable upon exercise of warrants. Kirstin McTaggart, the Chief Compliance Officer of Sprott Asset Management has voting and dispositive power over the shares held by Sprott Asset Management. Ms. McTaggart disclaims beneficial ownership of the common stock.

(11) As reported pursuant to a Schedule 13G/A filed with the Securities and Exchange Commission on June 9, 2008. Luxor Capital Group, LP is the investment manager of Luxor Capital Partners, LP, LCG Select, LLC, Luxor Spectrum, LLC, Luxor Capital Partners Offshore, Ltd., LCG Select Offshore, Ltd. and Luxor Spectrum Offshore, Ltd., who in the aggregate, beneficially own 8,163,200 shares of our common stock, which includes 1,719,369 shares of common stock issuable upon exercise of warrants. Luxor Management, LLC is the general partner of Luxor Capital Group. Mr. Christian Leone is the managing member of Luxor Management. LCG Holdings, LLC is the general partner of Luxor Capital Partners, LP and the managing member of LCG Select, LLC and Luxor Spectrum, LLC. Mr. Leone is the managing member of LCG Holdings. Each of Mr. Leone, LCG Holdings, Luxor Management and Luxor Capital Group disclaims beneficial ownership of the common stock except to the extent of that person's pecuniary interest therein and each disclaims that it is, the beneficial owner, as defined in Rule 13d-3 under the Securities Exchange Act of 1934, of any of the common stock.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE.

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

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

Audit Fees

The aggregate fees billed by our current auditor, for professional services rendered for the audit of our annual financial statements during the years ended January 31, 2009 and 2008, and for the reviews of the financial statements included in our Quarterly Reports on Form 10-Q during the fiscal years, were $130,000 and $nil, respectively.

The aggregate fees billed by our previous auditor, for professional services rendered for the audit of our annual financial statements during the years ended January 31, 2009 and 2008, and for the reviews of the financial statements included in our Quarterly Reports on Form 10-Q during the fiscal years, were $43,900 and $75,960, respectively.

Audit-Related Fees

Our current independent registered public accounting firm billed us $97,000 and $nil during the fiscal years ended January 31, 2009 and 2008, respectively, for audit related services. These services relate to required securities filings such as prospectus, Form S-1 and Form S-8.

Our previous independent registered public accounting firm billed us $13,500 and $7,918 during the fiscal years ended January 31, 2009 and 2008, respectively, for audit related services.

Tax Fees

Our current independent registered public accounting firm billed us $17,760 and $3,675 during the fiscal years ended January 31, 2009 and 2008 for tax related work.

Our previous independent registered public accounting firm billed us $nil and $20,000 during the fiscal years ended January 31, 2009 and 2008 for tax related work.

All Other Fees

Our current and previous independent registered public accounting firm did not bill us during fiscal years ended January 31, 2009 or 2008 for other services.

The Board of Directors and Audit Committee have considered whether the provision of non-audit services is compatible with maintaining the principal accountant's independence.

PART IV.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

Exhibit No.		Description

3.1		Articles of Incorporation, filed as an exhibit to the registration statement on Form SB-2 filed with the Securities and Exchange Commission on February 27, 2004 and incorporated herein by reference.

3.2		Articles of Amendment to the Articles of Incorporation, changing the name to Triangle Petroleum Corporation, filed with the Nevada Secretary of State on May 10, 2005.

3.3		Bylaws of the Company, filed as an exhibit to the registration statement on Form SB-2 filed with the Securities and Exchange Commission on February 27, 2004 and incorporated herein by reference.

10.01		2005 Incentive Stock Plan, filed as an exhibit to the Registration Statement on Form S-8, filed with the Commission on October 14, 2005 and incorporated herein by reference.

10.02		2007 Incentive Stock Plan, filed as an exhibit to the Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on September 14, 2007 and incorporated herein by reference.

10.03		Master License Agreement, dated as of June 15, 2005, between Elmworth Energy Corporation and Millennium Seismic Ltd., filed as an exhibit to the registration statement on Form SB-2 filed with the Securities and Exchange Commission on October 7, 2005 and incorporated herein by reference.

10.03		Participation Agreement, dated as of October 26, 2005, by and between Triangle USA Petroleum Corporation and Kerogen Resources, Inc., filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on October 28, 2005 and incorporated herein by reference.

10.04		Joint Exploration Agreement, dated as of October 28, 2005, by and between Triangle USA Petroleum Corporation and Hunter Energy LLC, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on November 8, 2005 and incorporated herein by reference.

10.05		Letter Exploration Agreement, dated as of September 19, 2006, by and between Triangle USA Petroleum Corporation and Kerogen Resources Inc., filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on October 2, 2006 and incorporated herein by reference.

10.06		Form of Indemnification Agreement, filed as an exhibit to the Post-Effective Amendment No. 5 to Form SB-2 on Form S-1, filed with the Commission on August 31, 2007 and incorporated herein by reference.

10.07		Form of Debenture Amendment Agreement, dated as of January 14, 2008, by and between Triangle Petroleum Corporation and Bank Sal. Oppenheim Jr. & Cie., (Schweiz) AG, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on February 1, 2008 and incorporated herein by reference.

10.08		Form of Debenture Amendment Agreement, dated as of January 14, 2008, by and between Triangle Petroleum Corporation and Centrum Bank AG, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on February 1, 2008 and incorporated herein by reference.

10.09		Form of Employment Agreement, effective as of January 31, 2008, by and between Elmworth Energy Corporation and Shaun Toker, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on February 1, 2008 and incorporated herein by reference.

10.10		Form of Employment Agreement, effective as of February 1, 2008, by and between Elmworth Energy Corporation and J. Howard Anderson, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on February 1, 2008 and incorporated herein by reference.

10.11		Form of Employment Agreement, effective as of March 17, 2008, by and between Elmworth Energy Corporation and Mark Gustafson, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on March 21, 2008 and incorporated herein by reference.

10.12		Form of Employment Agreement, effective as of March 17, 2008, by and between Elmworth Energy Corporation and Ron Hietala, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on March 21, 2008 and incorporated herein by reference.

14.01		Code of Ethics for Senior Financial Officers, filed as an exhibit to the annual report on Form 10-KSB filed with the Securities and Exchange Commission on May 16, 2005 and incorporated herein by reference.

14.02		Audit Committee Charter, filed as an exhibit to the annual report on Form 10-KSB filed with the Securities and Exchange Commission on May 16, 2005 and incorporated herein by reference.

21.01		List of subsidiaries, filed as an exhibit to the Registration Statement on Form SB-2, filed with the Commission on January 18, 2006 and incorporated herein by reference.

23.01		Consent of Ryder Scott, Independent Petroleum Engineers.

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

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

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

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

SIGNATURES

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

TRIANGLE PETROLEUM CORPORATION

Date: April 8, 2009	By:	/s/ MARK GUSTAFSON
	Mark Gustafson
	Chief Executive Officer (Principal Executive Officer)

Date: April 8, 2009	By:	/s/ SHAUN TOKER
	Shaun Toker
	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

POWER OF ATTORNEY

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

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

Name	Position	Date

/s/ MARK GUSTAFSON	Chief Executive Officer (Principal Executive Officer)	April 8, 2009
Mark Gustafson	and Director

/s/ SHAUN TOKER	Chief Financial Officer (Principal Financial Officer and	April 8, 2009
Shaun Toker	Principal Accounting Officer)

/s/ DAVID L. BRADSHAW	Director	April 8, 2009
David L. Bradshaw

/s/ STEPHEN A. HOLDITCH	Director	April 8, 2009
Stephen A. Holditch

/s/ RANDAL MATKALUK	Director	April 8, 2009
Randal Matkaluk

1100 LOUISIANA	SUITE 3800	HOUSTON, TEXAS 77002-5218	Telephone (713) 651-9191	Fax (713) 651-0849

600 SEVENTEENTH	SUITE 900N	DENVER, COLORADO 80202-5401	Telephone (303) 623-9147	Fax (303) 623-4258

	By:	/S/ MARK GUSTAFSON
Date: April 8, 2009	Name:	Mark Gustafson
	Title:	Chief Executive Officer