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, 2008

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 class: Common Stock, $0.00001 par value

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 oAccelerated filer o

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

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act.)  Yeso   Nox

The aggregate market value of the voting common equity held by non-affiliates as of July 31, 2007, based on the closing sales price of the Common Stock as quoted on the Over-the-Counter Bulletin Board was $50,127,204. 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 24, 2008, there were 48,653,758 shares of issuer’s common stock outstanding.

TRIANGLE PETROLEUM CORPORATION

FORM 10-K

For the Fiscal Year Ended January 31, 2008

	Page
Part I
Item 1. Business	3
Item 1A. Risk Factors	9
Item 1B. Unresolved Staff Comments	14
Item 2. Properties	15
Item 3. Legal Proceedings	19
Item 4. Submission of Matters to a Vote of Security Holders	19
	Page
Part II
Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	20
Item 6. Selected Financial Data	21
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	22
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	31
Item 8. Financial Statements and Supplementary Data	32
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	33
Item 9A. Controls and Procedures	33
Item 9B. Other Information	34
	Page
Part III
Item 10. Directors and Executive Officers of the Registrant	35
Item 11. Executive Compensation.	40
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	44
Item 13. Certain Relationships and Related Transactions, and Director Independence	45
Item 14. Principal Accounting Fees and Services	45
	Page
Part IV
Item 15. Exhibits and Financial Statement Schedules	47
Signatures.	51

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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 are an exploration company focused on emerging shale gas opportunities in the Maritimes Basin of Nova Scotia, Canada. We are one of the first companies to explore in the Maritimes shale plays and drilled two new wells on the Windsor Block (516,000 gross acres, 361,200 net acres) in Nova Scotia in late 2007.In addition, we also have an interest in the Fayetteville Shale trend in Arkansas (20,874 gross acres, 10,437 net acres). An experienced team comprising technical and business skills has been formed to optimize our opportunities through our operating subsidiaries, Triangle USA Petroleum Corporation in the United States and Elmworth Energy Corporation in Canada.

THE SHALE GAS INDUSTRY

It is estimated that at the end of 2006, total shale-gas resources in the U.S. were between 500 and 600 trillion cubic feet (Tcf) and that more than 35,000 shale-gas wells were producing in the U.S., with cumulative production of about 600 billion cubic feet (Bcf) per year. The most well known shale gas plays in the U.S. are the Barnett, Fayetteville, Woodford, Antrim and New Albany and in Canada is the Montney.

Shale gas is essentially natural gas contained within a sequence of predominantly fine grained rocks, dominated by shale. Shale gas plays are considered area plays since shale gas, similar to coal bed methane (CBM), is often found over large contiguous areas. Most shales have low matrix permeability’s and require the fracturing of the shale to achieve commercial gas production rates. The low permeability of shale gas reservoirs results in recovery rates of approximately 20% of original gas in place compared to approximately 75% for conventional reservoirs.

In general, shale reservoirs have the following characteristics:

· initial production rates that range from 20 thousand cubic feet per day (mcf/d) to greater than 1,000 mcf/d and decline approximately 60% in the first year and cover very large areas;

· low decline rates after the first year — generally less than 5% per year (typically 2% to 3%);

· long production lives (up to 30 years);

· potential to be thick (up to 1,500 feet);

· typically organically rich;

· contain large gas reserves (5 billion cubic feet (bcf) to 100 bcf per section);

· low matrix porosity and permeability; and

· the requirement for stimulation (fracing) to be economic.

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The combination of tax credits and advances in technology has helped shale gas production increase steadily since the early 1980’s. Advanced fracturing fluids and horizontal drilling are two of the more important technological advances. At the end of 2005, shale gas accounted for approximately 3% of total U.S. natural gas production and shale gas could supply 10% of the nation’s needs by 2015.

Far and away the most productive shale gas play in the U.S. is the Barnett Shale play in the Fort Worth Basin. While the Barnett Shale has been one of the more popular onshore plays over the last couple of years, its success was a long time in the making. The unlocking of the value of the Barnett Shale began in the early 1980’s when Mitchell Energy (now part of Devon Energy) began experimenting with foam fractures in an effort to increase flow rates. Today, operators are using a variety of advanced fracturing techniques and horizontal drilling technology to substantially increase production rates. Several operators in Johnson County in the Barnett Shale have drilled horizontal wells that have initial production rates in the 2.1 to 5 mmcf/d range. The Barnett Shale play continues to expand outward from its core Newark East field and currently produces in excess 2 bcf/d. The most exciting new shale gas play in the U.S. is the Fayetteville Shale near Conway County, Arkansas.

With several companies in the early stages of delineating other shale natural gas plays and continued production growth from existing plays, we believe that shale gas production in North America will continue to grow for years to come. Due to the long-life nature of shale gas plays, the substantial advances in technology in recent years and today’s high commodity price environment, the economics of shale gas have never been better.

OUR OPERATIONS

During fiscal 2008, we had exploration operations in three areas:

· Maritimes Basin of Eastern Canada - we drilled 2 test wells (1.4 net) during fiscal 2008 and we have 516,000 gross acres (361,200 net) of contiguous oil and gas leaseholds. During fiscal 2009, we plan to have a joint venture partner join a summer/fall drilling and completion program which we are targeting to drill up to six wells for a gross cost of approximately $35 million;

· Fayetteville Shale of the Arkoma Basin - we drilled one well (0.5 net) during fiscal 2008, which is awaiting completion and we have 20,874 gross acres (10,437 net) of oil and gas leaseholds. We hope to conclude the sale of this acreage before the start of the summer drilling program in the Maritimes Basin; and

· US Rocky Mountains - we drilled one well (0.25 net) during fiscal 2008 that was non-productive. 

During fiscal 2008, we had two producing wells in the Alberta Deep Basin, Canada, and six producing wells in the Barnett Shale of Texas, U.S.

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 recently attracted a great deal of interest from numerous other companies and it is expected that the competition for land, personnel and equipment will become more intense over the months and years ahead.

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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 obligation.

Canada

The oil and natural gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. Such regulation includes requiring permits for the drilling of wells; maintaining bonding requirements in order to drill or operate wells; implementing spill prevention plans; limiting the venting or flaring of gas; submitting notification and receiving permits relating to the presence, use and release of certain materials incidental to oil and gas operations; regulating the location and spacing of wells, the method of drilling and casing wells, the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities, surface usage and the restoration of properties upon which wells have been drilled, the plugging and abandoning of wells and the transporting of production. The effect of these regulations is to limit the amounts of oil and gas we may be able to produce from our wells and to limit the number of wells or the locations at which we may be able to drill. We do not expect that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and gas industry participants of similar size.

In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than government lands are determined by negotiations between the mineral owner and the lessee. Royalties on government land are determined by government regulation and are generally calculated as a percentage of the value of gross production, and the rate of royalties payable generally depends upon prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

In Nova Scotia and New Brunswick, the royalty reserved to the Crown in respect of natural gas production is 10%. In Alberta, the royalty reserved to the Crown in respect of natural gas production, subject to various incentives, is between 5% and 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying exploratory natural gas wells spudded or deepened after July 31, 1985 and before June 1, 1988 is eligible for a royalty exemption for a period of 12 months, up to a prescribed maximum amount. Natural gas produced from qualifying intervals in eligible gas wells spudded or deepened to a depth below 2,500 meters is also subject to a royalty exemption, the amount of which depends on the depth of the wells. In mid 2007, the Alberta Crown announced proposed royalty changes that would increase royalties, with the new royalty for natural gas production proposed to be between 5% and 50%. Theses changes are not expected to have a significant impact on our current operational plans or reserves.

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The North American Free Trade Agreement among the governments of Canada, the United States and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms that are contained in the Canada-U.S. Free Trade Agreement. Subject to the General Agreement on Tariffs and Trade, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, so long as any export restrictions do not:

· reduce the proportion of energy resources exported relative to total supply (based upon the proportion prevailing in the most recent 36 month period or another representative period agreed upon by the parties);

· impose an export price higher than the domestic price (subject to an exception that applies to some measures that only restrict the value of exports); or

· disrupt normal channels of supply.

All three countries are prohibited from imposing minimum or maximum export or import price requirements, with some limited exceptions.

United States

Our operations are or will be subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells; maintaining bonding requirements in order to drill or operate wells; implementing spill prevention plans; submitting notification and receiving permits relating to the presence, use and release of certain materials incidental to oil and gas operations; and regulating the location of wells, the method of drilling and casing wells, the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities, surface usage and the restoration of properties upon which wells have been drilled, the plugging and abandoning of wells and the transporting of production. Our operations are or will be also subject to various conservation matters, including the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in a unit, and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally limit the venting or flaring of gas, and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas we may be able to produce from our wells and to limit the number of wells or the locations at which we may be able to drill.

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 Alberta, all applicable environmental laws are consolidated in the Alberta Environmental Protection and Enhancement Act. Under this Act, environmental standards and requirements applicable to compliance, cleanup and reporting have been made more strict. Also, the range of enforcement actions available and the severity of penalties have been significantly increased. These changes will have an incremental increase in the cost of conducting oil and natural gas operations in Alberta.

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In 1994, the United Nations' Framework Convention on Climate Change came into force and three years later led to the Kyoto Protocol which requires, upon ratification, nations to reduce their emissions of carbon dioxide and other greenhouse gases. In December 2002, the Canadian federal government ratified the Kyoto Protocol. If certain conditions are met and the Kyoto Protocol enters into force internationally, Canada will be required to reduce its greenhouse gas (GHG) emissions. Currently the upstream crude oil and natural gas sector is in discussions with various provincial and federal levels of government regarding the development of greenhouse gas regulations for the industry. It is premature to predict what impact these potential regulations could have on us but it is possible that we would face increases in operating costs in order to comply with a GHG emissions target.

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.

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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 24, 2008, we had eight full time employees, including our CEO, President, Chief Financial Officer, Chief Operating Officer, Vice President Exploration, land manager, operations manager and accounting manager and we had two part time employees, including our office manager and accounting clerk. We consider our relations with our employees to be good.

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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 $29,600,747 and $4,281,969 for the years ended January 31, 2008 and 2007, 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 Auditors Have 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 24, 2008, our independent auditors stated that our financial statements for the year ended January 31, 2008 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. Our company has 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 in our company.

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.

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If We Are Unable to Retain the Services of Messrs. Gustafson and Hietala 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, President, and a director and Mr. Ron Hietala, a director and President of Elmworth Energy Corporation, our wholly-owned subsidiary. Loss of the services of Messrs. Gustafson or Hietala could have a material adverse effect on our growth, revenues, and prospective business. We have obtained key-man insurance on the life of Mr. Hietalaand do not intend to further pursue key man insurance on the life of Mr. Gustafson at this time. 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.

The Potential Profitability of Oil and Gas Ventures Depends Upon Factors Beyond the Control of Our Company.

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 our company 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. We cannot predict whether governments will convert our exploration agreements into production agreements, including our Windsor Block exploration agreement with the Nova Scotia governments which is due to expire on September 15, 2008.

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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 Our Company.

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, water discharges and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. However, such laws and regulations are frequently changed and we are unable to predict the ultimate cost of compliance. Generally, environmental requirements do not appear to affect us any differently or to any greater or lesser extent than other companies in the industry.

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

11

Any Change in Government Regulation and/pr 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 the ability of our company 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.

Risks Relating to Our Outstanding Financing Arrangements:

There Are Essentially a Limitless Number of Shares Underlying Our Convertible Debentures That May be Available for Future Sale and the Sale of These Shares May Depress the Market Price of Our Common Stock.

As of April 24, 2008, we had 48,653,758shares of common stock issued and outstanding, secured convertible debentures issued on December 8, 2005 outstanding that may be converted into 3,294,160 shares of common stock based on current market prices, and convertible debentures issued on December 28, 2005 and January 23, 2006 outstanding that may be converted into 2,500,000 shares of common stock. All of the shares, including all of the shares issuable upon conversion of the convertible debentures, may be sold without restriction. The sale of these shares may adversely affect the market price of our common stock.

The Continuously Adjustable Conversion Price Feature of Our Secured Convertible Debentures Could Require Us to Issue a Substantially Greater Number of Shares, Which Will Cause Dilution to Our Existing Stockholders. 

Our obligation to issue shares upon conversion of our secured convertible debentures issued to YA Global Investments on December 8, 2005 is essentially limitless. The following is an example of the number of shares of our common stock that are issuable, upon conversion of our $4,625,000 remaining face amount of secured convertible debentures (excluding accrued interest), based on market prices 25%, 50% and 75% below the market price, as of April 24, 2008 of $1.56.

			With		Number		% of
% Below	Price Per		Discount		of Shares		Outstanding
Market	Share		at 10%		Issuable		Stock
25%	$	1.17	$	1.053		4,392,213		8.28	%
50%	$	0.78	$	0.702		6,588,319		11.93	%
75%	$	0.39	$	0.351		13,176,638		21.31	%

As illustrated, the number of shares of common stock issuable upon conversion of our secured convertible debentures will increase if the market price of our stock declines, which will cause dilution to our existing stockholders.

The Continuously Adjustable Conversion Price Feature of our Secured Convertible Debentures May Encourage Investors to Make Short Sales in Our Common Stock, Which Could Have a Depressive Effect on the Price of Our Common Stock.

The secured convertible debentures are convertible into shares of our common stock at a 10% discount to the trading price of the common stock prior to the conversion. The downward pressure on the price of the common stock as the selling stockholder converts and sells material amounts of common stock could encourage short sales by investors. Short sales by investors could place further downward pressure on the price of the common stock. In addition, not only the sale of shares issued upon conversion of secured convertible debentures, but also the mere perception that these sales could occur, may adversely affect the market price of the common stock.

12

The Issuance of Shares Upon Conversion of the Secured Convertible Debentures and Convertible Debentures May Cause Immediate and Substantial Dilution to Our Existing Stockholders.

The issuance of shares upon conversion of the secured convertible debentures and convertible debentures may result in substantial dilution to the interests of other stockholders since the selling stockholders may ultimately convert and sell the full amount issuable on conversion. Although YA Global Investments, L.P. may not convert its secured convertible notes if such conversion would cause it to own more than 4.99% of our outstanding common stock and Bank Sal. Oppenheim Jr. & Cie., (Schweiz) AG and Centrum Bank may not convert their convertible debentures if such conversion would cause them to own more than 4.9% of our outstanding common stock, this restriction does not prevent YA Global Investments, L.P., Bank Sal. Oppenheim Jr. & Cie., (Schweiz) AG or Centrum Bank from converting and/or exercising some of their holdings and then converting the rest of their holdings. In this way, YA Global Investments, L.P., Bank Sal. Oppenheim Jr. & Cie., (Schweiz) AG and Centrum Bank could sell more than their limit while never holding more than this limit. There is no upper limit on the number of shares that may be issued upon conversion of the secured convertible debentures issued to YA Global Investments, L.P. which will have the effect of further diluting the proportionate equity interest and voting power of holders of our common stock, including investors in this offering.

If We Are Required for any Reason to Repay Our Outstanding Convertible Debentures, We Would Be Required to Deplete Our Working Capital, If Available, Or Raise Additional Funds. Our Failure to Repay the Convertible Debentures, If Required, Could Result in Legal Action Against Us, Which Could Require the Sale of Substantial Assets.

In December 2005, we entered into three securities purchase agreements for the sale of an aggregate of $25,000,000 principal amount of convertible debentures, secured and unsecured. The $15,000,000 in secured convertible debentures, of which $4,625,000 remained outstanding as of April 24, 2008, are due and payable, with 5% interest, three years from the date of issuance, unless sooner converted into shares of our common stock. Additionally, the $10,000,000 in convertible debentures, which all remained outstanding as of April 24, 2008, are due and payable, with 7.5% interest, on June 1, 2009, unless sooner converted into shares of our common stock. In addition, any event of default such as our failure to repay the principal or interest when due, our failure to issue shares of common stock upon conversion by the holder, our failure to have our registration statements continue to be effective, breach of any covenant, representation or warranty in the Securities Purchase Agreements or related convertible debentures, the assignment or appointment of a receiver to control a substantial part of our property or business, the filing of a money judgment, writ or similar process against our company in excess of $50,000, the commencement of a bankruptcy, insolvency, reorganization or liquidation proceeding against our company and the delisting of our common stock could require the early repayment of the convertible debentures, secured and unsecured, including default interest rate on the outstanding principal balance of the debentures if the default is not cured with the specified grace period. We anticipate that the full amount of the convertible debentures, secured and unsecured, will be converted into shares of our common stock, in accordance with the terms of the convertible debentures. If we were required to repay the convertible debentures, secured and unsecured, we would be required to use our limited working capital and raise additional funds. If we were unable to repay the debentures when required, the debenture holders could commence legal action against us and foreclose on all of our assets to recover the amounts due. Any such action would require us to curtail or cease operations.

If an Event of Default Occurs under the Securities Purchase Agreement dated December 8, 2005, Secured Convertible Debentures or Security Agreements, the Investors Could Take Possession of all Our Goods, Inventory, Contractual Rights and General Intangibles, Receivables, Documents, Instruments, Chattel Paper, and Intellectual Property.

In connection with the Securities Purchase Agreement dated December 8, 2005, we and our subsidiaries executed Security Agreements in favor of the investors granting them a first priority security interest in all of our goods, inventory, contractual rights and general intangibles, receivables, documents, instruments, chattel paper, and intellectual property. The Security Agreements state that if an event of default occurs under the Securities Purchase Agreement, Secured Convertible Debentures or Security Agreements, the Investors have the right to take possession of the collateral, to operate our business using the collateral, and have the right to assign, sell, lease or otherwise dispose of and deliver all or any part of the collateral, at public or private sale or otherwise to satisfy our obligations under these agreements.

13

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 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. If we fail to remain current on our reporting requirements, we could be removed from the OTC Bulletin Board. 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 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.

14

ITEM 2. PROPERTIES.

We maintain our principal office at 1250, 521 – 3^rd 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 $17,307 Cdn (approximately $17,307 US) per month for the first three years and $18,172 Cdn (approximately $18,172 US) per month for the remaining three years. We must also pay our share of building operating costs and taxes.

Maritimes Basin – Eastern Canadian Shale Gas Project

During fiscal 2007 and in early fiscal 2008, a multi-disciplined geoscience team screened prospective basins in Eastern Canada. The screening process included an assessment of the geologic 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 with a Canadian company to pursue two shale gas opportunities in the Maritimes Basin in March and May of 2007.

Beech Hill Block

The first farm-in agreement was entered into in March 2007 and covers approximately 68,000 gross acres in the Moncton Sub-Basin of the Maritimes Basin located in the province of New Brunswick, Canada. We are entitled to earn a 70% working interest in the block subsequent to the acquisition and evaluation of a minimum $250,000 seismic program no later than June 1, 2008 and then electing no later than December 31, 2008 to drill a test well. These work commitments have not been satisfied as at April 24, 2008. We are currently assessing if the exploration well will proceed on this Block. The Block is covered by leases and licenses to search for oil and natural gas with the New Brunswick government which expire from February 2009 to June 2011. Production royalties on this Block are 10% government and 4.5% third party. Our partner may elect to convert its 30% working interest to a 5% gross overriding royalty after the test well is drilled.

Windsor Block

The second farm-in agreement was entered into in May 2007 and covers approximately 516,000 gross acres in the Windsor Sub-Basin of the Maritimes Basin located in the province of Nova Scotia, Canada. During fiscal 2008, we earned a 70% working interest in the block by drilling and completing a test well. Production royalties on this Block are 10% government and 4.5% third party. Our partner has until July 8, 2008 to elect to convert its 30% working interest to a 5% gross overriding royalty. During fiscal 2008, we spent approximately $14 million on our Windsor Basin exploration program, consisting of drilling and completing two wells, a 2D and 3D seismic program and geological studies. Both of the test wells, the seismic and geological studies have provided us with sufficient valuable technical information to conclude that this is a significant shale gas resource project. Based upon an estimated resource of 89 to 109 Bcf per section (square mile) from Schlumberger's log analysis, we believe this project has sufficient gas in place to drive our exploration program. The Block is covered by an exploration agreement with the Nova Scotia government which expires on September 15, 2008. During fiscal 2009, we plan to work with the Nova Scotia government to transition the exploration agreement into a production agreement. A production agreement application must be submitted to the government before September 15, 2008, at which time the Nova Scotia government will have 6 months to review the agreement and approve it. If the agreement is not approved, our right to explore for and develop oil and gas on this Block would be forfeited. We plan to submit the production agreement before the end of May 2008. Also, we plan to have a joint venture partner join us in the summer/fall drilling and completion program within the Windsor Basin.

Summary of the two wells we drilled and completed in the Windsor Basin in fiscal 2008:

The first well, Kennetcook #1, reached a total depth of 4,390 feet and was rig released on September 15, 2007 after running casing to total depth. Kennetcook #1 is located 25 miles west of the community of Truro, Nova Scotia. This well was extensively cored over an interval of 1,254 feet. Based upon the preliminary log analysis and lab work, the primary zone of interest is approximately 350 feet thick and the secondary zone of interest is approximately 260 feet thick. Advanced well log data was acquired on this well and the data was integrated with the special core measurements performed by service companies with extensive unconventional shale gas expertise.

15

The second well, Kennetcook #2, reached a total depth of 6,350 feet and was rig released on October 13, 2007 after running casing to total depth. Kennetcook #2 is located approximately two miles north-west of Kennetcook #1 and was cored over an interval of 392 feet. Similar logging programs to Kennetcook #1 were performed and the integration with shale gas laboratory measurements was performed. Based upon preliminary log analysis, the primary shale zone in Kennetcook #2 is approximately 500 feet thick. Both Kennetcook #1 and Kennetcook #2 are vertical test wells designed to provide us with technical information to assess the Horton Bluff shale potential in the Windsor Basin.

We concluded that a comprehensive hydraulic fracture stimulation program was warranted to assess the Horton Bluff deliverability. As such, a stimulation program was designed in October 2007 based on favorable laboratory measurements of rock properties, gas content and fluid compatibility. The design required two frac water holding ponds to be constructed, each with the capacity to hold up to 2.5 million gallons of fluid, and the Kennetcook #1 well to be completed first with the results of this operation used to guide the completion planning for Kennetcook #2.

A large, slick water fracture stimulation program was performed in two stages on each well during the later part of November and early December 2007. The Kennetcook #1 first stage frac used 850,000 gallons of slick water with 560,000 pounds of sand proppant, and the second stage frac used 660,000 gallons of water and 386,000 pounds of sand. The Kennetcook #2 first stage frac used 641,000 gallons of slick water with 176,000 pounds of sand, and the second stage frac used 653,000 gallons of water and 366,000 pounds of sand. Stimulations of this magnitude are in line with the current stimulations in the Barnett Shale of the Fort Worth Basin and the Fayetteville Shale of the Arkoma Basin.

In early December 2007, after the initial stimulations, both of the wells were placed on flowback to recover frac fluids, with the exception of a temporary shut-in during the Christmas break. In late January 2008, we installed downhole pumps on both wells with the intent of increasing the frac fluid recovery rates. During January 2008, natural gas (predominantly methane) began bubbling out of the recovered completion frac water in Kennetcook #2. In the latter half of February 2008, a free gas column began to build in the Kennetcook #2 casing while water continued to be pumped up the tubing. Wellhead pressure increased to over 500 psi while fluid levels in the casing continued to drop. On March 4, 2008, crews opened the well to flow through a separator, and small quantities of gas were flared.

Kennetcook #2 continues to flow frac fluids to the surface and to flare gas. We continue to be encouraged by free gas flow of approximately 15 mcf/d at Kennetcook #2, particularly as field crews continue to pump previously-injected frac water out of the well. Additional water still needs to be removed in order to reduce the bottomhole pressure and increase gas production rates. To accelerate water removal, we plan to install a larger, higher-capacity pump in the well. We anticipate that Kennetcook #2 should demonstrate higher production rates after the limiting effects of water in the wellbore are removed. As of April 24, 2008, approximately 81% of the 1.3 million gallons of water that had been pumped into the reservoir during the completion process has been recovered.

During March 2008, Kennetcook #1 continued to show production of dissolved gas, however free gas production had not yet been observed as of the latter half of March. Accordingly, after 90 days of testing operations this well was shut-in. Kennetcook #1 may prove useful in future drilling programs (micro seismic well monitor, fluid disposal, etc). It is important to note that Kennetcook #1 and Kennetcook #2 were specifically drilled as "test" wells to obtain scientific and geological data on which to base our future drilling strategies. Management believes that these two wells were successful based on their initial objectives and the amount of quality technical data derived.

Summary of the 2D and 3D seismic program in the Windsor Basin in fiscal 2008:

An aggressive seismic program was acquired during October 2007: the 25 square mile 3-D program covers our initial target area over the Kennetcook wells and the 30 mile 2-D program extends to another favorable area of the land block. Shot hole drilling for both the 3-D and the 2-D programs has been completed and all the data was recorded. The processing phase of the seismic program was finished in early December. Interpretation of this data was completed in March 2008. The first application of the interpreted 3-D seismic program will be to select well locations for the fiscal 2009 drilling program.

Summary of the geological studies in the Windsor Basin in fiscal 2008:

The Kennetcook #1 and Kennetcook #2 wells were drilled specifically for the purpose of providing us with the necessary technical information in order to fully assess the Upper Devonian to Lower Mississippian shale potential within the Horton Bluff formation. The Kennetcook #1 and Kennetcook #2 wells were selectively completed and fracture-stimulated in organic rich shale zones.

16

Extensive coring was undertaken while drilling the two Kennetcook wells including 1,254 feet of core from Kennetcook #1 and 392 feet of core from Kennetcook #2. More than 140 samples were submitted to multiple labs for analyses that included Leco TOC (total organic carbon content derived from the Leco Corporation carbon analyzer), RockEval (detection of type and maturity of organic matter with the Rock Eval module), organic facies determination, maturity, gas desorption, gas composition, XRD (X-ray diffraction to characterize composition of the shale), CT scans, mechanical rock properties and fluid compatibility studies. Petrophysical interpretations were derived from the extensive log suites taken on the two wells integrated with core and sample derived data.

A comprehensive interpretation of source rock potential, thermal maturity, headspace gas composition, canister gas desorption, adsorption and composition, and physical properties of selected samples of both wells was performed by the analytical laboratories of the Weatherford Group (Humble Geochemical, OMNI Laboratories, and TICORA Geosciences) and Global Geoenergy Research Ltd.

Average TOC from all shale samples was 10%. Organic matter type was determined by organic facies analysis as Type II/III to Type III. Maturity of the shales in the zones of interest as measured by the vitrinite reflectance ranged from 1.53% to 2.07%, placing the shale's maturity within the peak window for natural gas generation.

X-ray diffraction data (XRD) indicates that the shales in the Horton Bluff contain an average of 52% quartz and carbonate with 42% clays. Clay type has been identified as a predominately kaolinite-illite mixture with more minor amounts of chlorite and mixed layer clays.

Summary of gas marketing

We are well positioned with the Windsor and Beech Hill Blocks located near the Maritimes & Northeast Pipeline (M&NP). The M&NP was built in 1999 to transport natural gas from offshore developments in Nova Scotia to Maine, New Hampshire and Massachusetts where it connects with the Algonquin Gas Transmission’s hub line and the North American pipeline grid at Dracut.

The pipeline is 670 miles in length, with 340 miles in the US and 330 miles in Canada. The capacity is 420 mmcfe/d in the US and 530 mmcfe/d in Canada without compression. The M&NP is owned by Spectra Energy Transmission (77.53%), Emera Inc. (12.92%) and ExxonMobil Corporation (9.55%).

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

In October 2007, we entered into a new joint venture agreement with our Houston based operating partner. The new joint venture includes a 52 township Area of Mutual Interest ("AMI") in Conway, Faulkner, Pope and Van Buren Counties, which covers a significant portion of the core producing areas of the Fayetteville, and consists of 20,874 gross acres (10,437 net). Both Companies hold an equal 50% working interest. The term of this agreement is for three years.

Under the terms of this new joint venture agreement, the operator is obligated to spud one new net horizontal well before July 31, 2008, in which we will pay 67% of the capped capital costs to earn a 50% interest. If the well is not spudded by July 31, 2008, we will automatically earn our 50% working interest in the AMI. All future operations under the joint venture will be shared on an equal basis. The noted drilling commitment is a replacement for a previous drilling commitment on the acreage originally acquired by both companies. To date, the operator has not satisfied this drilling commitment.

Prior to entering into the new joint venture agreement described above, we participated in drilling one vertical test well in Conway County, which is awaiting completion. The location is covered by a 12 square mile proprietary 3-D seismic survey. An adjacent second 12 square mile proprietary 3-D seismic survey has been shot and is currently being processed and merged with the first survey.

Based upon escalating land prices in this basin and due to the lack of progress in accelerating the exploration program, we decided in late March 2008 to sell our 10,437 non-operated net acres. We are planning to sell this acreage in the most effective manner by assessing new industry activity and overall direct acreage sales. The sale of this acreage is expected to be concluded this summer.

17

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

In fiscal 2006, we embarked on a joint venture with a Denver based operator. We made an initial commitment to participate in the drilling of three projects, where we were obligated to pay 33% of the drilling costs to earn a 25% working interest. The project areas are geographically located in northwestern Colorado, southwestern Wyoming, and northern Montana. The gross acreage position in the three areas is approximately 77,000 acres. To date, we have drilled two of the three projects.

Although the initial test wells in Colorado and Wyoming were not successful in the primary targets, opportunity exists based on area operators pursuing additional exploration programs. The third prospect in this project, located in Northern Montana, has not yet been drilled. Given the priority of our shale gas projects, and the operator's delay in initiating drilling on the project, we are not actively pursuing this project at this time.

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

In fiscal 2009, there is no exploration activity planned on this project. We currently have six shale gas wells pipeline connected and producing various rates of gas.

We participated in a five-county joint venture program with a Houston based operator where our working interests range from 6% to 27%. Approximately 12,400 gross acres was leased. In July 2007, we sold our working interest position (27%) of approximately of 12,100 gross acres of undeveloped acreage. The remaining acreage contains two producing wells which we participated in at a lower working interest (approximately 6%). The two wells are currently producing at various rates. The operator of these wells has commenced voluntary bankruptcy proceedings. As a result, we have not received our monthly production revenue since January 2007; however the amounts owing to us have been set aside by the bankruptcy trustee in a separate bank account. In addition, we continue to receive monthly statements detailing our share of production revenue and related production royalties and operating expenses. We have advised the trustee to sell our interest in the two wells in an auction of the operator’s assets that is to be concluded this summer.

We participated in another joint venture which drilled four Barnett Shale gas wells in late 2006 where our working interests range between 11% and 15%. All four horizontal wells were on production as of November 2007; however, two wells are currently temporarily shut-in.

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

In fiscal 2009, there is no exploration activity planned on this project. We originally licensed a 120 square mile seismic data set, at a cost of approximately $1.3 million, to assist in the generation of prospective drilling sites. To date, we have participated in drilling and/or completing seven Deep Basin wells. These wells were drilled as part of four different joint ventures with varying working interests.

We are producing from two of seven wells. The first well located in the Kakwa Area where 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 in this well. Of the remaining five wells drilled by us, one of the wells tested fresh water, with no natural gas present and the other four wells tested gas but at rates that that were uneconomic to warrant a pipeline tie-in based on today’s natural gas pricing environment.

18

Information with regard to oil and gas producing activities follows:

Net Reserves of Crude Oil and Natural Gas Liquids and Natural Gas at Year-End 2008

The following table summarizes our January 31, 2008 reserves estimates and future discounted cash flow at 10%, plus our 12 month production for the year ended January 31, 2008 for these wells.

	Alberta Deep  Basin, Canada		Texas Barnett  Shale, U.S.A		Total
Estimated Proved Developed Producing Reserves:
Total Working Interest Reserves (MMcfe)		164		10		173
Total Company Net Reserves (MMcfe)		114		7		121
Discounted Cash Flow-10%	$	329,979	$	16,711	$	346,690
Fiscal 2008 Working Interest Production (MMcfe)		55		65		120

MMcfe – Millions cubic feet equivalent

We refer you to Note 6 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.

19

PART II

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

MARKET INFORMATION

Our common stock is quoted on the OTC Bulletin Board under the symbol “TPLM”.

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

	Fiscal Year 2007
	High		Low
First Quarter	$	5.24	$	3.62
Second Quarter	$	4.07	$	2.05
Third Quarter	$	3.45	$	2.06
Fourth Quarter	$	3.24	$	1.95

	Fiscal Year 2008
	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

HOLDERS

As of April 24, 2008, we had approximately 15 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

On May 9, 2005, we declared a stock dividend of six shares of common stock for each one share of common stock outstanding. 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 November, 2007, we issued 3,039,725 shares of common stock upon conversion of $3,199,860 of a previously issued convertible debenture. The shares were issued pursuant to an exemption under Section 4(2) of the Securities Act of 1933.

In November, 2007, we issued 6,000,000 shares of common stock upon the exercise of 6,000,000 previously issued share purchase warrants for total cash proceeds of $6,000,000. The shares were issued pursuant to an exemption under Section 4(2) of the Securities Act of 1933.

In December, 2007, we issued 50,000 shares of common stock to Torrey Hills Capital for investor relations serviced provided to us. The shares were issued pursuant to an exemption under Section 4(2) of the Securities Act of 1933.

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Subsequent to Fiscal Year End

In March 2008, we issued 782,554 shares of common stock upon conversion of $600,140 of a previously issued convertible debenture. The shares were issued pursuant to an exemption under Section 4(2) of the Securities Act of 1933.

In April 2008, we issued 1,076,674 shares of common stock upon conversion of $875,000 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 24, 2008. 

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		1,580,000	$	3.00		420,000
Equity compensation plans not approved by shareholders		1,300,000	$	2.00		700,000
Total		2,880,000	$	2.55		1,120,000

ITEM 6. SELECTED FINANCIAL DATA.

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

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

The following information should be read in conjunction with the consolidated financial statements and the notes thereto contained elsewhere in this report. The Private Securities Litigation Reform Act of 1995 provides a "safe harbor" for forward-looking statements. Information in this Item 6, "Management's Discussion and Analysis of Financial Conditions and Results of Operations," and elsewhere in this 10-K that does not consist of historical facts, are "forward-looking statements." Statements accompanied or qualified by, or containing words such as "may," "will," "should," "believes," "expects," "intends," "plans," "projects," "estimates," "predicts," "potential," "outlook," "forecast," "anticipates," "presume," and "assume" constitute forward-looking statements, and as such, are not a guarantee of future performance. The statements involve factors, risks and uncertainties including those discussed in the “Risk Factors” section contained elsewhere in this report, the impact or occurrence of which can cause actual results to differ materially from the expected results described in such statements. Risks and uncertainties can include, among others, fluctuations in general business cycles and changing economic conditions; changing product demand and industry capacity; increased competition and pricing pressures; advances in technology that can reduce the demand for the Company's products, as well as other factors, many or all of which may be beyond the Company's control. Consequently, investors should not place undue reliance on forward-looking statements as predictive of future results. The Company disclaims any obligation to update the forward-looking statements in this report.

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 commence shifting towards an oil and gas exploration company. In connection with the shift in operational focus, we changed our name to Triangle Petroleum Corporation.

The changeover from a mining to an oil and gas exploration company has taken place over the past two years, during one of the strongest markets for oil and natural gas. The average monthly price for West Texas Intermediate (WTI) crude oil and natural gas (Henry Hub Nymex), currently, as compared to the past, is as follows:

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Although these strong commodity prices have resulted in extremely competitive conditions for the supply of products and services for exploration companies, our outlook remains positive. Despite these strong fundamentals, it should be noted that significant short term fluctuations in North American natural gas prices have occurred based upon seasonal weather patterns and gas storage levels. It should also be noted that actual prices received for oil and gas are typically less than the WTI and Henry Hub prices, respectively. This discount varies from time to time and is based on location, quality and other factors.

Plan of Operations

Our corporate strategy is to utilize our US 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. Based on activity to date, we have carefully selected and designated one project as core from our portfolio of projects based on our belief that it provides the best prospect for exploring for commercial quantities of gas. This core project is focused on a shale gas opportunity located in the Maritimes Basin of 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 have a secondary project focused on securing an initial land position in a Western Canadian Shale Project. Our remaining four project areas (Fayetteville Shale, Rocky Mountain Conventional Programs, Barnett Shale and Alberta Deep Basin) are currently designated as non-core due to existing market conditions related to land costs, drilling costs and completion costs, and focusing our limited manpower resources.

Maritimes Basin – Eastern Canadian Shale Gas Project

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 geologic 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 with a Canadian company to pursue two shale gas opportunities in the Maritimes Basin in March and May of 2007.

Beech Hill Block

The first farm-in agreement was entered into in March 2007 and covers approximately 68,000 gross acres in the Moncton Sub-Basin of the Maritimes Basin located in the province of New Brunswick, Canada. We are entitled to earn a 70% working interest in the block subsequent to the acquisition and evaluation of a minimum $250,000 seismic program no later than June 1, 2008 and then electing no later than December 31, 2008 to drill a test well. These work commitments have not been satisfied as at April 24, 2008. We are currently assessing if the exploration well will proceed on this Block. The Block is covered by leases and licenses to search for oil and natural gas with the New Brunswick government which expire from February 2009 to June 2011.

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Windsor Block

The second farm-in agreement was entered into in May 2007 and covers approximately 516,000 gross acres in the Windsor Sub-Basin of the Maritimes Basin located in the province of Nova Scotia, Canada. During fiscal 2008, we earned a 70% working interest in the block by drilling and completing a test well. Our partner has until July 8, 2008 to elect to convert its 30% working interest to a 5% gross overriding royalty. During fiscal 2008, we spent approximately $16 million on our Windsor Basin exploration program, consisting of drilling and completing two wells, a 2D and 3D seismic program and geological studies. Both of the test wells, the seismic and geological studies have provided us with sufficient valuable technical information to conclude that this is a significant shale gas resource project. Based upon an estimated resource of 89 to 109 Bcf per section (square mile) from Schlumberger's log analysis, we believe this project has the gas in place to drive our exploration program. The Block is covered by an exploration agreement with the Nova Scotia government which expires on September 15, 2008. During fiscal 2009, we plan to work with the Nova Scotia government to transition the exploration agreement into a production agreement must be submitted to the government before September 15, 2008, at which time the Nova Scotia government will have 6 months to review the agreement and approve it. If the agreement is not approved, our right to explore for and develop oil and gas on this Block would be forfeited. We plan to submit the production agreement before the end of May 2008. Also, we plan to have a joint venture partner join a summer/fall drilling and completion program which we are targeting to drill up to six wells for a gross cost of approximately $35 million.

Western Canadian Shale Program

We continue to actively evaluate various shale packages in Alberta and British Columbia. Our objective is to secure an initial land position prior to the end of 2008 and to commence an exploration program next year. This follows the corporate strategy in the Maritimes Basin of utilizing our US shale gas experience to secure early stage shale gas projects in Canada.

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

Based upon escalating land prices in this basin and due to the lack of progress in accelerating the exploration program, we decided in late March 2008 to sell our 10,400 non-operated net acres. We are planning to sell this acreage in the most effective manner by assessing new industry activity and overall direct acreage sales. The sale of this acreage is expected to be concluded this summer.

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

Although the initial test wells in Colorado and Wyoming were not successful in the primary targets, opportunity exists based on area operators pursuing additional exploration programs. The third prospect in this project, located in Northern Montana, has not yet been drilled. Given the priority of our shale gas projects, and the operator's delay in initiating drilling on the project, we are not actively pursuing this project at this time.

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

In fiscal 2009, there is no exploration activity planned on this project. We have six low working interest shale gas wells pipeline connected (5.75%-15% working interest), of which four are currently producing. Two are expected to come back on production in the near future. The operator of two of the six wells has commenced voluntary bankruptcy proceedings. We continue to receive monthly statements detailing our share of production revenue and related production royalties and operating expenses. We have advised the trustee to sell our interest in the two wells in an auction of the operator’s assets that is to be concluded this summer.

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

In fiscal 2009, there is no exploration activity planned on this project. 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.

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Results of Operations

Daily Sales Volumes, Working Interest before royalties

		2008		2007
Barnett Shale in Texas, USA	Mcfpd		177		40
Deep Basin in Alberta, Canada	Mcfpd		152		-
Total Company	Mcfpd		329		40
Total Company	Boepd		55		7

Net Operating Results

		2008		2007
Volumes	Mcf		119,927		14,674
Price	$/Mcf		6.52		4.73
Revenue		$	781,696	$	69,428
Royalties			194,892		15,086
Revenue, net of royalties			586,804		54,342
Production expenses			304,537		-
Net		$	282,267	$	54,342

For the year ended January 31, 2008, we realized $781,697, in revenue from sales of natural gas and natural gas liquids, as compared to $69,428 for the year ended January 31, 2007. This revenue was the result of production from six small working interest wells located in the Barnett Shale in Texas that came on production in the three months ended October 31, 2006, two wells located in the Deep Basin of Alberta that came on production in the three months ended July 31, 2007 and two additional wells located in the Barnett Shale in Texas that came on production in the three months ended October 31, 2007. Royalties related to this revenue totaled $194,892 and $15,086 (25% and 22% of revenue, respectively) for the years ended January 31, 2008 and 2007, respectively. Production expenses related to this revenue totaled $304,537 and $nil ($15.24/Boe and $nil/Boe) for the years ended January 31, 2008 and 2007, respectively.

Depletion, Depreciation and Accretion (“DD&A”)

	2008		2007
DD&A – oil and gas properties	$	441,881	$	36,229
Depreciation – property and equipment		40,429		26,627
Total	$	482,310	$	62,856
Total per BOE	$	24.13	$	25.71

Due to the startup of production in the three months ended October 31, 2006, depletion on the proven oil and gas properties was calculated and expensed at $25.71/BOE in the year ended January 31, 2007 compared to $24.13 for the comparable period of 2008.

Unproven property costs of $24,565,040 (2007 - $20,471,516) were excluded from costs subject to depletion at January 31, 2008.

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Impairment Costs

	2008		2007
Proved property cost impairment:
Alberta Deep Basin	$	6,939,003	$	1,098,645
Texas Barnett shale		4,027,749		-
Unproven property cost impairment
Fayetteville Shale		6,527,501		-
US Rocky Mountains		2,104,663		182,854
Total	$	19,598,916	$	1,281,499

In the current year, we recognized proved property impairments of $6,939,003 related to the Alberta Deep Basin and $4,027,749 related to the Barnett Shale, that management now considers non-core assets. These were mainly the result of low gas prices, higher costs to drill and complete the wells than anticipated and lower production and reserves than forecasted. Included in the Barnett Shale impairment of $4,027,749 was an impairment loss of $945,403 related to land and geological and geophysical costs of $1,929,305 spent on 12,100 gross acres (27% working interest) in northeast Hill County of Texas that was sold for gross proceeds of $983,902 on July 18, 2007. In the year ended January 31, 2007, we recognized an impairment charge of $1,098,645 related to the Alberta Deep Basin assets primarily as a result of a dry hole.

We recognized an unproven property costs impairment of $2,104,663 in the year ended January 31, 2008 (January 31, 2007 - $182,854) related mainly to land, seismic purchase and drilling costs in the US Rocky Mountains related to the Colorado and Wyoming prospects that we drilled and have determined to not move forward on. We recognized an unproven property cost impairment $6,527,501 in the current year related to the Fayetteville Shale project since we have elected to sell all our Fayetteville land in 2008. As a result we have written-off $5,971,671 of exploration costs mainly related to the drilling of the Ed Gordon well and Happy Hollow seismic which are no longer recoverable. Also, we have expensed land costs in the Fayetteville project of $555,830 related to land prospecting fees which resulted in no acreage acquisition.

As a result of the above impairments, the net carrying value of our oil and gas properties costs is distributed as follows:

	January 31, 2008 $		January 31, 2007 $
Maritimes Basin – Eastern Canada Shale		15,463,119		654,159
Arkoma Basin, Arkansas - Fayetteville Shale		8,289,901		7,569,101
U.S. Rocky Mountains (Colorado, Montana, Wyoming)		812,020		2,187,391
Alberta Deep Basin – Western Canada		324,162		6,154,643
Greater Fort Worth Basin, Texas - Barnett Shale		89,747		4,536,201
Net carrying value of acquisition and exploration costs		24,978,949		21,101,495

General and Administrative (“G&A”)

	2008		2007
Salaries, wages and consulting fees	$	1,537,870	$	1,043,594
Other, travel and office expense		1,566,103		1,346,320
Stock-based compensation		2,696,143		5,825,356
G&A	$	5,800,116	$	8,215,270

General and administrative expenses have decreased significantly in the year ended January 31, 2008 compared to 2007 primarily due to decreased stock-based compensation expense mainly as a result of shares issued to our executives that have now been fully recognized.

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Accretion of Discounts on Convertible Debentures

Agreement Date	2008		2007
June 14, 2005	$	515,626	$	2,990,625
December 8, 2005		4,773,326		3,826,025
December 28, 2005		3,236,669		3,333,334
Total accretion of discounts	$	8,525,621	$	10,149,984

Accretion of discounts on convertible debentures decreased in the year ended January 31, 2008 compared to 2007 due primarily to the June 14, 2005 debenture discounts predominately realized prior to fiscal 2008.

Interest Expense

Agreement Date	2008		2007
June 14, 2005	$	18,918	$	309,239
December 8, 2005		514,247		663,732
December 28, 2005		750,000		734,761
Total interest expense	$	1,283,165	$	1,707,732

Interest expense decreased for the year ended January 31, 2008 compared to 2007 due primarily to the June 14, 2005 convertible debentures being fully converted as at June 2007.

Liquidity and Capital Resources

To date, we have generated minimal revenues and have incurred operating losses in every quarter. We are an early stage exploration 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, 2008, we had working capital of $362,974, excluding non-cash derivative liabilities and the current portion of convertible debentures, resulting primarily from accrued interest of $2,751,096 and payables of $3,533,833 offset by our cash and cash equivalents of $4,581,589. For the year ended January 31, 2008, we had net cash outflow from operating activities of $4,246,258, mainly related to cash general and administrative expenses.

We have $16,100,140 of convertible debentures outstanding as at January 31, 2008. As at April 24, 2008, we have $14,625,000 of convertible debentures outstanding. The convertible debentures have three separate maturity dates. First, $5,000,000 matures on December 8, 2008 which are 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. We anticipate that these convertible debentures will be fully converted prior to the maturity date. Subsequent to January 31, 2008, $375,000 of these convertible debentures were converted. Second, $1,100,140 matures on January 17, 2009 which are 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. Subsequent to January 31, 2008, these convertible debentures were fully converted. Third, $10,000,000 matures on June 1, 2009 which are convertible at $4.00. Based on the current share price, conversion is not likely and we will either be required repay or refinance these debentures.

We are currently committed to pay 66% of the drilling and completion costs for one well in our Fayetteville project to earn a 50% working interest. The operator must spud this well before July 31, 2008 or we automatically earn our 50%. We do not expect to incur any drilling costs in fiscal 2009 to fulfill this commitment since we are in the process of selling our interest in the Fayetteville project. We are also committed to pay 33% of the costs to drill one well in our Rocky Mountains project to earn 25%. We do not expect to incur any drilling costs in fiscal 2009 for this commitment since we do not expect the operator to proceed with the well in fiscal 2009. We expect significant capital expenditures during the next 12 months for drilling programs on our Canadian shale program, overhead and working capital purposes. We are currently seeking joint venture partners and equity financing to fund these expenditures, although we do not have any contracts or commitments for either at this time. 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 current 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.

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By adjusting our operations to the 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 are 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 U.S. 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.

Cash used in investing activities

Cash used in investing activities totaled $22,279,141 for the year ended January 31, 2008, mainly related to oil and gas expenditures.

	2008
Alberta Deep Basin	$	1,153,976
Maritimes Basin – Eastern Canada		14,050,784
Canada		15,204,760
Fayetteville Shale – Arkoma Basin Arkansas		7,231,534
Rocky Mountains (Colorado and Wyoming)		719,352
Barnett Shale – Fort Worth Basin Texas		834,066
United States		8,784,952
Net change in non-cash working capital		(766,127	)
Total oil and gas expenditures	$	23,223,585
Total oil and gas divestitures		(983,902	)
Total office equipment and other assets		39,458
		22,279,141

During the year ended January 31, 2008, we spent:

•$1,153,976 in the Alberta deep basin primarily to finish the 2006 drilling program;

•$14,050,784 on the Martimes Basin shale gas project in the Eastern Canada mainly for Kennetcook #1 and #2 drilling, completions and testing ($10.5 million) plus 2D and 3D seismic acquisition ($3.4 million);

•$7,231,534 on the Fayetteville Shale project in Arkansas mainly for land acquisition ($1.8 million), drilling one well ($3.3 million) and seismic acquisition ($2.1 million);

•$719,352 in the US Rocky Mountains primarily to drill one well in Wyoming; and

•$834,066 on the Barnett shale gas project primarily to finish the 2006 drilling program.

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Also in the year ended January 31, 2008, we sold our 27% interest in 12,100 gross acres in northeast Hill County of Texas for gross proceeds of $983,902.

Cash provided by financing activities

Cash provided by financing activities totaled $25,308,006 for the year ended January 31, 2008.

In November of 2007, we received proceeds of $6,000,000 related to the exercise of all share purchase warrants issued in connection with our June 14, 2005 private placement which resulted in the issuance of 6,000,000 shares of common stock.

On February 26, 2007, we sold an aggregate of 10,412,000 shares of our common stock at $2.00 per share to 24 accredited investors in a private placement transaction for aggregate proceeds of $20,824,000. We paid the placement agents of the offering a cash fee of 6.5% of the proceeds of the offering. The registration statement was declared effective on March 14, 2007.

In the prior fiscal years, we sold $31,000,000 of convertibles debentures and issued 8,500,000 warrants. During the year ended January 31, 2008, $9,899,860 of convertible debentures were converted into 7,806,664 common shares. The face value and carrying value of the convertible debentures is as follows:

	January 31, 2008						January 31, 2007
Agreement Date	Face Value		Discount		Carrying Value		Face Value		Discount		Carrying Value
June 14, 2005	$	-	$	-	$	-	$	2,750,000	$	515,626	$	2,234,374
December 8, 2005		6,100,140		1,321,869		4,778,271		13,250,000		6,095,192		7,154,808
December 28, 2005		10,000,000		3,229,279		6,770,721		10,000,000		6,383,450		3,616,550
Total convertible debentures	$	16,100,140	$	4,551,148	$	11,548,992	$	26,000,000	$	12,994,268	$	13,005,732

The December 8, 2005 convertible debentures have essentially no limit on the number of shares for which the secured convertible debentures may be converted into since they have a floating conversion price. As a result, the warrants issued with the June 14, 2005 and December 28, 2005 convertible debentures and the embedded conversion feature for the December 8, 2005 convertible debenture have been accounted for as liabilities. The estimated fair value of the warrants and the embedded conversion feature is presented as a liability and changes in the estimated fair value are included in earnings. The derivative liability consists of the following:

	2008		2007
June 14 and December 2005 warrants	$	-	$	10,451,400
December 8, 2005 conversion feature		3,262,846		5,541,457
Derivative liability	$	3,262,846	$	15,992,857

The decrease in the derivative liability is mainly due to the exercise of the December 28, 2005 warrants and the conversion of over half of the December 8, 2005 convertible debentures which reduced the conversion features outstanding.

The unrealized gain (loss) on the derivatives is comprised of:

	2008			2007
June 14, 2005 warrants	$	7,046,293		$	13,170,000
December 8, 2005 conversion feature		(1,094,119	)		2,075,722
December 28, 2005 warrants		-			1,715,250
Unrealized gain on fair value of derivatives	$	5,952,174		$	16,960,972

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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 unproved properties, geological expenditures and direct internal costs are capitalized into the full cost pool. We had two countries with proven reserves. For our proven 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 unproved 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 unproved 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 obligation 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.

Derivative Liabilities

We record derivatives at their fair values on the date that they meet the requirements of a derivative instrument and at each subsequent balance sheet date. Fair values are determined using the Black Scholes option pricing model, which requires and is very sensitive to an estimate of the Company’s stock price volatility and term. Any change in fair value will be recorded as non-operating, non-cash income or expense at each reporting date.

Recently Issued Accounting Pronouncements

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 effect the Company's financial statements.

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

30

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. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year that begins on or before November 15, 2007, provided the entity also elects to apply the provision of SFAS No. 157, “Fair Value Measurements”. The adoption of this statement is not expected to have a material effect on our future reported financial position or results of operations.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”. The objective of SFAS No. 157 is to increase consistency and comparability in fair value measurements and to expand disclosures about fair value measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. The provisions of SFAS No. 157 are effective for fair value measurements made in fiscal years beginning after November 15, 2007. The effective date for SFAS No. 157 as it relates to fair value measurement for non-financial assets and liabilities that are not measured at fair value on a recurring basis has been deferred to fiscal years beginning on or after December 31, 2008. The adoption of this statement is not expected to have a material effect on our future reported financial position or results of operations.

In December 2007, the FASB revised 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.

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

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

31

ITEM 8. FINANCIAL STATEMENTS.

TRIANGLE PETROLEUM CORPORATION

INDEX TO FINANCIAL STATEMENTS

	Page
Reports of Independent Registered Public Accounting Firm	F-1 and F-2
Consolidated Balance Sheets as of January 31, 2008 and 2007	F-3
Consolidated Statements of Operations for each of the years in the two year period ended January 31, 2008	F-4
Consolidated Statements of Cash Flows for each of the years in the two year period ended January 31, 2008	F-5
Consolidated Statement of Stockholders' Equity (Deficit) for each of the years in the two year period ended January 31, 2008	F-6
Notes to the Consolidated Financial Statements	F-7 to F-21

32

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Triangle Petroleum Corporation

We have audited the accompanying consolidated balance sheet of Triangle Petroleum Corporation as of January 31, 2008, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the year 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 audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether 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, 2008, and the results of its operations and its cash flows for the year 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 and has a net capital deficiency 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 and financial statement schedules do not include any adjustments that might result from the outcome of this uncertainty.

/s/ KPMG LLP

Chartered Accountants

Calgary, Canada

April 24, 2008

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders

of Triangle Petroleum Corporation (An Exploration Stage Company)

We have audited the accompanying consolidated balance sheets of Triangle Petroleum Corporation (An Exploration Stage Company) as of January 31, 2007 and the related consolidated statements of operations, cash flows and stockholders’ equity for the year 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 audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether 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 Triangle Petroleum Corporation as of January 31, 2007 and the results of its operations and its cash flows for the year then ended in conformity with generally accepted accounting principles used in the United States.

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company is in the exploration stage, has not generated significant revenue and has incurred significant losses since inception. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also discussed in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ MANNING ELLIOTT LLP

CHARTERED ACCOUNTANTS

Vancouver, Canada

April 2, 2007

F-2

Triangle Petroleum Corporation

Consolidated Balance Sheets

(Expressed in U.S. dollars)

	January 31, 2008 $			January 31, 2007 $
ASSETS
Current Assets
Cash and cash equivalents		4,581,589			5,798,982
Prepaid expenses (Note 3)		797,307			2,519,009
Other receivables		1,689,391			344,342
Total Current Assets		7,068,287			8,662,333
Debt Issue Costs, net		465,833			916,353
Property and Equipment (Note 4)		66,121			67,091
Oil and Gas Properties (Note 5)		24,978,949			21,101,495
Total Assets		32,579,190			30,747,272
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current Liabilities
Accounts payable		3,533,833			4,199,961
Accrued interest on convertible debentures		2,751,096			2,095,989
Accrued liabilities (Note 7)		420,384			466,112
Derivative liabilities (Note 10)		3,262,846			15,992,857
Convertible debentures, current portion, less unamortized discount of $1,321,869 and $515,626, respectively (Note 9)		4,778,271			2,234,374
Total Current Liabilities		14,746,430			24,989,293
Asset Retirement Obligations (Note 8)		1,003,353			90,913
Convertible Debentures, less unamortized discount of $3,229,279 and $12,478,642, respectively (Note 9)		6,770,721			10,771,358
Total Liabilities		22,520,504			35,851,564
Going Concern (Note 1)
Commitments (Note 13)
Subsequent Event (Note 15)
Stockholders’ Deficit
Common Stock (Note 11) Authorized: 100,000,000 shares, par value $0.00001 Issued: 46,794,530 shares (2007 – 22,475,866 shares)		468			225
Additional Paid-In Capital (Note 11)		57,852,277			13,088,795
Deficit		(47,794,059	)		(18,193,312	)
Total Stockholders’ Deficit		10,058,686			(5,104,292	)
Total Liabilities and Stockholders’ Deficit		32,579,190			30,747,272

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,
	2008			2007
	$			$
Revenue, net of royalties		586,804			54,342
Operating Expenses
Oil and gas production		304,537			–
Depletion, depreciation and accretion		441,881			36,229
Depreciation – property and equipment		40,429			26,627
General and administrative		5,800,116			8,215,270
Foreign exchange (gain) loss		317,656			(34,578	)
Impairment loss on oil and gas properties		19,598,916			1,281,499
Total Operating Expenses		26,503,535			9,525,047
Loss from Operations		(25,916,731	)		(9,470,705	)
Other Income (Expense)
Accretion of discounts on convertible debentures		(8,525,621	)		(10,149,984	)
Amortization of debt issue costs		(450,521	)		(411,805	)
Interest expense		(1,283,165	)		(1,707,732	)
Interest income		622,497			497,285
Unrealized gain on fair value of derivatives		5,952,794			16,960,972
Total Other Income (Expense)		(3,684,016	)		5,188,736
Net Loss for the Year		(29,600,747	)		(4,281,969	)
Net Loss Per Share – Basic and Diluted		(0.80	)		(0.21	)
Weighted Average Number of Shares Outstanding – Basic and Diluted		37,192,000			20,582,000

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,
	2008			2007
	$			$
Operating Activities
Net loss		(29,600,747	)		(4,281,969	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Accretion of discounts on convertible debentures		8,525,621			10,149,984
Amortization of debt issue costs		450,521			411,805
Depletion, depreciation and accretion		441,881			36,229
Depreciation – property and equipment		40,429			26,627
Impairment loss on oil and gas properties		19,598,916			1,281,499
Stock-based compensation		2,696,143			5,825,356
Unrealized gain on fair value of derivatives		(5,952,794	)		(16,960,972	)
Changes in operating assets and liabilities
Prepaid expenses		(103,837	)		(2,201,259	)
Other receivables		(1,139,216	)		(255,737	)
Accounts payable		88,049			3,672,904
Accrued interest on convertible debentures		655,107			1,707,731
Accrued liabilities		53,669			(262,243	)
Cash Used in Operating Activities		(4,246,258	)		(850,045	)
Investing Activities
Purchase of property and equipment		(39,458	)		(24,453	)
Oil and gas property expenditures		(23,223,585	)		(15,295,942	)
Oil and gas property divestitures		983,902			–
Cash Used in Investing Activities		(22,279,141	)		(15,320,395	)
Financing Activities
Proceeds from issuance of common stock		26,824,000			–
Common stock issuance costs		(1,515,994	)		–
Proceeds from issuance of convertible debentures		–			5,000,000
Debt issue costs		–			(425,000	)
Cash Provided by Financing Activities		25,308,006			4,575,000
Decrease in Cash and Cash Equivalents		(1,217,393	)		(11,595,440	)
Cash and Cash Equivalents – Beginning of Year		5,798,982			17,394,422
Cash and Cash Equivalents – End of Year		4,581,589			5,798,982
Cash		1,334,635			353,981
Cash equivalents		3,246,954			5,445,001
Non-cash Investing and Financing Activities
Common stock issued for conversion of debentures and warrants		16,851,576			4,100,000
Supplemental Disclosures:
Interest paid		628,058			–

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

F-5

Triangle Petroleum Corporation

Statement of Stockholders’ Equity (Deficit)

Period from January 31, 2006 to January 31, 2008

(Expressed in U.S. dollars)

					Additional
	Common Stock				Paid-in			Deferred
	Shares		Amount		Capital			Compensation			Deficit			Total
	#		$		$			$			$			$
Balance – January 31, 2006		19,182,530		192		7,650,141			(4,486,667	)		(13,911,343	)		(10,747,677	)
Issuance of common stock on conversion of convertible debenture at a weighted average price of $1.245 per share		3,293,336		33		4,099,967			–			–			4,100,000
Amortization of deferred compensation		–		–		–			3,430,000			–			3,430,000
Elimination of deferred compensation pursuant to FAS 123R		–		–		(1,056,667	)		1,056,667			–			–
Stock based compensation		–		–		2,395,354			–			–			2,395,354
Net loss for the year		–		–		–			–			(4,281,969	)		(4,281,969	)
Balance – January 31, 2007		22,475,866		225		13,088,795			–			(18,193,312	)		(5,104,292	)
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
Issuance of common stock for cash pursuant to private placement at $2.00 per share in February 2007		10,412,000		104		20,823,896			–			–			20,824,000
Share issuance costs		–		–		(1,515,994	)		–			–			(1,515,994	)
Issuance of common stock for cash 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		–		–		3,405,107			–			–			3,405,107
Issuance of common stock for investor relation services		100,000		1		173,499			–			–			173,500
Change in fair value of conversion feature on modification		–		–		82,500			–			–			82,500
Stock based compensation		–		–		2,522,642			–			–			2,522,642
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

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)

The Company was incorporated in the State of Nevada on December 11, 2003 under the name Peloton Resources Inc. On May 10, 2005, the Company changed its name to Triangle Petroleum Corporation. During the fiscal year ended January 31, 2006, the Company changed its principal business to that of acquisition, exploration and development of oil and gas resource properties. In the prior year, the Company was accounted for as an exploration stage. Starting in the fourth quarter of fiscal 2008, the Company was no longer accounted for as an exploration stage entity.

1. Going Concern

The Company is primarily engaged in the acquisition, exploration and development of oil and gas resource properties. The Company has working capital of $362,974 as at January 31, 2008, excluding derivative liabilities and the current portion of convertible debentures.

The Company will have to raise additional funds through equity or debt offerings, dispositions of assets or other means to finance the repayment of the convertible debentures (if the holders do not elect to convert), to finance commitments to continue to earn lands related to farm-out agreements, 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 US 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 useful life and recoverability of long-lived assets, proved and unproven oil and gas expenditures, asset retirement obligations, stock-based compensation, the estimated fair value of derivatives and deferred income tax asset valuation allowances. The Company bases its estimates and assumptions on current facts, historical experience and various other factors that it believes to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities and the accrual of costs and expenses that are not readily apparent from other sources. The actual results experienced by the Company may differ materially and adversely from the Company’s estimates. To the extent there are material differences between the estimates and the actual results, future results of operations will be affected.

c) Foreign Currency Translation

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

F-7

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

2. Summary of Significant Accounting Policies (continued)

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) Long-lived Assets

The Company tests long-lived assets or asset groups for recoverability when events or changes in circumstances indicate that their carrying amount may not be recoverable. Circumstances which could trigger a review include, but are not limited to: significant decreases in the market price of the asset; significant adverse changes in the business climate or legal factors; accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the asset; current period cash flow or operating losses combined with a history of losses or a forecast of continuing losses associated with the use of the asset; and current expectation that the asset will more likely than not be sold or significantly disposed of before the end of its estimated useful life.

Recoverability is assessed based on the carrying amount of the asset and its fair value which is generally determined based on the sum of the undiscounted cash flows expected to result from the use and the eventual disposal of the asset, as well as specific appraisal in certain instances. An impairment loss is recognized when the carrying amount is not recoverable and exceeds fair value.

g) 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 proven 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 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 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)

h) 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 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 the Company settles the obligation.

i) 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.

j) 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 collectibility is reasonably assured.

k) 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 derecognition, 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 is to be 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.

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 resassessment 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 2008. 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, 2004. 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, 2008, 2007 and 2006, there were no charges for interest or penalties.

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

Basic EPS is computed by dividing net income (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.

m) Financial Instruments

The fair values of financial instruments, which include cash and cash equivalents, other receivables, accounts payable, accrued liabilities and accrued interest on convertible debentures approximate their carrying values due to the relatively short time to maturity of these instruments. The fair values of convertible debentures are estimated to approximate their carrying values adjusted for unamortized discounts.

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)

n) Concentration of Risk

The Company does not believe that it is exposed to interest rate risk as its convertible debentures have fixed interest rates. The Company maintains its cash accounts 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 U.S. 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, 2008, the Company has not engaged in any transactions that would be considered derivative instruments or hedging activities, except for derivatives embedded in the convertible debentures (note 9). To date, the Company has not incurred a loss relating to this concentration of credit risk.

o) 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 will be recorded as non-operating, non-cash income or expense at each reporting date.

p) Comprehensive Loss

As at January 31, 2008 and 2007, and for each of the years in the three year period ended January 31, 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.

q) 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.

r) Recent Accounting Pronouncements

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 effect the Company's financial statements.

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.

In February 2007, the Financial Accounting Standards Board (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. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year that begins on or before November 15, 2007, provided the entity also elects to apply the provision of SFAS No. 157, “Fair Value Measurements”. The adoption of this statement is not expected to have a material effect on the Company's financial statements.

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)

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”. The objective of SFAS No. 157 is to increase consistency and comparability in fair value measurements and to expand disclosures about fair value measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. The provisions of SFAS No. 157 are effective for fair value measurements made in fiscal years beginning after November 15, 2007. The effective date for SFAS No. 157 as it relates to fair value measurement for non-financial assets and liabilities that are not measured at fair value on a recurring basis has been deferred to fiscal years beginning on or after December 31, 2008. The adoption of this statement is not expected to have a material effect on the Company's financial statements.

In December 2007, the FASB revised 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 is not expected to have a material effect on the Company's financial statements.

s) Reclassifications

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

3. Prepaid Expenses

The components of prepaid expenses are as follows:

	January 31, 2008 $		January 31, 2007 $
Office space deposit and rent		46,571		8,342
Prepaid insurance		131,763		97,654
Prepaid joint-venture exploration costs		542,384		2,367,923
Professional and consulting services		33,833		22,917
Royalty deposit		20,157		–
Software subscriptions		22,599		22,173
Total prepaid expenses		797,307		2,519,009

4. Property and Equipment

	Cost $		Accumulated Depreciation $		January 31, 2008 Net Carrying Value $
Computer hardware		71,712		39,250		32,462
Furniture and equipment		48,464		17,826		30,638
Geophysical software		9,691		6,670		3,021
Leasehold Improvements		7,927		7,927		–
		137,794		71,673		66,121

	Cost $		Accumulated Depreciation $		January 31, 2007 Net Carrying Value $
Computer hardware		49,421		17,515		31,906
Furniture and equipment		33,861		8,697		25,164
Geophysical software		8,971		3,885		5,086
Leasehold Improvements		6,083		1,148		4,935
		98,336		31,245		67,091

F-11

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

5. Oil and Gas Properties

The following table summarizes information regarding the Company's oil and gas acquisition, exploration and development activities:

	January 31,			January 31,
	2008 $			2007 $
Proved Properties
Exploration costs		12,886,510			1,764,853
Less:
Accumulated depletion		(407,204	)		(36,229	)
Impairment costs		(12,065,397	)		(1,098,645	)
		413,909			629,979
Unproven Properties
Acquisition costs		11,150,649			15,606,365
Exploration costs		23,247,119			6,065,718
Less:
Impairment costs		(9,832,728	)		(1,200,567	)
		24,565,040			20,471,516
Net Carrying Value		24,978,949			21,101,495

All of the Company’s oil and gas properties are located in the United States and Canada. The Company is currently participating in oil and gas exploration activities in Arkansas, Montana and Texas, USA, and Nova Scotia and New Brunswick, Canada.

Depletion expense – Proved Properties

Depletion expense for the year ended January 31, 2008 of $243,156 (2007 - $36,229) was recorded in the U.S. cost center and $127,819 (2007 - $nil) was recorded in the Canadian cost center. All of the Company’s unproven properties are not subject to depletion.

o In Canada, $15,463,119 of unproven property costs were excluded from costs subject to depletion which relate to Eastern Canada shale gas exploration costs mainly in the Windsor Basin of Nova Scotia. The Company anticipates that these costs will be subject to depletion in fiscal 2010, when the company anticipates having pipelines built and commissioned to market potential gas from the Windsor Basin.

o In the U.S., $8,209,891 of unproven property costs were excluded from costs subject to depletion which relate to Fayetteville Shale gas acquisition costs. Subsequent to year-end, the Company announced that it anticipates selling its acreage position related to these costs in fiscal 2009.

o In the U.S., $812,020 of unproven property costs were excluded from costs subject to depletion which relate to U.S. Rocky Mountain leasehold acquisition costs. The Company anticipates that these costs will be subject to depletion in fiscal 2010, when the exploration well is planned to be drilled in this area.

Impairment costs – Proved Properties

(a) During 2008, the Company’s proved properties in Alberta exceeded their estimated realizable value which resulted in a $6,939,003 (2007 – $1,098,645) non-cash impairment loss being recognized.

(b) During 2008, the Company’s proved properties in Texas exceeded the their estimated realizable value which resulted in a $3,082,346 non-cash impairment loss being recognized.

(c) On July 18, 2007, the Company sold its 27% interest in 12,100 gross acres in northeast Hill County of Texas for gross proceeds of $983,902. The Company had incurred proven land and geological and geophysical costs of $1,929,305 related to this prospect which resulted in a $945,403 non-cash impairment being recognized.

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

	January 31, 2008 $		January 31, 2007 $
Alberta – Canada		324,162		–
Barnett Shale (Texas) – United States		89,747		629,979
Total proved acquisition and exploration costs		413,909		629,979

Impairment costs – Unproven Properties

(a) During 2008, the Company’s unproven property costs in the US Rocky Mountains (Colorado and Wyoming) were considered impaired resulting in a $2,104,663 (2007 - $182,854) non-cash impairment loss.

(b) During 2008, 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-12

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

5. Oil and Gas Properties (Continued)

The Company's unproven acquisition and exploration costs were distributed in the following geographic areas:

	January 31, 2008 $		January 31, 2007 $
Alberta		–		6,154,643
East Coast (Nova Scotia and New Brunswick)		15,463,119		654,159
Canada		15,463,119		6,808,802
Fayetteville Shale(Arkansas)		8,289,901		7,569,101
Rocky Mountains (Colorado, Montana, Wyoming)		812,020		2,187,391
Barnett Shale (Texas)		–		3,906,222
United States		9,101,921		13,662,714
Total unproven acquisition and exploration costs		24,565,040		20,471,516

6. Natural gas and oil reserves (unaudited)

The following table summarizes the changes in the Company’s proved natural gas and oil reserves for the year ended January 31, 2008. The Company had two producing wells at the beginning of fiscal 2008 that were not assigned proved reserves.

	Gas (MMcf)						Oil and 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
Proved developed reserves:
Beginning of year		-		-		-		-		-		-		-		-		-
End of year		103		7		111		1,846		-		1,846		-		-		122

MMcf – Millions of cubic feet Bbls – Barrels

MMcfe – Millions of cubic feet equivalent (1 Bbls = 6 Mcfe = 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. The gas and oil reserve quantities owned by the Company were audited by the independent petroleum engineering firm of Ryder Scott, Inc.

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

	Canada		US		Total
Future cash inflows	$	908,391	$	55,070	$	963,461
Future production costs		503,919		37,976		541,895
Future net cash flows		404,472		17,094		421,566
10% annual discount for estimated timing of cash flows		74,493		383		74,876
Standardized measure of discounted future net cash flows	$	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 C$7.38 per Mcf for Canadian gas, $8.10 per Mcf for U.S. gas and $94.22 per barrel for liquids in 2008.  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-13

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

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

	Year Ended January 31, 2008
	Canada			US			Total
Revenue, net of royalties	$	284,931		$	301,873		$	586,804
Production costs		(90,613	)		(213,924	)		(304,537	)
Depletion, depreciation and accretion		(179,142	)		(262,739	)		(441,881	)
Impairment loss on oil and gas properties		(6,939,003	)		(12,659,913	)		(19,598,916	)
Results of oil and gas activities	$	(6,923,827	)	$	(12,834,703	)	$	(19,758,530	)

7. Accrued Liabilities

The components of accrued liabilities are as follows:

	January 31, 2008 $		January 31, 2007 $
Oil and gas capital expenditures		366,714		466,112
Oil and gas operating expenditures		53,670		–
Total accrued liabilities		420,384		466,112

8. Asset Retirement Obligations

	January 31, 2008 $		January 31, 2007 $
Balance, beginning of year		90,913		33,000
Revision of prior year estimate		70,078		–
Liabilities incurred		793,624		56,446
Accretion		48,738		1,467
Total asset retirement obligations		1,003,353		90,913

We are required to recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties including without limitation the costs of reclamation of our drilling sites, storage and transmission facilities and access roads. We base our estimate of the liability on the industry experience of our management and on our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates and determine the credit-adjusted risk-free rate to use. The asset retirement obligation was 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 $1,435,000.

9. Convertible Debentures

Agreement Date	June 14, 2005 (a) $			December 8, 2005 (b) $			December 28, 2005 (c) $			Total $
Balance, January 31, 2006		1,593,750			2,813,470			283,105			4,690,325
Issued		-			5,000,000			-			5,000,000
Discount		-			(2,734,579	)		-			(2,734,579	)
Converted		(2,350,000	)		(1,750,000	)		-			(4,100,000	)
Accretion		2,990,625			3,825,915			3,333,446			10,149,986
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	)		(7,149,860	)		-			(9,899,860	)
Accretion		515,625			4,773,325			3,236,670			8,525,620
Balance, January 31, 2008		-			4,778,271			6,770,721			11,548,992
Amount classified as current		-			4,778,271			-			4,778,271
Face value at January 31, 2008		-			6,100,140			10,000,000			16,100,140
Interest rate		8	%		5	%		7.5	%

F-14

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

9. Convertible Debentures (continued)

(a) On June 14, 2005, the Company entered into a securities purchase agreement with a single accredited investor pursuant to which the investor purchased an 8% convertible debenture with a principal amount of $1,000,000, and warrants to purchase 1,000,000 shares of the Company’s common stock, exercisable at a price of $1.00 per share until June 15, 2008. On July 14, 2005, the investor purchased an additional $5,000,000 of convertible debentures, and warrants to purchase 5,000,000 shares of common stock, exercisable at a price of $1.00 per share until June 15, 2008.

The convertible debentures matured on June 10, 2007. The Company was not required to make any interest or principle payments until the maturity date. The principal and accrued interest on these convertible debentures may be converted into shares of the Company’s common stock at a rate of $1.00 per share, at the option of the holder. The investor had contractually agreed to restrict the ability to convert the convertible debentures to an amount which would not exceed the difference between the number of shares of common stock beneficially owned by the holder or issuable upon exercise of the warrant held by such holder and 4.99% of the outstanding shares of common stock of the Company.

The Company recognized the value of the conversion feature of $3,141,817 as additional paid-in capital and an equivalent discount which was expensed over the term of the convertible debentures. The Company allocated the proceeds of issuance between the convertible debt and the detachable warrants based on their relative fair values. Accordingly, the Company recognized the fair value of the detachable warrants of $2,858,183 as additional paid-in capital and an equivalent discount against the convertible debentures.

During the year ended January 31, 2006, a principal amount of $900,000 was converted into 900,000 shares of common stock. The unamortized discount on the converted debenture of $731,250 was charged to accretion expense. During the year ended January 31, 2007, a principal amount of $2,350,000 was converted into 2,350,000 shares of common stock. The unamortized discount on the converted debentures of $1,171,875 was charged to accretion expense. During the year ended January 31, 2008, a principal amount of $2,750,000 was converted into 2,750,000 shares of common stock. The unamortized discount on the converted debenture of $284,375 was charged to accretion expense. As at January 31, 2008, all of the $6,000,000 convertible debentures have been converted into common stock of the Company. On June 21, 2007, accrued interest of $628,058 was paid in cash.

On December 8, 2005, upon the issuance of the convertible debentures referred to in Note 9(b), the detachable warrants no longer met the requirements for equity classification. As such, the Company recorded the fair value of the warrants of $31,384,800 as a derivative liability. The $28,526,617 change in the fair value of the warrants from the date of issuance of $2,858,183 to December 8, 2005 of $31,384,800 was accounted for as an adjustment to stockholders’ equity. During the year ended January 31, 2008, the Company recorded a gain on the change in fair value of the derivative liability of $7,826,400 (2007 - $13,170,000) and as at January 31, 2008, the fair value of the derivative liability was $nil (January 31, 2007 - $10,451,400). As at January 31, 2008, all of these 6,000,000 warrants have been exercised and converted into common stock of the Company. In November of 2007, cash proceeds of $6,000,000 were received related to the exercise of these 6,000,000 warrants.

(b) On December 8, 2005, the Company entered into a securities purchase agreement with a single investor pursuant to which the investor purchased 5% secured convertible debentures in the aggregate principal amount of $15,000,000. The gross proceeds of this financing was received as follows:

(i) $5,000,000 was received on December 8, 2008, being the closing date;

(ii) $5,000,000 was received on January 17, 2006, being the second business day prior to the filing date of the registration statement; and

(iii) $5,000,000 was received on June 1, 2006, being the fifth business day following the effective date of the registration statement.

The Company agreed to pay an 8% fee on the receipt of each installment, and a $15,000 structuring fee. The convertible debentures mature on the third anniversary of the date of issue. The Company is not required to make any payments until the maturity date. The investor may convert, at any time, any amount outstanding under the convertible debentures into shares of common stock of the Company at a conversion price per share equal to the lesser of $5.00 or 90% of the average of the three lowest daily volume weighted average prices of the common stock ten trading days immediately preceding the date of conversion.

The Company, at its option has the right, with three business days advance written notice, to redeem a portion or all amounts outstanding under these convertible debentures prior to the Maturity Date provided that the closing bid price of the common stock is less than $5.00 at the time of the redemption. In the event of redemption, the Company is obligated to pay an amount equal to the principal amount being redeemed plus a 20% redemption premium, and accrued interest.

The Company also entered into a registration rights agreement providing for the filing of a registration statement with the U.S. Securities and Exchange Commission (“SEC”) registering the common stock issuable upon conversion of the convertible debentures. The Company is obligated to ensure that the registration statement declared effective on May 26, 2006 remains in effect until all of the shares of common stock issuable upon conversion of the convertible debentures have been sold. In the event of a default of its obligations under the registration rights agreement, the Company is required pay to the investor, as liquidated damages, for each month that the registration statement is not declared effective, either a cash amount or shares of common stock equal to 2% of the liquidated value of the convertible debentures. The registration statement continues to be effective.

F-15

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

9. Convertible Debentures (continued)

The investor has agreed to restrict its ability to convert the convertible debentures and receive shares of the Company’s common stock such that the number of shares of common stock held by the investor in the aggregate and its affiliates after such conversion or exercise does not exceed 4.9% of the then issued and outstanding shares of the Company’s common stock. The investor can waive the provision to not exceed 4.9% of the issued and outstanding shares upon not less than 65 days prior notice to the Company. In addition, the investor is restricted from converting more than $1,500,000 in principle amount of the debenture in any thirty day period, with no more than $1,000,000 of such amount at the variable market conversion price.

In connection with the securities purchase agreement, the Company and each of its subsidiaries executed security agreementsin favor of the investor granting them a first priority security interest in all of the Company’s goods, inventory, contractual rights and general intangibles, receivables, documents, instruments, chattel paper, and intellectual property. The security agreements state that if an event of default occurs under the convertible debentures or security agreements, the investor has the right to take possession of the collateral, to operate the Company’s business using the collateral, and have the right to assign, sell, lease or otherwise dispose of and deliver all or any part of the collateral, at public or private sale or otherwise to satisfy the Company’s obligations under these agreements.

The Company was required to classify the conversion feature contained within the debenture as derivative liability. As such, the Company recorded a derivative liability related to the convertible debentures equal to the estimated fair value of the conversion feature of $10,151,918 with an equivalent discount on the debentures. During the year ended January 31, 2007, a principal amount of $1,750,000 was converted into 943,336 shares of common stock. The unamortized discount on the converted debentures of $847,164 was charged to accretion expense. During the year ended January 31, 2008, a principal amount of $7,149,860 was converted into 5,056,664 shares of common stock. The unamortized discount on the converted debentures of $2,439,401 was charged to accretion expense. The carrying value of the convertible debentures at January 31, 2008 of $4,778,721 will be accreted to the face value of $6,100,140 to maturity. To January 31, 2008, accrued interest of $1,207,946 (January 31, 2007 – $693,699) has been included in accrued liabilities and $8,830,049 (2007 - $4,056,724) has been accreted increasing the carrying value of the convertible debentures to $4,778,721 (January 31, 2007 - $7,154,808) (net of conversions of $8,899,860). During the year ended January 31, 2008, the Company recorded a loss on the change in fair value of the conversion option derivative liability of $1,094,119 (January 31, 2007 – gain of $2,075,722) and as at January 31, 2008, the fair value of the conversion option derivative liability was $3,262,846 (January 31, 2007 - $5,541,457).

(c) On December 28, 2005, the Company entered into a securities purchase agreement with two accredited investors providing for the sale by the Company to the investors of 7.5% convertible debentures in the aggregate principal amount of $10,000,000, of which $5,000,000 was advanced immediately, and 1,250,000 warrants to purchase 1,250,000 shares of the Company’s common stock, exercisable at a price of $5.00 per share until December 28,2006, of which 625,000 were issued. The second instalment of $5,000,000 and 625,000 warrants was advanced on January 18, 2006, upon the filing of a registration statement by the Company with the SEC. The warrants expired in full without exercise during the fiscal year ended January 31, 2007.

On January 29, 2008, the convertible debentures maturity date was extended from the third anniversary date from issuance (December 28, 2008 and January 23, 2009) to June 1, 2009. The Company is not required to make any payments until the maturity date. The investors may convert, at any time, any amount outstanding under the convertible debentures into shares of common stock of the Company at a conversion price per share of $4.00.

In connection with the securities purchase agreement, the Company also entered into a registration rights agreement providing for the filing of a registration statement with the SEC registering the common stock issuable upon conversion of the convertible debentures and warrants. The Company was obligated to use its best efforts to cause the registration statement to be declared effective no later than May 28, 2006 and to insure that the registration statement remains in effect until all of the shares of common stock issuable upon conversion of the convertible debentures have been sold. In the event of a default of its obligations under the registration rights agreement, including its agreement to file the registration statement with the SEC no later than February 26, 2006, or if the registration statement was not declared effective by June 30, 2006, the Company is required pay to the investors, as liquidated damages, for each month that the registration statement has not been filed or declared effective, as the case may be, a cash amount equal to 1% of the liquidated value of the convertible debentures. The Company filed a registration statement on January 18, 2006 that was declared effective May 25, 2006. The registration statement continues to be effective.

Each investor has agreed to restrict its ability to convert the convertible debentures or exercise the warrants and receive shares of the Company’s common stock such that the number of shares of common stock held by them in the aggregate and their affiliates after such conversion or exercise does not exceed 4.99% of the then issued and outstanding shares of the Company’s common stock.. The Company recognized the fair value of the warrants of $3,261,250 as a derivative liability and an equivalent discount on the debentures as a result of the terms of the December 5, 2005 debentures. The Company recorded the embedded beneficial conversion feature of $6,738,750 as additional paid-in capital with an equivalent discount on the debentures. The carrying value of the convertible debentures at January 31, 2008 of $6,770,721 (January 31, 2007 - $3,616,551) will be accreted to the face value of $10,000,000 to maturity. To January 31, 2008, accrued interest of $1,543,151 (January 31, 2007 – $793,150) has been included in accrued liabilities.

F-16

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

10. Derivative Liabilities

	Warrants									Conversion
				Weighted average exercise price			Fair Value			Feature Fair Value			Total Fair Value
	#			$			$			$			$
January 31, 2006		7,250,000			1.69			25,336,650			4,882,600			30,219,250
Conversion features issued June 1, 2006								-			2,734,579			2,734,579
Warrants expired		(1,250,000	)		(5.00	)		-			-			-
Change in fair value		-			-			(14,885,250	)		(2,075,722	)		(16,960,972	)
January 31, 2007		6,000,000			1.00			10,451,400			5,541,457			15,992,857
Conversion features settled		-			-			-			(3,372,110	)		(3,372,110	)
Warrants exercised		(6,000,000	)		(1.00	)		(3,405,107	)		-			(3,405,107	)
Change in fair value		-			-			(7,046,293	)		1,093,499			(5,952,794	)
January 31, 2008		-			-			-			3,262,846			3,262,846

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

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 in the December 8, 2008 convertible debenture.

	Volatility			Risk Free Rate			Dividend Yield		Term in Years
Weighted Average Assumptions at:
January 31, 2008		72.8	%		2.11	%		–		0.87
January 31, 2007		74.3	%		4.94	%		–		2.01

The following table shows the assumptions used in the calculation of the fair value for the warrants.

	Volatility			Risk Free Rate			Dividend Yield		Term in Years
Weighted Average Assumptions at:
January 31, 2007		74.3	%		5.09	%		–		1.37

F-17

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

11. Common Stock

	Shares		Common Stock		Additional Paid- In Capital
			$		$
January 31, 2006		19,182,530		192		3,163,474
Conversion of debentures		3,293,336		33		4,099,967
Stock based compensation (a and b)		-		-		5,827,354
January 31, 2007		22,475,866		225		13,088,795
Conversion of debentures (d)
-Face value		7,806,664		78		9,899,782
-Fair value of embedded conversion		-		-		3,372,109
Private placement (e)		10,412,000		104		20,823,896
Issuance costs (e)		-		-		(1,515,994	)
Exercise of warrants (f)		6,000,000		60		9,405,047
Investor relations services (g)		100,000		1		173,499
Change in fair value of conversion feature on modification (Note 9c)						82,500
Stock-based compensation (a, b and Note 12)		-		-		2,522,643
January 31, 2008		46,794,530		468		57,852,277

(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. As the shares were issued for below fair value, a discount on the issuance of shares of $4,160,000 was recorded as deferred compensation. During the year ended January 31, 2006, $1,473,333 was charged to operations. During the year ended January 31, 2007, $2,080,000 was charged to operations. During the year ended January 31, 2008, $606,667 was charged to operations.

(b)   On June 2, 2005, the Company issued 2,000,000 shares of common stock to the 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 $2,700,000 was recorded as deferred compensation. During the year ended January 31, 2006, $900,000 was charged to operations. During the year ended January 31, 2007, $1,350,000 was charged to operations. During the year ended January 31, 2008, $450,000 was charged to operations.

(c)   On June 2, 2005, the Company issued 2,000,000 shares of common stock at $0.01 per share for cash proceeds of $20,000. As the shares were issued for below fair value, a discount on the issuance of shares of $2,700,000 was recorded as deferred compensation. On July 20, 2005, the shares were returned for $20,000 and the deferred compensation amount of $2,700,000 was reversed.

F-18

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

11. Common Stock (Continued)

(d) 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 date of issuance is shown on the table below

Date	Shares		Common Stock		Additional Paid- In Capital		Total
	#		$		$		$
February 20, 2007		108,923		1		249,999		250,000
March 6, 2007		900,000		9		899,991		900,000
March 7, 2007		106,696		1		249,999		250,000
April 11, 2007		129,333		1		249,999		250,000
April 30, 2007		128,939		1		249,999		250,000
May 4, 2007		748,000		7		747,993		748,000
May 11, 2007		130,494		1		249,999		250,000
May 21, 2007		265,041		3		499,997		500,000
June 15, 2007		279,002		3		499,997		500,000
June 21, 2007		1,102,000		11		1,101,989		1,102,000
June 25, 2007		138,742		1		249,999		250,000
June 28, 2007		138,566		1		249,999		250,000
September 25, 2007		591,203		6		749,994		750,000
November 13, 2007		484,872		5		499,995		500,000
November 15, 2007		419,076		4		499,996		500,000
November 21, 2007		805,996		8		999,992		1,000,000
November 26, 2007		402,998		4		499,996		500,000
November 27, 2007		926,783		9		1,149,851		1,149,860
Total		7,806,664		78		9,899,782		9,899,860

(e)   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. Pursuant to the terms of sale, the Company agreed to cause a resale registration statement covering the common stock to be filed no later than 30 days after the closing and declared effective no later than 120 days after the closing. If the Company failed to comply with the registration statement filing or effective date requirements, it would have been required to pay the investors a fee equal to 1% of the aggregate amount invested by the purchasers per each 30 day period of delay, not to exceed 10%. On March 14, 2007, the registration statement was declared effective. 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.

(f)   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.

(g)   During the year ended January 31, 2008, the Company issued 100,000 (2007 – $nil) shares of common stock at a fair value of $173,500 (2007 – $nil) for investor relation services rendered.

12. 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. Pursuant to the 2005 Plan, stock options vest 20% upon granting and 20% every six months. As at January 31, 2008, the Company had 420,000 stock options available for granting pursuant to the 2005 Plan. The 2005 Plan allows 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. The total number of options granted to any person shall not exceed 5% of the issued and outstanding common stock of the Company.

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 2007 Plan, stock options vest 20% upon granting and 20% every six months. As at January 31, 2008, the Company had 1,000,000 stock options available for granting pursuant to the 2007 Plan. The 2007 Plan allows 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. The total number of options granted to any person shall not exceed 5% of the issued and outstanding common stock of the Company.

F-19

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

12. Stock Options (Continued)

The weighted average grant date fair value of stock options granted during the year ended January 31, 2008 and 2007 was $1.06 and $2.96 per share, respectively. No stock options were exercised during the years ended January 31, 2008 and 2007. During the year ended January 31, 2008 and 2007, the Company recorded stock-based compensation of $2,696,143 and $5,825,356, respectively, as general and administrative expense.

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

	Number of Options			Weighted Average Exercise Price $		Aggregate Intrinsic Value $
Outstanding, January 31, 2006		1,330,000			3.28
Granted		700,000			2.96
Forfeited		(400,000	)		2.71
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			2.61		–
Exercisable, January 31, 2008		1,330,000			3.12		–

The weighted average remaining contractual life of stock options outstanding as of January 31, 2008 and 2007 was 3.13 years and 3.89 years, respectively. As at January 31, 2008, there are 200,000 stock options outstanding with an weighted average exercise price of $4.55 and a weighted average remaining contractual life of 2.51 years, 830,000 stock options outstanding with an weighted average exercise price of $3.26 and a weighted average remaining contractual life of 2.72 years, and 1,550,000 stock options outstanding with an weighted average exercise price of $2.01 and a weighted average remaining contractual life of 4.53 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, 2008			Year Ended January 31, 2007
Expected dividend yield		0	%		0	%
Expected volatility		71	%		173	%
Expected life (in years)		3.5			2.7
Risk-free interest rate		4.23	%		4.72	%

As at January 31, 2008, there was $1,165,635 of total unrecognized compensation costs related to nonvested share-based compensation arrangements granted under the 2005 Plan and 2007 Plan which are expected to be recognized over a weighted-average period of 18 months. The total fair value of shares vested during the years ended January 31, 2008 and 2007 was $1,465,986 and $2,395,354, respectively.

A summary of the status of the Company’s nonvested shares as of January 31, 2008, and changes during the year ended January 31, 2008, is presented below:

Nonvested shares	Number of Shares			Weighted-Average Grant-Date Fair Value $
Nonvested at January 31, 2007		782,000			2.80
Granted		1,550,000			0.78
Forfeited		(180,000	)		1.96
Vested		(902,000	)		2.08
Nonvested at January 31, 2008		1,250,000			0.93

F-20

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

13. Commitments

The Company is contractually obligated to spend capital to earn lands that are subject to farm-out agreements. First, the Company is currently committed to pay 66% of the drilling and completion costs for one well in its Fayetteville project to earn a 50% working interest which the operator must spud before July 31, 2008 or the Company automatically earn its 50% interest. Management does not expect to incur any drilling costs in fiscal 2009 to fulfill this commitment. Second, the Company is committed to pay 33% of the costs to drill one well in its Rocky Mountains project to earn a 25% interest. Management does not expect to incur any drilling costs in fiscal 2009 for this commitment as the operator is not expected to proceed with the well in fiscal 2009.

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 payable at $208,469 (Cdn$207,680) for the first three years and $218,912 (Cdn$218,084) for the remaining three years. The Company must also pay its share of building operating costs and taxes. During the year ended January 31, 2008, the Company paid rent expense of $202,826 (2006 - $49,173). Future minimum lease payments over the next five fiscal years are as follows:

2009	$	208,000
2010		208,000
2011		216,000
2012		219,000
2013		55,000
	$	935,000

14. 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 37.22% (2007 – 35%) to income tax expense as reported is as follows:

	2008 $			2007 $
Expected income tax benefit		11,038,396			1,498,689
Non-deductible stock-based compensation		(557,071	)		(1,338,875	)
Non-deductible interest and accretion for convertible debentures		(3,727,339	)		(4,150,200	)
Non-taxable gain on change in fair value of derivatives		2,262,062			5,936,340
Change in enacted tax rate		213,367			–
Other and changes in valuation allowance		(9,229,415	)		(1,945,954	)
Provision for income taxes		–			–

The significant components of the Company’s deferred tax assets and liabilities as at January 31, 2008 and 2007 are as follows:

	2008 $			2007 $
Deferred income tax assets
Resource properties		7,308,000			804,724
Net losses carried forward (expire from 2023 to 2028)		5,319,455			2,444,006
Gross deferred income tax assets		12,627,455			3,248,730
Valuation allowance		(12,627,455	)		(3,248,730	)
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 current income.

15. Subsequent Event

Subsequent to January 31, 2008, the Company issued 1,859,228 shares of common stock for the conversion of convertible debentures with an aggregate principal amount of $1,475,140.

F-21

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

On March 11, 2008, Triangle Petroleum Corporation (the “Company”) dismissed Manning Elliott LLP (“Manning Elliott”) as its independent registered public accounting firm. The decision to change accountants was made by the Audit Committee of the Company’s Board of Directors (the “Audit Committee”) and was made to consolidate the Company’s accounting and outside accounting functions in Calgary, Alberta.

On March 11, 2008, the Company engaged KPMG LLP (“KPMG”) as its independent registered public accounting firm. The decision to engage KPMG was made by the Audit Committee.

During the two fiscal years ended January 31, 2006 and 2007, and through March 11, 2008, (i) there were no disagreements between the Company and Manning Elliott on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure which, if not resolved to the satisfaction of Manning Elliott would have caused Manning Elliott to make reference to the matter in its reports on the Company’s financial statements, and (ii) except for (a) Manning Elliott’s report on the Company's January 31, 2007 financial statements dated April 2, 2007 (except for Note 19, as to which the date is February 29, 2008), which included an explanatory paragraph wherein Manning Elliott expressed substantial doubt about the Company's ability to continue as a going concern and (b) Manning Elliott’s report on the Company's January 31, 2006 financial statements dated April 10, 2006 (except for Note 16, as to which the date is February 29, 2008), which included an explanatory paragraph wherein Manning Elliott expressed substantial doubt about the Company's ability to continue as a going concern, Manning Elliott’s reports on the Company’s financial statements did not contain an adverse opinion or disclaimer of opinion, nor were they modified as to audit scope or accounting principles. During the two fiscal years ended January 31, 2006 and 2007 and through March 11, 2008, there were no reportable events as that term is described in Item 304(a)(1)(iv) of Regulation S-K.

During the two fiscal years ended January 31, 2006 and 2007 and through March 11, 2008, the Company has not consulted with KPMG regarding either:

1.

The application of accounting principles to any specific transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Company’s financial statements, and neither a written report was provided to the Company nor oral advice was provided that KPMG concluded was an important factor considered by the Company in reaching a decision as to the accounting, auditing or financial reporting issue; or

2.

Any matter that was either subject of disagreement or event, as defined in Item 304(a)(1)(iv) of Regulation S-K and the related instruction to Item 304 of Regulation S-K, or a reportable event, as that term is described in Item 304(a)(1)(iv) of Regulation S-K.

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 Corporation 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, 2008 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.

33

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for 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-IntegratedFramework. 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:

a) 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.

b) 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, 2008, management has concluded that we did not maintain effective internal control over financial reporting as of January 31, 2008, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (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.

34

PART III.

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Names:	Ages	Titles:	Board of Directors
Mark G. Gustafson	48	President, Chief Executive Officer, Secretary; Chief Executive Officer – Elmworth Energy Corporation;	Director
Ron W. Hietala	54	President – Elmworth Energy Corporation; President – Triangle USA Petroleum Corporation	Director
Shaun Toker	29	Chief Financial Officer; Chief Financial Officer – Elmworth Energy Corporation; Chief Financial Officer – Triangle USA Petroleum Corporation
J. Howard Anderson	50	Chief Operating Officer and Vice-President Engineering, Elmworth Energy Corporation, Chief Operating Officer and Vice-President Engineering – Triangle USA Petroleum Corporation
Stephen A. Holditch (1)	61		Director
David L. Bradshaw (1)	53		Director
Randal Matkaluk (1)	49		Director

____________________

(1) Independent Director, Member of Audit Committee, Member of Compensation Committee, Member of Nominating - Corporate Governance 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 since May 16, 2005, a Director since May 2005 and Secretary since August 2007. 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.

Ron W. Hietala has been a director of our Company since June 2005. On June 28, 2005, Mr. Hietala was appointed President and Director of Elmworth Energy Corporation, our wholly owned Alberta-based subsidiary and on October 27, 2005 he was appointed President and Director of Triangle USA Petroleum Corporation, our wholly owned Colorado-based subsidiary. Elmworth Energy Corporation is the operating company that will carry out all oil and gas exploration activities for Triangle in Canada, whereas Triangle USA Petroleum will carry out all oil and gas exploration activities for Triangle in the United States. From March 2004 to June 2005, Mr. Hietala served as the President of Golden Eagle Energy Ltd., a private company focused on developing low to medium risk production in west central Alberta. Since 1995, Mr. Hietala has been the President and co-founder of Petro-Hunt Oil and Gas Ltd., a private company focused on providing business and technical evaluation expertise to non-industry operating partners. Mr. Hietala entered the oil and gas business in 1973 with Imperial Oil Limited as a petrophysicist. During the period of 1973 to 1976 Mr. Hietala was involved with Imperial’s Western Canadian exploration and development programs including the active programs of the northern Mackenzie Delta. An active role was taken to develop an understanding of the reservoir production characteristics in the large production base at Imperial Oil. In 1977, Mr. Hietala joined Canadian Hunter Exploration Limited in the capacity of petrophysicist and reservoir evaluation specialist. He held numerous senior level positions, eventually being appointed Vice President and Director of Canadian Hunter Exploration Limited. He was a team contributor to the multitude of discoveries made by Canadian Hunter in Alberta, British Columbia and Saskatchewan.

35

Shaun Toker has been our Chief Financial Officer since August 2007. Mr. Toker is also the Chief Financial Officer 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, an American Stock Exchange and Toronto Stock Exchange listed company. 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 is a Chartered Accountant (Canada).

J. Howard Anderson has been our Chief Operating Officer and Vice-President Engineering since February 1, 2008. Mr. Anderson is also the 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 has been the Vice-President Engineering for Rockyview Energy Inc., an oil production company. Between June 2004 and June 2005, Mr. Anderson was the Manager, Central Business Unit for APF Energy Inc., an oil 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.

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. 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), 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. Since March 2006, Mr. Matkaluk has been an independent businessman. Between January 2003 and February 2006, Mr. Matkaluk was the co-founder and Chief Financial Officer of Relentless Energy Corporation, an oil and gas exploration company. Between June 2001 and December 2002, Mr. Matkaluk was the Chief Financial Officer of Antrim Energy Inc., a Toronto Stock Exchange listed company. 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.

36

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.

Corporate Governance/Nominating Committee

Our Corporate Governance/Nominating Committee currently consists of Messrs. David L. Bradshaw, Randal Matkaluk and Stephen Holditch, with Mr. Holditch elected as Chairman of the Committee. The Board of Directors has determined that all of the members are “independent.”

Our Corporate Governance/Nominating Committee has responsibility for assisting the Board in, among other things, effecting the organization, membership and function of the Board and its committees. The Corporate Governance/Nominating Committee shall identify and evaluate the qualifications of all candidates for nomination for election as directors.

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 FINRA’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.

37

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, 2008, the Audit Committee:

-  Reviewed and discussed the annual audit process and the audited financial statements for the fiscal year ended January 31, 2008 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 auditors 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, 2008 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 assure 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.

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Code of Ethics

We have adopted a Code of Ethics that are 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 the directors, executive officers, and greater than ten percent (10%) beneficial owners have filed all reports required under Section 16(a).

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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, 2008 and 2007 exceeded $100,000

Name & Principal Position	Year		Salary ($)		Bonus ($)		Stock Awards($)		Option Awards ($)		All Other Compensation($)		Total ($)
Mark Gustafson (a),
CEO, Principal		2008		288,000		-		606,667		-		1,083		895,750
Executive Officer		2007		153,000		-		2,080,000		-		763		2,233,763
Ron Hietala (b), President of
Elmworth Energy		2008		-		-		450,000		-		220,000		670,000
Corporation		2007		-		-		1,350,000		-		240,000		1,590,000
Aly Musani (c),
CFO, Principal		2008		78,000		-		-		121,678		3,724		203,402
Financial Officer		2007		120,000		17,500		-		243,356		6,278		387,134
Shaun Toker (d), CFO, Principal Financial Officer		2008		56,500		5,000		-		54,760		2,706		118,966
Troy Wagner (e),		2008		133,333		-		-		145,395		12,777		291,505
COO		2007		96,282		-		-		282,283		3,294		381,859

a) 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.

b) 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 must 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.

c) 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.

d) 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.

e) 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.

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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.

Ron Hietala

Effective March 17, 2008, Elmworth entered into a new employment agreement with Ron Hietala as President, until such time as either party terminates the agreement. Pursuant to the agreement, Mr. Hietala receives an annual salary of $200,000. In addition, Mr. Hietala is entitled to receive an annual bonus based upon various criteria targets. Additionally, Mr. Hietala 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. Hietala’s employment is terminated by Elmworth without cause (as defined in the agreement), Mr. Hietala 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. In addition, pursuant to the employment agreement, Mr. Hietala will serve as President of Triangle USA Petroleum Corporation

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 February 1, 2008, Elmworth entered into an 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 $180,000. Further, Mr. Anderson received options to purchase 300,000 shares of common stock, exercisable at $2.00 per share, with 20% vesting on February 1, 2008 and every six months thereafter. 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.

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Option/SAR Grants in Last Fiscal Year

Name and Position	Number of Units
Randal Matkaluk - Director		200,000
David L. Bradshaw - Director		200,000
Stephen Holditch - Director		100,000
Shaun Toker - Chief Financial Officer		250,000
Executives as a Group		250,000
Non-Executive Directors as a Group		500,000

Outstanding Equity Awards at Fiscal Year-End Table.

Option Awards										Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable		Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)		Option Exercise Price ($)		Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested ($)		Equity Incentive  Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested  (#)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested  ($)
Shaun Toker		50,000		200,000		0	$	2.00	August 16, 2012		0		0		0		0
Steven Holditch		200,000		0		0	$	3.23	August 5, 2010		0		0		0		0
		160,000		40,000		0	$	4.55	February 21, 2011		0		0		0		0
		20,000		80,000		0	$	2.00	August 16, 2012		0		0		0		0
David L. Bradshaw		40,000		160,000		0	$	2.00	August 1, 2012		0		0		0		0
Randal Matkaluk		40,000		160,000		0	$	2.00	August 1, 2012		0		0		0		0

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 or she 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.

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Directors received compensation for their services for the fiscal year ended January 31, 2008 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 ($)		Total ($)
John D. Carlson	$	10,000	$	0	$	0	$	0	$	0	$	0	$	20,000
Stephen A. Holditch	$	15,000	$	0	$	700,357	$	0	$	0	$	0	$	715,357
David L. Bradshaw	$	20,000	$	0	$	57,371	$	0	$	0	$	0	$	77,371
Randal Matkaluk	$	20,000	$	0	$	57,371	$	0	$	0	$	0	$	77,371

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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 24, 2008.

·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		2,650,500			5.36	%
Suite 1250, 521-3rd Avenue SW
Calgary, Alberta T2P 3T3 Canada
Ron W. Hietala		Common Stock		2,000,000			4.05	%
Suite 1250, 521-3rd Avenue SW
Calgary, Alberta T2P 3T3 Canada
Stephen A. Holditch		Common Stock		464,600	(4)		*
Suite 1250, 521-3rd Avenue SW
Calgary, Alberta T2P 3T3 Canada
Shaun Toker		Common Stock		100,000	(3)		*
Suite 1250, 521-3rd Avenue SW
Calgary, Alberta T2P 3T3 Canada
David L. Bradshaw		Common Stock		80,000	(3)		*
Suite 1250, 521-3rd Avenue SW
Calgary, Alberta T2P 3T3 Canada
Randal Matkaluk		Common Stock		80,000	(3)		*
Suite 1250, 521-3rd Avenue SW
Calgary, Alberta T2P 3T3 Canada
Howard Anderson		Common Stock		175,000	(5)		*
Suite 1250, 521-3rd Avenue SW
Calgary, Alberta T2P 3T3 Canada
All Officers and Directors		Common Stock		5,550,100	(6)		11.23	%
As a Group (7 persons)
Palo Alto Investors, LLC		Common Stock		6,944,500	(7)		14.05	%
470 University Avenue
Palo Alto, California 94301
Resolute Performance Fund		Common Stock		9,300,000	(8)		18.82	%
3030 Yonge Street, Suite 5000
Box 73 Toronto, Ontario M4N 3N1

* Less than 1%.

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(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 24, 2008 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 48,653,758 shares issued and outstanding on April 24, 2008.

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

(4) Represents 440,000 shares of common stock underlying options that are currently exercisable or exercisable within 60 days.

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

(6) Includes 500,000 shares of common stock underlying options that are currently exercisable or exercisable within 60 days.

(7) As reported pursuant to a Schedule 13G filed with the Securities and Exchange Commission on February 13, 2008. 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 6,944,500 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.

(8) As reported pursuant to a Schedule 13G filed with the Securities and Exchange Commission on January 30, 2008. Resolute Performance Fund is an open-ended investment trust established under the laws of Ontario, Canada. Resolute Funds Limited is the Trustee and Manager of the Fund. Units of the Fund are sold on a prospectus-exempt basis in selected provinces of Canada to investors in amounts of CDN $150,000 or more. Resolute Funds Limited is registered with the Ontario Securities Commission as an Investment Counsel and Portfolio Manager.

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.

Audit Fees

The aggregate fees billed by our previous auditors, for professional services rendered for the audit of our annual financial statements during the years ended January 31, 2008 and 2007, and for the reviews of the financial statements included in our Quarterly Reports on Form 10-Q during the fiscal years, were $75,960 and $46,200, respectively.

Our current auditors did not bill us during the years ended January 31, 2008 and 2007 for services rendered for the audit of our annual financial statements.

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Audit-Related Fees

Our previous independent registered public accounting firm billed us $7,918 during the fiscal year ended January 31, 2008 and $4,250 during the fiscal year ended January 31, 2007 for audit related services.

Our current independent registered public accounting firm did not bill us during the years ended January 31, 2008 and 2007 for audit related services.

Tax Fees

Our previous independent registered public accounting firm billed us $20,000 during the fiscal year ended January 31, 2008 for tax related work and did not bill us during the fiscal year ended January 31, 2007 for tax related work.

Our current independent registered public accounting firm billed us $3,675 for tax related work during fiscal years ended January 31, 2008, and billed us $5,078 for tax related work during the fiscal year ended January 31, 2007.

All Other Fees

Our independent registered public accounting firm did not bill us during fiscal years ended January 31, 2008 or 2007 for other services.

Our current independent registered public accounting firm did not bill us during the years ended January 31, 2008 and 2007 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.

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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 (filed herewith).
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.
4.1	Securities Purchase Agreement, dated December 8, 2005, by and between Triangle Petroleum Corporation and Cornell Capital Partners LP, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on December 12, 2005 and incorporated herein by reference.
4.2	Secured Convertible Debenture issued to Cornell Capital Partners LP, dated December 8, 2005, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on December 12, 2005 and incorporated herein by reference.
4.3	Registration Rights Agreement, dated December 8, 2005, by and between Triangle Petroleum Corporation and Cornell Capital Partners LP, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on December 12, 2005 and incorporated herein by reference.
4.4	Security Agreement, dated December 8, 2005, by and between Triangle Petroleum Corporation and Cornell Capital Partners LP, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on December 12, 2005 and incorporated herein by reference.
4.5	Security Agreement, dated December 8, 2005, by and between Elmworth Energy Corporation and Cornell Capital Partners LP, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on December 12, 2005 and incorporated herein by reference.
4.6	Security Agreement, dated December 8, 2005, by and between Triangle USA Petroleum Corporation and Cornell Capital Partners LP, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on December 12, 2005 and incorporated herein by reference.
4.7	Securities Purchase Agreement, dated December 28, 2005, 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 December 30, 2005 and incorporated herein by reference.
4.8	Securities Purchase Agreement, dated December 28, 2005, by and between Triangle Petroleum Corporation and Centrum Bank, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on December 30, 2005 and incorporated herein by reference.
4.9	Convertible Debenture issued to Bank Sal. Oppenheim Jr. & Cie., (Schweiz) AG, dated December 28, 2005, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on December 30, 2005 and incorporated herein by reference.
4.10	Convertible Debenture issued to Centrum Bank, dated December 28, 2005, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on December 30, 2005 and incorporated herein by reference.

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4.11	Registration Rights Agreement, dated December 28, 2005, 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 December 30, 2005 and incorporated herein by reference.
4.12	Registration Rights Agreement, dated December 28, 2005, by and between Triangle Petroleum Corporation and Centrum Bank, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on December 30, 2005 and incorporated herein by reference.
4.13	Convertible Debenture issued to Bank Sal. Oppenheim Jr. & Cie., (Schweiz) AG, dated January 23, 2006, filed as an exhibit to the Registration Statement on Form SB-2, filed with the Commission on February 24, 2006 and incorporated herein by reference.
4.14	Convertible Debenture issued to Centrum Bank, dated January 23, 2006, filed as an exhibit to the Registration Statement on Form SB-2, filed with the Commission on February 24, 2006 and incorporated herein by reference.
4.15	Amendment, dated May 3, 2006, to Securities Purchase Agreement dated December 7, 2005, by and between Triangle Petroleum Corporation and Cornell Capital Partners LP, filed as an exhibit to the amended Registration Statement on Form SB-2/A, filed with the Commission on May 17, 2006 and incorporated herein by reference.
4.16	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.
4.17	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.
10.1	Stock Purchase Agreement between the Company and Rowlings Financial Inc., dated as of June 14, 2005, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on June 16, 2005 and incorporated herein by reference.
10.2	Convertible Debenture issued by the Company in favor of Rowlings Financial, Inc., dated as of June 14, 2005, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on June 16, 2005 and incorporated herein by reference.
10.3	Common Stock Purchase Warrant issued by the Company in favor of Rowlings Financial, Inc., dated as of June 14, 2005, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on June 16, 2005 and incorporated herein by reference.
10.4	Registration Rights Agreement between the Company and Rowlings Financial Inc., dated as of June 14, 2005, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on June 16, 2005 and incorporated herein by reference.
10.5	Convertible Debenture issued by the Company in favor of Rowlings Financial, Inc., dated as of July 14, 2005, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on July 18, 2005 and incorporated herein by reference.
10.6	Common Stock Purchase Warrant issued by the Company in favor of Rowlings Financial, Inc., dated as of July 14, 2005, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on July 18, 2005 and incorporated herein by reference.

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10.7	Form of Stock Purchase Agreement, dated as of June 2, 2005, filed as an exhibit to the current report on Form 8-K filed with the Securities and Exchange Commission on July 18, 2005 and incorporated herein by reference.
10.8	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.
10.9	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.
10.10	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.
10.11	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.
10.12	Form of Securities Purchase Agreement, dated as of February 26, 2007, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on February 27, 2007 and incorporated herein by reference.
10.13	Form of Securities Purchase Agreement, dated as of February 26, 2007, filed as an exhibit to the Current Report on Form 8-K, filed with the Commission on February 27, 2007 and incorporated herein by reference.
10.14	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.
10.15	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.
10.16	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.
10.17	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.
10.18	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.
10.19	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.
10.2	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.

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14.1	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.
14.2	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.
21.1	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.
23.1	Consent of Ryder Scott, Independent Petroleum Engineers
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14 and Rule 15d-14(a), promulgated under the Securities and Exchange Act of 1934, as amended.
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14 and Rule 15d 14(a), promulgated under the Securities and Exchange Act of 1934, as amended.
32.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer).
32.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer).

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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 29, 2008	By:	/s/ MARK GUSTAFSON
		Mark Gustafson
		President (Principal Executive Officer)
Date: April 29, 2008	By:	/s/ SHAUN TOKER
		Shaun Toker
		Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

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

Name	Position	Date
/s/ MARK GUSTAFSON Mark Gustafson	President (Principal Executive Officer) and Director	April 29, 2008
/s/ SHAUN TOKER Shaun Toker	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	April 29, 2008
/s/ RON W. HIETALA Ron W. Hietala	Director	April 29, 2008
David L. Bradshaw	Director	April 29, 2008
Stephen A. Holditch	Director	April 29, 2008
/s/ RANDAL MATKALUK Randal Matkaluk	Director	April 29, 2008

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