Triangle Petroleum (TPLMQ) 8-K Regulation FD Disclosure

Exhibit 99.1

No securities regulatory authority has expressed an opinion about these securities and it is an offence to claim otherwise. This prospectus does not constitute a public offering of any securities.

PROSPECTUS

Non-Offering Prospectus November 20, 2008

TRIANGLE PETROLEUM CORPORATION

No securities are being offered or sold pursuant to this prospectus. This prospectus is being filed with the Alberta, British Columbia and Ontario securities commissions to enable Triangle Petroleum Corporation ("Triangle" or the "Corporation"), a company incorporated under the laws of the State of Nevada, to become a reporting issuer under applicable securities legislation in the provinces of Alberta, British Columbia and Ontario. Since no securities are being sold pursuant to this prospectus, no proceeds will be raised. Expenses in connection with the preparation and filing of this prospectus will be borne by the Corporation from its working capital.

As at the date of this prospectus, the Corporation had 67,426,043 shares of common stock ("Common Shares") issued and outstanding. The Common Shares currently trade over the counter and are quoted on the Bulletin Board (the "OTC Bulletin Board") under the symbol "TPLM". On November 19, 2008, the closing sale price for the Common Shares was $0.23 on the OTC Bulletin Board.

The TSX Venture Exchange Inc. (the "TSXV") has conditionally accepted the listing of the Corporation's Common Shares. Listing is subject to the Corporation fulfilling all of the requirements of the TSXV.

The principal office of the Corporation is located at 1250, 521 Third Avenue SW, Calgary, Alberta T2P 3T3.

The Corporation is organized under the laws of a foreign jurisdiction, and two of the Corporation's directors (Messrs. Bradshaw and Holditch) are resident outside of Canada. Although the Corporation has appointed Macleod Dixon LLP, 3700 Canterra Tower, 400 Third Avenue SW, Calgary, Alberta T2P 4H2 as its agent for service of process in the Province of Alberta, it may not be possible for investors to collect from the Corporation and/or its directors and officers, judgements obtained in courts in Canada predicated on the civil liability provisions of securities legislation.

The financial statements included in this prospectus have been prepared in accordance with U.S. generally accepted accounting principles, which differ in certain material respects from Canadian generally accepted accounting principles. The Corporation has not provided, nor is it required to provide, a reconciliation of its financial statements to Canadian generally accepted accounting principles. Unless otherwise noted, all references to dollars or "$" are to U.S. dollars.

No underwriter has been involved in the preparation of this prospectus or performed any review of the contents of this prospectus.

An investment in the Corporation is subject to certain risks related to the nature of the Corporation's business and its present stage of development. Potential investors should carefully consider the information set out under "Risk Factors" and the other information in this prospectus.

This prospectus does not constitute an offer to sell or the solicitation of an offer to buy any securities.

Triangle Petroleum Corporation

1250, 521 Third Avenue SW

Calgary, Alberta T2P 3T3

Phone:  (403) 262-4471

Fax:  (403) 262-4472

Website: www.trianglepetroleum.com

TABLE OF CONTENTS

	Page
FORWARD LOOKING STATEMENTS	II
MARKET AND INDUSTRY DATA	III
PROSPECTUS SUMMARY	IV
The Corporation	iv
Principal Business	iv
Directors and Officers	iv
Principal Properties	iv
Selected Reserves Information	v
Summary Financial Information	v
Risk Factors	v
GLOSSARY OF TERMS	VI
THE CORPORATION	1
BUSINESS OF THE CORPORATION	1
Plan of Operations	1
Employees	1
History of the Corporation	1
Financings	3
The Shale Gas Industry	4
PRINCIPAL PROPERTIES	5
Properties	5
Work Program & Budget	8
AVAILABLE FUNDS	10
DISCLOSURE OF RESERVES DATA	11
Other Material Information	16
Significant Factors or Uncertainties	16
Future Development Costs	16
Natural Gas Wells	17
Properties with No Attributed Reserves	17
Additional Information Concerning Abandonment and Reclamation Costs	18
Costs Incurred	18
Exploration and Development Activities	19
Production Estimates	19
Production History	20
SELECTED CONSOLIDATED FINANCIAL INFORMATION	23
Annual Information of Triangle	23
Quarterly Information of Triangle	23
Dividends	23
U.S. GAAP	24
MANAGEMENT'S DISCUSSION AND ANALYSIS OF TRIANGLE	24
Results of Operations	24
General and Administrative ("G&A")	25
Liquidity and Capital Resources	31
DESCRIPTION OF SHARE CAPITAL	34
Common Shares	34
Warrants	35
Convertible Debentures	35
CAPITALIZATION	35
OPTION PLAN	35
PRIOR SALES	37
TRADING PRICE AND VOLUME	37
ESCROWED SECURITIES	38
PRINCIPAL SHAREHOLDERS	38
DIRECTORS AND OFFICERS	39
Penalties, Sanctions and Bankruptcies	41
EXECUTIVE COMPENSATION	41
Stock Options	42
Employment Contracts	43
Compensation of Directors	44
INDEBTEDNESS OF DIRECTORS AND EXECUTIVE OFFICERS	44
CORPORATE GOVERNANCE DISCLOSURE	44
Board of Directors	44
Directorships	45
Orientation and Continuing Education	45
Ethical Business Conduct	45
Nomination of Directors	45
Compensation	46
Assessments	46
AUDIT COMMITTEE INFORMATION	47
Audit Committee's Charter	47
Composition of the Audit Committee	47
Pre-Approval Policies and Procedures	48
External Auditor Service Fees	48
INDUSTRY CONDITIONS	48
Canadian and U.S. Government Regulation	49
Pricing and Marketing Oil	49
Pricing and Marketing Natural Gas	49
The North American Free Trade Agreement	49
Royalties and Incentives	50
Land Tenure	51
Canadian Environmental Regulation	51
RISK FACTORS	51
Risks Relating to Triangle's Business	51
Risks Relating to The Corporation's Outstanding Financing Arrangements	57
Risks Relating to the Corporation's Common Shares	57
CONFLICTS OF INTEREST	58
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	58
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	58
AUDITOR, TRANSFER AGENT AND REGISTRARS	58
MATERIAL CONTRACTS	58
EXPERTS	59
CONSENT OF KPMG LLP	60
CONSENT OF MANNING ELLIOTT LLP	60
CERTIFICATE OF THE CORPORATION	61
APPENDIX "A" FINANCIAL STATEMENTS	A-1
APPENDIX "B" FORM 51-101F2	B-1
APPENDIX "C" FORM 51-101F3	C-1
APPENDIX "D" CHARTER - AUDIT COMMITTEE	D-1

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FORWARD LOOKING STATEMENTS

Certain statements in this prospectus are forward looking statements. These forward looking statements are not based on historical facts but rather on the expectations of Triangle's management team ("Management") regarding the Corporation's future growth, results of operations, performance, future capital and other expenditures (including the amount, nature and source of funding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, business prospects and opportunities. The words "anticipate", "believe", "estimate", "intend", "plan", "project", "will", "would", and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain these identifying words. Such forward looking statements reflect Management's current beliefs and assumptions and are based on information currently available to Management. Forward looking statements involve significant known and unknown risks and uncertainties. In particular, this prospectus contains forward looking statements pertaining to, among other things:

• capital expenditure programs and other expenditures;

• schedules and timing of certain projects and the Corporation's strategy for growth;

• the quantum of, and future net revenues from, the Corporation's reserves;

• projections of commodity prices and costs;

• expectations regarding the Corporation's ability to raise capital and to add reserves through acquisitions, exploration and development;

• supply and demand for oil, natural gas, and natural gas liquids;

• the Corporation's future operating and financial results; and

• treatment under governmental regulatory regimes and tax laws.

With respect to the forward looking information contained in this prospectus, the Corporation's actual results could differ materially from those anticipated in these forward looking statements as a result of the factors set forth below and elsewhere in this prospectus, including:

• geological, technical, drilling and processing problems;

• uncertainties associated with dealing with governments and their regulation of the oil and gas industry;

• uncertainties associated with additional funding requirements of the Corporation in the future;

• fluctuations in the price of crude oil, natural gas, and natural gas liquids;

• changes in supply and demand for oil, natural gas, and natural gas liquids;

• changes in income tax laws or incentive programs relating to the oil and gas industry;

• royalties payable in respect of oil and gas production;

• general economic conditions in Canada, the United States and globally;

• fluctuation in foreign exchange or interest rates;

• costs of land reclamation;

• competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; and

• operating risk liability.

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The foregoing list of factors should not be construed as exhaustive. A number of other factors could cause actual results to differ materially from the results discussed in the forward looking statements, many of which are beyond the control of the Corporation. Some of these other factors are discussed under the heading "Risk Factors" in this prospectus. Readers are cautioned that these factors and risks are difficult to predict and that the assumptions used in the preparation of such information, although considered reasonably accurate at the time of preparation, may prove to be incorrect. Consequently, there is no representation by the Corporation that actual results achieved will be the same in whole or in part as those set out in the forward looking information and subscribers should not place undue reliance on them. Furthermore, the forward looking statements contained in this prospectus are made as of the date hereof, and the Corporation undertakes no obligation, except as required by applicable securities legislation, to update publicly or to revise any of the included forward looking statements, whether as a result of new information, future events or otherwise. The forward looking statements contained herein are expressly qualified by this cautionary statement.

MARKET AND INDUSTRY DATA

Unless otherwise indicated, the market and industry data contained in this prospectus is based upon information from the Canadian government, provincial governments, independent industry and other publications and the knowledge of and experience of Management in the markets in which the Corporation operates. While the Corporation believes this data to be reliable, market and industry data is subject to variations and cannot be verified with complete certainty due to limits on the availability and reliability of raw data, the voluntary nature of the data gathering process and other limitations and uncertainties inherent in any statistical survey. The Corporation has not independently verified any of the data from third party sources referred to in this prospectus or ascertained the underlying assumptions relied upon by such sources.

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PROSPECTUS SUMMARY

The following is a summary of the principal features of this prospectus and should be read together with the more detailed information and financial data and statements contained elsewhere in this prospectus. Reference is made to the Glossary for the meanings of certain defined terms.

The Corporation

Triangle was incorporated under the laws of the State of Nevada on December 11, 2003 under the name "Peloton Resources Inc." On May 10, 2005, the Corporation amended its articles to change its name to "Triangle Petroleum Corporation". The principal or head office of the Corporation is located at 1250, 521 Third Avenue SW, Calgary, Alberta T2P 3T3 and the registered office of the Corporation in Alberta is located at 3700 Canterra Tower, 400 Third Avenue SW, Calgary, Alberta T2P 4H2. The Corporation conducts its operations through its subsidiaries, Triangle USA Petroleum Corporation in the U.S. and Elmworth Energy Corporation in Canada. (See "The Corporation")

Principal Business

The Corporation is an exploration company focused on emerging shale gas opportunities in the Maritimes Basin in the provinces of Nova Scotia and New Brunswick. In addition, the Corporation also has interests in the Fayetteville Shale trend in Arkansas, the Barnett Shale trend in Texas and interests in conventional oil and gas properties in Alberta, Colorado and Wyoming. Triangle's corporate strategy is to exploit its Canadian shale gas assets based upon the experience it has gained in the U.S. shale gas market since November 2005. (See "Business of the Corporation")

Directors and Officers

Triangle's directors and senior officers are as set out in the following table:

Name	Positions Held
Mark G. Gustafson	Chief Executive Officer & Director
Shaun Toker	Chief Financial Officer & Secretary
J. Howard Anderson	President, Chief Operating Officer, and Vice President, Engineering
David L. Bradshaw	Director
Stephen A. Holditch	Director
Randal Matkaluk	Director

(See "Directors and Officers")

Principal Properties

All of Triangle's oil and gas properties are located in the United States and Canada. The Corporation is currently participating in oil and gas exploration activities in the provinces of Nova Scotia and New Brunswick. Triangle's core project is a shale gas opportunity located in the Maritimes Basin in the provinces of Nova Scotia and New Brunswick. Triangle intends to execute its operating plan in order to realize the full value of the land base that has been established in the Maritimes Basin. Triangle is also in the process of evaluating a potential secondary shale gas project in Western Canada. The Corporation's remaining four project areas (Fayetteville Shale, Rocky Mountain Program, Barnett Shale and Alberta Deep Basin) are currently designated as non-core due to Triangle's desire to focus its limited manpower resources on one core and one secondary project. (See "Business of the Corporation" and "Principal Properties")

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Selected Reserves Information

The following is a summary of the Corporation's estimated projection of remaining natural gas and natural gas liquids reserves as at July 1, 2008, based on forecast price and cost assumptions, as evaluated by Ryder Scott Company Petroleum Consultants.

	Natural Gas				Natural Gas Liquids
	Gross (mmcf)		Net (mmcf)		Gross (bbls)		Net (bbls)
Canada
Total Proved		129		94		2,790		2,123
Total Probable		43		34		1,079		825
Total Proved plus Probable		172		128		3,869		2,948
United States
Total Proved		33		25		0		0
Total Probable		35		26		0		0
Total Proved plus Probable		68		51		0		0
Aggregate (Canada + USA)
Total Proved		162		119		2,790		2,123
Total Probable		78		60		1,079		825
Total Proved plus Probable		240		179		3,869		2,948

(See "Disclosure of Reserves Data")

Summary Financial Information

The following is a summary of selected unaudited financial information of the Corporation as at July 31, 2008 and July 31, 2007 and audited financial information of the Corporation as at and for the fiscal years ended January 31, 2008 and January 31, 2007, which is derived from and should be read in conjunction with the financial statements of the Corporation and the notes to such financial statements included elsewhere in this prospectus. (See "Selected Consolidated Financial Information") All references to "$" are to U.S. dollars.

	Six Months  ended July 31, 2008 ($)			Six Months  ended July 31, 2007 ($)			Fiscal Year  ended January 31, 2008 ($)			Fiscal Year  ended January 31, 2007 ($)
Revenue, net of royalties		259,950			193,226			586,804			54,342
Net loss		(4,213,248	)		(9,305,984	)		(29,600,747	)		(4,281,969	)
Total operating expenses		2,533,981			7,921,655			26,503,535			9,525,047
Oil and gas properties		22,773,219			24,364,524			24,978,949			21,101,495
Total assets		47,294,130			43,540,355			32,579,190			30,747,272
Total liabilities		14,429,697			29,498,830			22,520,504			35,851,564
Working capital (deficit)		10,623,175			1,304,128			(7,678,143	)		(16,326,960	)
Total shareholders' equity (deficit)		32,864,433			14,041,525			10,058,686			(5,104,292	)
Basic and diluted loss per share		(0.08	)		(0.28	)		(0.80	)		(0.21	)

(See "Selected Consolidated Financial Information" and "Appendix A - Financial Statements")

Risk Factors

An investment in the Corporation is subject to certain risks related to the nature of the Corporation's business and its present stage of development. Potential investors should carefully consider the information set out under "Risk Factors" and the other information in this prospectus.

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GLOSSARY OF TERMS

In this prospectus, the following terms shall have the meanings set forth below, unless otherwise indicated:

"1933 Act" means the U.S. Securities Act of 1933, as amended;

"1934 Act" means the U.S. Securities Exchange Act of 1934, as amended;

"2005 Plan" means the Corporation's 2005 Incentive Stock Plan to acquire Common Shares;

"2007 Plan" means the Corporation's 2007 Incentive Stock Plan to acquire Common Shares;

"ABCA" means the Alberta Business Corporations Act, R.S.A. 2000, c. B-9, as amended, including the regulations promulgated thereunder;

"AEPEA" means the Environmental Protection and Enhancement Act, R.S.A. 2000, c. E-12;

"AEUB" means the Alberta Energy and Utilities Board;

"Beech Hill Farm-In Agreement" means the farm-in agreement dated May 25, 2007 between Elmworth as farmee and Contact as farmor for a 70% working interest (net 45% should Zodiac elect to participate pursuant to the Zodiac Joint Venture Agreement) on approximately 68,000 gross acres in the Beech Hill Block of the Province of New Brunswick;

"Board of Directors" means the board of directors of the Corporation;

"COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook;

"Common Shares" mean the shares of common stock in the capital of Triangle;

"Contact" means Contact Exploration Inc.;

"Convertible Debentures" means the $10,000,000 principal amount convertible debentures due and payable by the Corporation on June 1, 2009, with 7.5% interest, unless sooner converted into Common Shares, at the holder's option, at a rate of $4.00 per share;

"Corporation" or "Triangle" means Triangle Petroleum Corporation and includes Triangle's two wholly-owned subsidiaries, Elmworth and Triangle USA;

"Elmworth" means Elmworth Energy Corporation, a wholly-owned subsidiary of the Corporation incorporated under the ABCA;

"EPEA" means the Environmental Protection and Enhancement Act, R.S.A. 2000, c. E-12, as amended, including the regulations promulgated thereunder;

"ERCB" means the Energy Resources Conservation Board of the Province of Alberta;

"Escrow Agreement" means the agreement dated November 20, 2008 among Triangle and Olympia Trust Company and those shareholders whose Common Shares are required to be escrowed and who are required to execute such agreement;

"Filing Jurisdictions" means the provinces of Alberta, British Columbia and Ontario;

"Management" means Triangle's management team;

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"NAFTA" means the North American Free Trade Agreement;

"Named Executive Officers" means the individuals who served, at any time during the previous financial year, as the Chief Executive Officer, the Chief Financial Officer, and each of Triangle's three most highly compensated officers, other than the Chief Executive Officer, the Chief Financial Officer, who were serving as officers at the end of the most recently completed financial year and whose total salary and bonus exceeds Cdn$150,000;

"NEB" means National Energy Board of Canada;

"NI 41-101" means National Instrument 41-101 - General Prospectus Requirements;

"NI 51-101" means National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities;

"NI 52-110" means National Instrument 52-110 - Audit Committees;

"Option" means an option to acquire Common Shares pursuant to one of the Option Plans;

"Option Plans" means, collectively, the 2005 Plan and the 2007 Plan;

"OTC Bulletin Board" means the over the counter Bulletin Board;

"Ryder Scott" means Ryder Scott Company Petroleum Consultants;

"Ryder Scott Reserves Report" means the report of Ryder Scott as of July 1, 2008 entitled "Estimated Future Reserves and Income Attributable to Certain Leasehold and Royalty Interests - Constant and Escalated Parameters";

"Ryder Scott Work Program Report" means the report of Ryder Scott dated September 24, 2008, for the period as of September 15, 2008, entitled "Work Program & Budget Pertaining to Certain Acreage Interests Onshore Nova Scotia";

"SEC" means the U.S. Securities and Exchange Commission;

"Shareholder" means a holder of Common Shares;

"Tax Act" means the Income Tax Act (Canada), as amended from time to time;

"Triangle USA" means Triangle USA Petroleum Corporation, a wholly-owned subsidiary of Triangle incorporated under the laws of the State of Colorado;

"TSXV" means the TSX Venture Exchange Inc.;

"U.S." means the United States of America;

"Warrants" means the warrants to purchase Common Shares exercisable until June 3, 2010 at a purchase price of $2.25 per Common Share;

"Windsor Block Farm-In Agreement" means the farm-in agreement dated May 10, 2007 between Elmworth as farmee and Contact as farmor for a 70% working interest (net 45% should Zodiac elect to participate pursuant to the Zodiac Joint Venture Agreement) on approximately 516,000 gross acres in the Windsor Sub-Basin of the Maritimes Basin located in the Province of Nova Scotia;

"Zodiac" means Zodiac Exploration Corp., a private Calgary-based exploration company; and

"Zodiac Joint Venture Agreement" means the joint venture agreement between Elmworth and Zodiac effective May 31, 2008 wherein Zodiac has the option to earn up to a 25% working interest in the Windsor Block and up to a 25% working interest in the Beech Hill Block.

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Conventions

Certain terms used herein are defined in the Glossary. Certain other terms used herein but not defined herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101.

The financial statements included in this prospectus have been prepared in accordance with U.S. generally accepted accounting principles, which differ in certain material respects from Canadian generally accepted accounting principles. The Corporation has not provided, nor is it required to provide, a reconciliation of its financial statements to Canadian generally accepted accounting principles.

Unless otherwise noted, all references to dollars or "$" are to U.S. dollars.

Abbreviations and Conversions

Abbreviations

Oil and Natural Gas Liquids		Natural Gas
bbl	barrel	mcf	thousand cubic feet
bbls	barrels	mcf/d	thousand cubic feet per day
bbls/d	barrels per day	mmcf	million cubic feet
mbbls	thousand barrels	mmcf/d	million cubic feet per day
NGL	natural gas liquids	bcf	billion cubic feet
		bcf/d	billion cubic feet per day
		tcf	trillion cubic feet

boebarrel of oil equivalent of natural gas on the basis of 1 boe for 6 (unless otherwise stated) mcf of natural gas (this conversion factor is an industry accepted norm and is not based on either energy content or current prices)

boe/dbarrel of oil equivalent per day

mboethousand barrels of oil equivalent

Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Conversions

The following table sets forth certain standard conversions from Standard Imperial Units to the International System of Units (or metric units).

To Convert From	To	Multiply By
mcf	cubic metre	28.174
cubic metres	cubic feet	35.494
bbls	cubic metres	0.159
cubic metres	bbls of oil	6.290
feet	metres	0.305
metres	feet	3.281
miles	kilometres	1.609
kilometres	miles	0.621
acres	hectares	0.405
hectares	acres	2.471

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THE CORPORATION

Triangle was incorporated under the laws of the State of Nevada on December 11, 2003 under the name "Peloton Resources Inc.". On May 10, 2005, the Corporation amended its articles to change its name to "Triangle Petroleum Corporation".

The principal or head office of the Corporation is located at 1250, 521 Third Avenue SW, Calgary, Alberta T2P 3T3 and the registered office of the Corporation in Alberta is located at 3700 Canterra Tower, 400 Third Avenue SW, Calgary, Alberta T2P 4H2.

The Corporation has two wholly-owned subsidiaries: Triangle USA Petroleum Corporation, which was incorporated under the laws of the State of Colorado on October 27, 2005 and Elmworth Energy Corporation, which was incorporated under the ABCA on June 1, 2005. The Corporation conducts its operations through its subsidiaries, Triangle USA in the U.S. and Elmworth in Canada. In this prospectus, unless the context otherwise requires, the "Corporation" or "Triangle" refers to Triangle Petroleum Corporation together with its two subsidiaries.

BUSINESS OF THE CORPORATION

The Corporation is an exploration company focused on emerging shale gas opportunities in the Maritimes Basin in the Provinces of Nova Scotia and New Brunswick. Triangle has acquired 2D and 3D seismic and drilled two vertical test wells on the Windsor Block (516,000 gross acres, 361,200 net acres or 232,200 net acres if the Corporation's joint venture participant elects to participate) in Nova Scotia in late 2007 and acquired 2D seismic, creating the option to earn an interest in the Beech Hill Block (68,000 gross acres, 47,600 net acres or 30,600 net acres if the Corporation's joint venture participant elects to participate) in New Brunswick in 2008. In addition, the Corporation has non-core interests in the Fayetteville Shale trend in Arkansas (20,344 gross acres, 10,172 net acres), the Barnett Shale trend in Texas (478 gross acres, 61 net acres), and conventional oil and gas plays in the Kakwa and Wapiti areas of Alberta (23,360 gross acres, 5,394 net acres) and the states of Colorado and Wyoming (38,419 gross acres and 9,605 net acres).

Plan of Operations

Triangle's corporate strategy is to utilize its U.S. shale gas experience to secure early stage shale gas projects in Canada. In conjunction with this strategy, the Corporation has screened and participated in various projects in North America with numerous potential joint venture partners. Based on activity to date, the Corporation has selected and designated one project as core from its portfolio of projects, based on Management's 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 Eastern Canada. The Corporation intends to execute its operating plan in order to realize the full value of the land base that has been established in the Maritimes Basin. The Corporation is also in the process of evaluating a potential secondary shale gas project in Western Canada. Its remaining four project areas (Fayetteville Shale, Rocky Mountain Program, Barnett Shale and Alberta Deep Basin) are currently designated as non-core due to the Corporation's desire to focus its limited manpower resources on one core and one secondary project.

Employees

There are presently seven full-time employees and two part-time employees of the Corporation and one full time consultant engaged by the Corporation. See "Directors and Officers".

History of the Corporation

Acquisitions and Dispositions

Triangle was incorporated in the State of Nevada on December 11, 2003 under the name "Peloton Resources Inc.". Its initial principal business plan was to acquire, explore and develop mineral properties and to ultimately seek earnings by exploiting the mineral claims. In December 2003, the Corporation purchased six mineral claims situated in the Greenwood Mining Division in the Province of British Columbia. A consultant was hired to assess the economic viability of exploring for, and developing, gold reserves on Peloton's properties. Based upon his report, Peloton decided to abandon all mining activities and to change its principal business to that of acquisition and exploration of oil and gas resource properties. Correspondingly, on May 10, 2005, the Corporation changed its name to "Triangle Petroleum Corporation".

1

On October 26, 2005, through its wholly-owned subsidiary, Triangle USA, the Corporation entered into a two year participation agreement with Kerogen Energy, Inc. ("Kerogen") to explore potential shale gas projects within the Southern Fort Worth Basin in Texas. The Corporation paid $300,000 to Kerogen upon execution of the agreement and another $297,600 in the following year. Pursuant to the terms of the agreement, all potential prospects discovered were first offered to the Corporation, which then had the right to participate in the prospect for 30% of the interest available to Kerogen. In the event that the Corporation exercised its right to participate in any prospect, the Corporation would be responsible for 30% of Kerogen's costs associated with the prospect and would receive 30% of all profits, subject to a 10% carrying fee exercisable by Kerogen. The projects within the Southern Fort Worth Basin in Texas were designated as non-core in 2007.

On October 28, 2005, through Triangle USA, the Corporation entered into a joint development agreement with Hunter Energy LLC ("Hunter") to jointly develop three oil and gas properties belonging to Hunter located in Colorado, Wyoming and Montana. The Corporation paid $1,000,000 to Hunter upon finalizing the exploration agreements, and another $1,000,000 on November 30, 2005. In addition, the Corporation paid 25% of the cost for the drilling of the first well, and carried a proportional share of Hunter's cost of the drilling and completion of the first well, being equal to 8.3% for a total share of the costs of the first well of 33.3%. These three properties were designated as non-core by the Corporation in 2007. In June 2008, the Montana project was sold by the Corporation for gross proceeds of $800,503.

On September 19, 2006, through Triangle USA, the Corporation entered into a joint development agreement with Kerogen to purchase 50% of Kerogen's land position in the Fayetteville Shale of the Arkoma Basin in Arkansas and to jointly develop oil and gas properties thereon. Pursuant to the agreement, the Corporation agreed to pay up to $9,609,039 for the Corporation's 50% interest in the land and seismic programs on the property. All costs for the land and seismic programs in excess of $9,609,039 were to be split evenly between the Corporation and Kerogen. Upon completion of the seismic programs, the Corporation was to jointly participate in two test wells per area on or before December 31, 2007. The Corporation agreed to pay up to $3,266,340 in test well costs per area, with all costs in excess of $3,266,340 to be split evenly between the Corporation and Kerogen. The Corporation designated the Fayetteville Shale project as non-core in 2007 and entered into an agreement with Tristone Capital to market the property for sale.

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, the Corporation executed two farm-in agreements with a Canadian company to pursue two shale gas opportunities in the Maritimes Basin in May 2007.

The Beech Hill Farm-In Agreement, located in the area known as the Beech Hill Block, was entered into with Contact in May 2007 and covers approximately 68,000 gross acres in the Moncton Sub-Basin of the Maritimes Basin located in the Province of New Brunswick. The Corporation is entitled to earn a 70% working interest in the block subsequent to the acquisition and evaluation of a minimum Cdn$250,000 seismic program and then electing no later than December 31, 2008 to drill a test well by mid-2009. Effective May 31, 2008, the Corporation entered into the Zodiac Joint Venture Agreement, wherein Zodiac agreed to incur the first Cdn$250,000 of costs for the seismic program for the option to earn a 25% working interest in the Beech Hill Block after paying 50% of the test well costs. Based upon Zodiac participating in the test well, the Corporation would retain a 45% working interest and would continue as operator.

The Windsor Block Farm-In Agreement, located in the area known as the Windsor Block, was entered into with Contact 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. During fiscal 2008, Triangle earned a 70% working interest in the block by drilling and completing a test well. Effective May 31, 2008, Triangle entered into the Zodiac Joint Venture Agreement to drill as many as six new delineation wells on the Windsor Block. The joint venture provides for an initial commitment by Zodiac to pay 50% of drilling costs, up to Cdn$7.5 million (Cdn$15 million gross), to earn a 12.5% working interest in the entire Windsor Block. Within 30 days of fulfilling this expenditure commitment, Zodiac has the option to commit another Cdn$7.5 million (Cdn$15 million gross) for an additional 12.5% working interest. Based upon Zodiac spending the entire Cdn$15 million, Triangle would retain a 45% working interest and would continue as operator, and Zodiac would earn a 25% working interest in the Windsor Block.

2

The Windsor Block is covered by an exploration agreement with the Nova Scotia government, originally issued in 1999, which was due to expire on September 15, 2008, and has now been extended by the Nova Scotia Department of Energy an additional 180 days. The Corporation is working with the Nova Scotia government to convert the exploration agreement into a production agreement. The Corporation submitted a development plan application in mid June 2008, which triggered an automatic six month extension of the exploration agreement while the Nova Scotia government reviews the application. If the production agreement is not granted, the Corporation's right to explore for and develop oil and gas on this block would be forfeited.

In November 2008, the Corporation sold 530 gross acres (265 net acres) of undeveloped acreage in the Fayetteville Shale of the Arkoma Basin in Arkansas for gross proceeds of $222,466.

Financings

First Convertible Debentures

On June 14, 2005, the Corporation 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 Common Shares, 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 Common Shares, exercisable at a price of $1.00 per share until June 15, 2008.

The convertible debentures matured on June 10, 2007. The Corporation was not required to make any interest or principle payments until the maturity date. During the year ended January 31, 2006, a principal amount of $900,000 was converted into 900,000 Common Shares. During the year ended January 31, 2007, a principal amount of $2,350,000 was converted into 2,350,000 Common Shares. During the year ended January 31, 2008, a principal amount of $2,750,000 was converted into 2,750,000 Common Shares and 6,000,000 warrants were converted into 6,000,000 Common Shares. As at January 31, 2008, all of the $6,000,000 convertible debentures had been converted into Common Shares of the Corporation.

Second Convertible Debentures

On December 8, 2005, the Corporation entered into a securities purchase agreement with Cornell Capital Partners L.P. (now YA Global Investments, L.P. and referred to herein as "Cornell"), pursuant to which Cornell purchased 5% secured convertible debentures in the aggregate principal amount of $15,000,000. The gross proceeds of the financing were received as to $5,000,000 on December 8, 2005, $5,000,000 on January 17, 2006, and $5,000,000 on June 1, 2006. The Corporation agreed to pay an 8% fee on the receipt of each instalment, and a $15,000 structuring fee. The convertible debentures were to mature on the third anniversary of the date of issue and the Corporation was not required to make any payments until the maturity date. Cornell had the ability to convert up to $1,000,000 per month of the convertible debentures into Common Shares 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 Shares 10 trading days immediately preceding the date of conversion. The Corporation, at its option, had 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 Shares could not be less than $5.00 at the time of the redemption. In the event of redemption, the Corporation would be obligated to pay an amount equal to the principal amount being redeemed plus a 20% redemption premium, and accrued interest. Cornell converted a total of $11,000,000 and, on June 5, 2008, the Corporation repaid the remaining $4,000,000 of these convertible debentures, plus an early redemption fee of $800,000 and associated accrued interest of $1,299,860. None of the Cornell convertible debentures remain outstanding.

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Third Convertible Debentures

On December 28, 2005, the Corporation entered into a securities purchase agreement with two accredited investors, Bank Sal. Oppenheim Jr. & Cie., (Schweiz) AG and Centrum Bank, providing for the sale by the Corporation to the investors of 7.5% Convertible Debentures in the aggregate principal amount of $10,000,000 and warrants to purchase 1,250,000 Common Shares, exercisable at a price of $5.00 per share until December 28, 2006, which have since expired. The Convertible Debentures are due and payable on June 1, 2009, with 7.5% interest, unless sooner converted into Common Shares, at the holder's option, at a rate of $4.00 per share. The investors have contractually agreed to restrict their ability to convert their respective debentures such that the number of Common Shares held by such investor and its affiliates after such conversion does not exceed 4.99% of the then issued and outstanding Common Shares. All of the Common Shares issuable upon conversion of the Convertible Debentures may be sold without restriction. As at July 31, 2008, there remains issued and outstanding an aggregate of $10,000,000 principal amount of Convertible Debentures and accrued interest of $1,917,122 that may be converted into Common Shares at $4.00 per share at the option of the debenture holders.

In connection with the securities purchase agreement, the Corporation also entered into a registration rights agreement providing for the filing of a registration statement with the SEC registering the Common Shares issuable upon conversion of the Convertible Debentures and warrants. The Corporation was obligated to use its best efforts to cause the registration statement to be declared effective no later than May 28, 2006 and to ensure that the registration statement remains in effect until all of the Common Shares 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 Corporation is required pay to the investors, as liquidated damages, for each month that the registration statement is not declared effective, a cash amount equal to 1% of the liquidated value of the Convertible Debentures. The registration statement continues to be effective.

Common Shares

On February 26, 2007, the Corporation sold an aggregate of 10,412,000 Common Shares at a price of $2.00 per share to 24 investors for aggregate proceeds of $20,824,000. The Common Shares were issued in a private placement transaction pursuant to section 4(2) of the 1933 Act. Pursuant to the terms of sale, the Corporation agreed to cause a resale registration statement covering the Common Shares to be filed no later than 30 days after the closing and declared effective no later than 120 days after the closing. The registration statement was declared effective by the SEC on March 14, 2007.

Units

On June 3, 2008, the Corporation sold an aggregate of 18,257,500 units in a private placement transaction for gross proceeds of $25,560,500. The net proceeds, after deducting expenses, were $23,537,913. Each unit was priced at $1.40 per unit and consists of one Common Share and one-half of a warrant. One full warrant can be exercised into one Common Share for a period of two years at a price of $2.25 per share. Pursuant to the terms of the sale, the Corporation was required, on a best efforts basis, to file a registration statement with the SEC, and to cause such registration statement to be declared effective by the SEC, within 150 days after closing, to permit the public resale of the shares underlying the warrants. The registration statement was declared effective by the SEC on July 14, 2008. Also, pursuant to the terms of the sale, the Corporation is required, on a best efforts basis, to list its Common Shares on the Toronto Stock Exchange (which includes the TSXV) on or before December 31, 2008. Failure to list the shares for trading by such date shall result in the Corporation paying, pro rata to the purchasers, of a penalty equal to 2% of the gross proceeds of the offering for each month or partial month until the shares are listed for trading on the Toronto Stock Exchange (which includes the TSXV), not to exceed 10% in the aggregate.

The Shale Gas Industry

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, is often found over large contiguous areas. Most shales have low matrix permeabilities 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.

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In general, shale reservoirs have the following characteristics:

· initial production rates that range from 20 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;

· long production lives (up to 30 years);

· potential to be thick (up to ½ kilometre);

· typically organically rich;

· large gas in place (5 bcf to 100 bcf per section);

· low matrix porosity and permeability; and

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

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.

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 of 2 bcf/d. Another new shale gas play in the U.S. is the Fayetteville Shale near Conway County, Arkansas.

In Canada there are two established shale gas plays (the Montney shale in northeast British Columbia and northwest Alberta and the Devonian Horn River shales in northeast British Columbia) and one potentially emerging shale gas play in the Appalachians of Southern Quebec.

With several companies in the early stages of delineating other shale natural gas plays and continued production growth from existing plays, Management believes that shale gas production in North America will continue to grow for years to come. The long-life nature of shale gas plays, the substantial advances in technology in recent years and today's high commodity price environment have increased the economics of shale gas significantly over the last few years.

PRINCIPAL PROPERTIES

Properties

All of Triangle's oil and gas properties are located in the United States and Canada. The Corporation is currently participating in oil and gas exploration activities in the provinces of Nova Scotia and New Brunswick. Triangle's core project is a shale gas opportunity located in the Maritimes Basin in the provinces of Nova Scotia and New Brunswick. Triangle intends to execute its operating plan in order to realize the full value of the land base that has been established in the Maritimes Basin in the provinces of Nova Scotia and New Brunswick. Triangle is also in the process of evaluating a potential secondary shale gas project in Western Canada. The Corporation's remaining four project areas (Fayetteville Shale, Rocky Mountain Program, Barnett Shale and Alberta Deep Basin) are currently designated as non-core due to Triangle's desire to focus its limited manpower resources on one core and one secondary project.

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Canada

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 geological history for a given area, estimates of pressure and temperature profiles and a determination of the ability to fracture stimulate a prospective shale package. As a direct result of implementing this strategy, Triangle executed two farm-in agreements with a Canadian company to pursue two shale gas opportunities in the Maritimes Basin in May 2007.

Beech Hill Block

The Beech Hill Farm-In Agreement was entered into with Contact in May 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. Triangle is entitled to earn a 70% working interest in the block subsequent to the acquisition and evaluation of a minimum Cdn$250,000 seismic program and then electing no later than December 31, 2008 to drill a test well by mid-2009. Effective May 31, 2008, the Corporation entered into the Zodiac Joint Venture Agreement, wherein Zodiac agreed to incur the first Cdn$250,000 of costs for the seismic program for the option to earn a 25% working interest in the Beech Hill Block after paying 50% of the test well costs. Based upon Zodiac participating in the test well, Triangle would retain a 45% working interest and would continue as operator.

During June and July 2008, approximately $280,000 gross ($30,000 net) expenditures were incurred to complete the acquisition phase of approximately 30 kilometres of 2D seismic on the Beech Hill Block. Triangle now has until the end of 2008 to interpret this data and decide whether or not to drill a well by mid-2009 in order to earn its 70% working interest (net 45% should Zodiac elect to participate). Zodiac has paid Cdn$250,000 towards the seismic program, thereby earning the option to participate in the drilling of the first potential well. The Beech Hill Block is covered by leases and licenses to search for oil and natural gas with the New Brunswick government which expire between February 2009 and June 2011.

Windsor Block

The Windsor Block Farm-In Agreement was entered into with Contact 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, Triangle earned a 70% working interest in the block by drilling and completing a test well. In July 2008, its joint venture partner, Contact, elected to maintain its 30% working interest instead of converting to a 5% gross overriding royalty. Effective May 31, 2008, Triangle entered into the Zodiac Joint Venture Agreement to drill as many as six new delineation wells on the Windsor Block. The joint venture provides for an initial commitment by Zodiac to pay 50% of drilling costs, up to Cdn$7.5 million (Cdn$15 million gross), to earn a 12.5% working interest in the entire Windsor Block. Within 30 days of fulfilling this expenditure commitment, Zodiac has the option to commit another Cdn$7.5 million (Cdn$15 million gross) for an additional 12.5% working interest. Based upon Zodiac spending the entire Cdn$15 million, Triangle would retain a 45% working interest and would continue as operator, and Zodiac would earn a 25% working interest in the Windsor Block.

From May 2007 to June 2008, Triangle spent approximately $17.5 million (net $14.6 million) on the first stage of the Windsor Block exploration program, consisting of drilling and completing two vertical test wells (Kennetcook #1 and Kennetcook #2), a 2D and 3D seismic program and geological studies. Both of the vertical test wells, the seismic and geological studies have provided Triangle with sufficient valuable technical information for it to believe that this is a significant shale gas resource project. In conjunction with Contact electing to maintain their 30% working interest instead of converting to a gross over-riding royalty in July 2008, Contact paid Triangle 30% of the gross costs ($2.9 million) for the second well and seismic program that was expended in this first stage of the drilling program that was not a part of the earning parameter.

6

The Windsor Block is covered by an exploration agreement with the Nova Scotia government, originally issued in 1999, which was due to expire on September 15, 2008, and has now been extended by the Nova Scotia Department of Energy an additional 180 days. Triangle is working with the Nova Scotia government to convert the exploration agreement into a production agreement. Triangle submitted a development plan application in mid June 2008, which triggered an automatic six month extension of the exploration agreement while the Nova Scotia government reviews the application. If the production agreement is not granted, Triangle's right to explore for and develop oil and gas on this block would be forfeited.

In July 2008, Triangle started the second stage of its Windsor Block program. Triangle contracted Nabors Rig #4, which has a depth rating of 3,600 meters, for the balance of 2008 to drill as many as six wells that are expected to test the gas content and productivity of the Horton Bluff shales in various locations across the Windsor Block, and also to evaluate potential overlying conventional oil and gas reservoirs. The first vertical exploration well of this second stage, N-14-A, spud in mid July 2008. N-14-A is located approximately 8 kilometres north of Triangle's two 2007 vertical test wells, Kennetcook #1 and Kennetcook #2. N-14-A has been drilled to a depth of 2,600 meters. The well encountered Horton Bluff shale at a depth of 1,100 meters, and drilled through a total of 1,500 meters of shale and interbedded sands before drilling was terminated in the lower Horton Bluff. An extensive suite of open hole logs has been obtained over the entire shale interval. Core was taken in the shale over an 18 meter interval at a depth of 1,700 meters, and cuttings samples were retrieved throughout the drilling operation. Log and lab analyses are currently underway in Calgary and Houston. The highest gas response was observed while drilling the interval between 1,300 to 2,500 meters. Preliminary analysis of the shales below 2,500 meters indicate higher thermal maturity and diminished gas response, so the decision was made to suspend drilling at 2,600 meters and to set 177 mm (7 inches) intermediate casing. By setting the large intermediate casing, Triangle retains the option to either deepen or drill out horizontally, depending on formation evaluation and completion results in the vertical well.

Triangle's second vertical exploration well in 2008, O-61-C, was spudded in late August 2008. The well finished drilling and was cased in October 2008. This well is located approximately 22 kilometres west of N-14-A, and is located in a separate fault block from N-14-A, extending the trend from the two Kennetcook test wells Triangle drilled in 2007. Total depth drilled was 2,960 meters. This well has been positioned using seismic to test the Horton Bluff shales and to evaluate potential conventional reservoirs in the uphole Windsor group. Logs have indicated over 300 meters of shale within the Horton Bluff section, with lab work ongoing to determine organic content and gas potential. Completion operations are expected to commence before the end of October on the N-14-A well, followed closely by 0-61-C. Individual completion intervals are currently being identified by Triangle's technical staff.

The drilling rig, Nabors Rig #4, has been moved from O-61-C and rigged up at a third location, E-38-A, in the Kennetcook area of the Windsor Block. This well is testing another new fault block in which Horton Bluff shales have been identified on seismic, and the well is positioned to evaluate additional uphole conventional targets. Total depth is expected to be 2,200 meters.

Western Canadian Shale Program

Triangle continues to actively evaluate various shale packages in Alberta and British Columbia. Its objective is to potentially secure an initial land position and to commence an exploration program in 2009. To date, Triangle has participated in a multi-company geological study of the West Canadian Sedimentary Basin, reviewed this study, identified its own key technical indicators, correlated these key indicators back to the study and identified prospective shale areas. This follows the corporate strategy in the Maritimes Basin of utilizing its U.S. shale gas experience to secure early stage shale gas projects in Canada.

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

In fiscal 2009, there is no exploration activity planned on this project. Triangle is producing from two wells. The first well is located in the Kakwa Area and Triangle has an 18% interest before payout (12% after payout). The second well is located in the Wapiti Area and Triangle has an approximate 35% working interest.

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United States

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 its exploration program, Triangle decided in late March 2008 to sell its 10,437 non-operated net acres. Triangle is planning to sell this acreage in the most effective manner by assessing new industry activity and overall direct acreage sales. In June 2008, Triangle and the operator of the lands entered into agreements with Tristone Capital to market the property. In November 2008, the Corporation sold 530 gross acres (265 net acres) of undeveloped acreage in the Fayetteville Shale of the Arkoma Basin in Arkansas for gross proceeds of $222,466. The sale of the remaining acreage is expected to be concluded before the end of 2008.

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

Triangle drilled initial test wells in Colorado and Wyoming in 2006 and 2007 that were not successful in the primary targets. In June 2008, Triangle sold its third prospect in this project, located in Northern Montana, consisting of 9,692 net acres of land, for proceeds of approximately $800,000.

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

In fiscal 2009, there is no exploration activity planned on this project. At the beginning of the year, Triangle had six low working interest shale gas wells pipeline connected (5.75%-15% working interest), of which four were producing. The operator of two of the six wells commenced voluntary bankruptcy proceedings in the prior year. During 2008, through the trustee, Triangle sold its interest in the two wells in an auction of the operator's assets for proceeds of approximately $165,000. As such, Triangle currently has four low working interest shale gas wells pipeline connected (11%-15% working interest), of which one well is currently producing.

Work Program & Budget

The Corporation intends to pursue its core projects in the Province of Nova Scotia pursuant to a work program and budget pertaining to certain acreage interests in the Windsor Block of Nova Scotia as of September 15, 2008. The work program and budget covers an 18-month period from the third quarter of 2008 to the fourth quarter of 2009, inclusive. It estimates gross expenditures of Cdn$47.5 million (Cdn$14.0 million net). The work program budget assumes that Zodiac will fund 50% of drilling costs up to $15 million gross ($7.5 million net to Zodiac) to earn a 12.5% interest in the Windsor Block and that Zodiac will exercise its option to earn an additional 12.5% interest in the Windsor Block by funding an additional $7.5 million net to Zodiac costs as per the terms of the Zodiac Joint Venture Agreement. Details of the Zodiac Joint Venture Agreement may be found in this prospectus under the headings "Principal Properties" and "Liquidity and Capital Resources".

The work program and budget prepared by Triangle was submitted to Ryder Scott for its evaluation. The evaluation is contained within the Ryder Scott Work Program Report. Pursuant to the Ryder Scott Work Program Report, it is the opinion of Ryder Scott that the terms and conditions of the Windsor Block Farm-in Agreement are reasonable and consistent with normal industry practice and that the Windsor Block project represents a legitimate shale gas exploration play. It is also the opinion of Ryder Scott that Triangle's proposed work program is a reasonable and prudent shale gas exploration program and that the individual items listed in Triangle's work program are consistent with normal industry practice when undertaking shale gas exploration in Canada. Furthermore, in Ryder Scott's opinion, Triangle's budget is a reasonable estimate of the costs to undertake the proposed work program. Ryder Scott notes that Triangle's project is in an early stage and the proposed work program and budget may be modified as a result of information obtained during the proposed exploration and development program. Ryder Scott emphasises that no commercial hydrocarbons have been discovered to date on the Windsor Block and there is no assurance that any commercial hydrocarbons will be discovered as a result of Triangle's proposed exploration activities.

The Corporation intends to use its working capital as described in the table below. However, there may be circumstances where, for sound business reasons, a reallocation of the funds may be necessary. In particular, the Corporation has identified six other locations in the Kennetcook area which, in the opinion of Ryder Scott, are equally viable to the locations proposed in the table below, and therefore substitutions or additions may occur.

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The work program, including the wells in Avon and Stanley, satisfies the requirements of a 10-well commitment made to the Nova Scotia Department of Energy in support of a production agreement and land tenure application submitted June 24, 2008. The 10 locations must be drilled prior to the end of 2011. Four locations must be drilled in Kennetcook prior to the end of 2009, which is satisfied by the 2008 portion of the work program, and two wells in each of Avon, Stanley and Wolfville, which requirements are partially satisfied by this work program, with the balance to be completed in 2010 and 2011.

Forward looking statements contained in this section are intended to reflect Management's current beliefs and assumptions regarding the Corporation's intended work program and budget, and use of this information for other purposes may not be appropriate. Actual results may vary from the forward-looking information contained in this section. Specific risk factors related to the work program and budget include geological, technical, drilling or processing problems relating to the work planned, increases in capital expenditure costs, and uncertainties associated with additional funding requirements of the Corporation in the future. The following table contains forward looking information about budgeted cash flows that are based on certain assumptions that include, but are not limited to, successful drilling and completions results, the ability to supplement the Corporation's working capital by completing equity or debt financings and selling non-core assets, continued funding from work program partners, Zodiac exercising its option under the Zodiac Joint Venture Agreement to earn an additional 12.5% working interest by paying 50% of the second $15 million in gross costs, and the availability of drilling and completion equipment.

These statements also involve other significant known and unknown risks and uncertainties, including those referred to under the headings "Forward Looking Statements" and "Risk Factors" in this prospectus, and should be read in conjunction with those sections. All references to "$" in the following table are to Canadian dollars.

Triangle Work Program and Budget
Timing of Expenditures	Exploration & Development Activity		Gross Cost  ($000's)		Triangle Net Cost  ($000's)			Cost Per Quarter  ($000's)
								Gross		Triangle Net
Q3 2008		Drill & case Kennetcook #3		3,000		600	(1)
		Drill & case Stanley #1		3,000		600	(1)		6,000		1,200
Q4 2008		Drill & case Kennetcook #4		3,000		600	(1)
		Complete Kennetcook #3		3,000		600	(1)
		Complete Stanley #1		3,000		600	(1)		9,000		1,800
Q1 2009		Complete Kennetcook #4		3,000		600	(2)
		Drill & case Kennetcook #5		4,000		800	(2)
		Complete Kennetcook #5		3,500		700	(2)		10,500		2,100
Q2 2009		Drill & case Kennetcook #6		2,000		400	(2)
		Complete Kennetcook #6		2,000		400	(2)		4,000		800
Q3 2009		Drill & case Kennetcook #7		3,000		1,350	(3)
		Complete Kennetcook #7		3,000		1,350	(3)
		Drill & case Avon #1		3,000		1,350	(3)
		Complete Avon #1		3,000		1,350	(3)		12,000		5,400
Q4 2009		Drill & case Stanley #2 delineation well		3,000		1,350	(3)
		Complete Stanley #2 delineation well		3,000		1,350	(3)		6,000		2,700
		Total Budget Expenditures	$	47,500	$	14,000

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Notes:

(1) Assumes Triangle pays 20%, Zodiac pays 50%, and Contact pays 30%.

(2) Assumes Triangle pays 20%, Zodiac elects to pay 50% to earn an additional 12.5% working interest, and Contact pays 30%.

(3) Assumes Triangle pays 45%, Zodiac pays 25%, and Contact pays 30%.

While the Corporation intends to use its working capital as described in the work program and budget, the Corporation's current working capital is not sufficient to complete the work program. Triangle intends to complete the wells listed in the work program and budget, based on its own past experience in the area, and employing best practices of other operators in the industry working in similar basins. Completions are expected to consist of perforating, fracture treating, and multi-day flow-testing several distinct geological intervals within each well. Depending on geological interpretation, it is expected that two to four intervals may be completed in any given vertical well. Horizontal wells may contain up to five separate completion intervals. Size and number of fracture treatments will depend on geologic and rock mechanics data received as the wells are drilled and logged. Perforation intervals are expected to be 1 to 10 metres thick, within overall prospective shale intervals that may be on the order of 100 metres thick. Fracture stimulation, likely using slick water and sand proppant, will be undertaken in virtually all cases. The size of fracture is expected to be between 10 and 100 tonnes per perforated interval. Industry best practices will be continually reviewed and employed if applicable. The expected completion program cost estimated in the work program and budget includes these estimates and assumptions.

AVAILABLE FUNDS

As at July 31, 2008, the Corporation had working capital of approximately $10,623,175. These funds are adequate for the Corporation's general and administrative costs for the following 12 month period, as well as for debt servicing during this period. The working capital available for the work program is set out below.

Working Capital Available for Work Program
Working Capital as at July 31, 2008				$	10,623,175
12-months general & administrative costs (August 1, 2008 - July 31, 2009)
Salary and employee benefits	$	1,660,000
Office		850,000
Professional fees		350,000
Public company costs		460,000
Overhead recoveries		(220,000	)
Total general and administrative costs(1)	$	3,100,000		$	(3,100,000	)
Unamortized convertible debenture discount(2)				$	(2,037,931	)
Interest payable on convertible debentures (August 1, 2008 - July 31, 2009)				$	(750,000	)
Working capital available for work program				$	4,735,244

Notes:

(1) Total general and administrative costs for the first six months of fiscal 2009 were $2,343,402, which included non-cash stock based compensation of $341,036. During the second quarter of fiscal 2009, Triangle implemented the following cost reductions on an annual basis: (a) reduced staff bonuses to nil, which is anticipated to result in a $200,000 reduction; (b) reduced travel to the U.S. (as a result of assets located in the U.S. being deemed non-core), which is anticipated to result in a $50,000 reduction; (c) reduced investor relation expenditures, which is anticipated to result in a $200,000 reduction; and (d) increased operating overhead recoveries by $150,000 related to the anticipated increased operated drilling and completion activity. In addition, the total general and administrative costs forecast above do not reflect non-recurring audit, legal and accounting fees of approximately $275,000 related to the restatement of Triangle's financial statements in fiscal 2008. Public company costs consist mainly of fees for investor relations and also include directors' fees, press release and SEC filing costs, printing costs and transfer agent fees.

(2) At July 31, 2008, the convertible debentures were recorded at their amortized cost of $7,962,069. The face value of the debentures at maturity on June 1, 2009 is $10 million.

The Corporation's working capital is sufficient to fund the drilling and completion of the Kennetcook #3, the Kennetcook #4 and the Stanley #1 wells. However, the current working capital is not sufficient to complete the entire work program described under "Principal Properties - Work Program & Budget".

10

The Corporation expects to increase its working capital by the sale of non-core assets located in the U.S. and by the completion of one or more equity or debt financings, if the terms are appropriate. Other alternatives to increase working capital include bringing in an industry partner or partners on a farm-in basis to assume some or all of Triangle's capital program in exchange for an earned working interest in the lands.

While the Corporation intends to use its working capital as described above, there may be circumstances where, for sound business reasons, a reallocation of working capital may be necessary. Specifically, expenditures under the work program contemplated to occur after July 1, 2009 are contingent on success during the first 12 months of the work program. The actual amount that the Corporation spends in connection with each of the intended uses may vary significantly from the amounts specified, and will depend on a number of factors. Specific risk factors related to the projections of working capital detailed above include increases in the Corporation's capital expenditure costs, the quantum of, and future net revenues from, the Corporation's reserves, and the Corporation's future operating and financial results. Other significant known and unknown risks and uncertainties include those referred to under the headings "Forward Looking Statements" and "Risk Factors" in this prospectus, and the forward looking information above should be read in conjunction with that section.

DISCLOSURE OF RESERVES DATA

The following is a summary of the Corporation's remaining natural gas and natural gas liquids reserves, and the estimated value of the Corporation's share of future net revenue as at July 1, 2008 as evaluated by Ryder Scott. The Ryder Scott Reserves Report was prepared in accordance with the standards contained in the COGE Handbook and the reserves definitions are those contained in National Instrument 51-101 and the COGE Handbook. The pricing used in the forecast is set forth in the notes to the tables.

The evaluation of future gross revenue in the Ryder Scott Reserves Report is after deduction of royalties and inclusion of gas cost allowance where applicable. Deductions are comprised of normal direct costs of operating wells, recompletion costs, development costs, and certain abandonment costs net of salvage. Future net revenue is before deduction of provincial or state and federal income taxes and general and administrative expenses, unless otherwise shown. Estimates of future income taxes were based on tax pools provided by the Corporation and tax rates currently in effect. The Corporation informed Ryder Scott that it is in a non-taxable position and has sufficient tax pools to remain non-taxable beyond the life of the properties included in the Ryder Scott Reserves Report. The estimated future net revenue contained in the following table does not necessarily represent the fair market value of the Corporation's reserves. There is no assurance that the forecast price and cost assumptions contained in the Ryder Scott Reserves Report will be attained and variances could be material. Other assumptions and qualifications relating to costs and other matters are included in the Ryder Scott Reserves Report. The recovery and reserves estimates on the Corporation's properties described herein are estimates only. The actual reserves on the Corporation's properties may be greater or less than those calculated.

11

SUMMARY OF RESERVES

as of July 1, 2008

FORECAST PRICES AND COSTS

	Natural Gas				Natural Gas Liquids
	Gross  (mmcf)		Net  (mmcf)		Gross  (bbls)		Net  (bbls)
Canada
Proved
Developed Producing		129		94		2,790		2,123
Developed Non-Producing		0		0		0		0
Undeveloped		0		0		0		0
Total Proved		129		94		2,790		2,123
Total Probable		43		34		1,079		825
Total Proved plus Probable		172		128		3,869		2,948
United States
Proved
Developed Producing		33		25		0		0
Developed Non-Producing		0		0		0		0
Undeveloped		0		0		0		0
Total Proved		33		25		0		0
Total Probable		35		26		0		0
Total Proved plus Probable		68		51		0		0
Aggregate (Canada + USA)
Proved
Developed Producing		162		119		2,790		2,123
Developed Non-Producing		0		0		0		0
Undeveloped		0		0		0		0
Total Proved		162		119		2,790		2,123
Total Probable		78		60		1,079		825
Total Proved plus Probable		240		179		3,869		2,948

12

NET PRESENT VALUES OF FUTURE NET REVENUE

as of July 1, 2008

FORECAST PRICES AND COSTS (CDN $)

	Before Income Taxes  Discounted At (%/year) ($000's)										After Income Taxes  Discounted At (%/year) ($000's)										Unit Value Before Income Tax Discounted At (10%/year) ($000's)
($000's)	0%		5%		10%		15%		20%		0%		5%		10%		15%		20%		($/mmcf)		($/bbl)
Canada
Proved Developed Producing		542		493		451		415		385		542		493		451		415		385		4,264		23.70
Proved Developed Non- Producing		0		0		0		0		0		0		0		0		0		0		-		-
Proved Undeveloped		0		0		0		0		0		0		0		0		0		0		-		-
Total Proved		542		493		451		415		385		542		493		451		415		385		4,264		23.70
Total Probable		128		86		60		43		32		128		86		60		43		32		1,464		11.01
Total Proved Plus Probable		670		579		511		458		417		670		579		511		458		417		3,555		20.88
United States
Proved Developed Producing		113		108		104		100		96		113		108		104		100		96		4,154		-
Proved Developed Non- Producing		0		0		0		0		0		0		0		0		0		0		-		-
Proved Undeveloped		0		0		0		0		0		0		0		0		0		0		-		-
Total Proved		113		108		104		100		96		113		108		104		100		96		4,154		-
Total Probable		138		122		108		96		86		138		122		108		96		86		4,152		-
Total Proved Plus Probable		251		230		212		196		182		251		230		212		196		182		4,153		-
Aggregate (Canada + USA)
Proved Developed Producing		656		602		555		515		480		656		602		555		515		480		4,234		24.11
Proved Developed Non- Producing		0				0		0		0		0				0		0		0		-		-
Proved Undeveloped		0		0		0		0		0		0		0		0		0		0		-		-
Total Proved		656		602		555		515		480		656		602		555		515		480		4,234		24.11
Total Probable		266		208		168		139		118		266		208		168		139		118		2,683		11.80
Total Proved Plus Probable		922		810		723		644		598		922		810		723		644		598		3,690		21.10

* Note: numbers may not add due to significant figure differences when rounding.

13

TOTAL FUTURE NET REVENUE

(UNDISCOUNTED)

as of July 1, 2008

FORECAST PRICES AND COSTS (CDN $)

($000's)	Revenue		Royalties		Operating Costs		Development Costs		Abandonment and Reclamation Costs		Future Net Revenue Before Income Taxes		Income Taxes		Future Net Revenue After Income Taxes
Canada
Total Proved		1,479		366		526		0		44		543		0		543
Total Probable		481		96		256		0		2		128		0		128
Total Proved Plus Probable		1,960		462		781		0		46		671		0		671
United States								0
Total Proved		269		27		121		0		8		113		0		113
Total Probable		260		26		95		0		1		138		0		138
Total Proved Plus Probable		529		53		216		0		9		251		0		251
Aggregate (Canada + USA)								0
Total Proved		1,748		393		647		0		52		656		0		656
Total Probable		741		122		351		0		2		266		0		266
Total Proved Plus Probable		2,489		515		998		0		54		922		0		922

* Note: numbers may not add due to significant figure differences when rounding.

14

FUTURE NET REVENUE

BY PRODUCTION GROUP

as of July 1, 2008

FORECAST PRICES AND COSTS (CDN $)

	Production Group		Future Net Revenue  Before Income Taxes  (Discounted at 10%/Year)  ($000's)		Unit Value  (Cdn$)
Canada
Total Proved		Natural Gas		401	$	4.26 /mcf
		Natural Gas Liquids		50	$	23.70 /bbl
		Total:		451
Total Probable		Natural Gas		50	$	1.46 /mcf
		Natural Gas Liquids		10	$	11.01 /bbl
		Total:		60
Total Proved Plus Probable		Natural Gas		451	$	3.55 /mcf
		Natural Gas Liquids		60	$	20.88 /bbl
		Total:		511
United States
Total Proved		Natural Gas		104	$	4.15 /mcf
		Natural Gas Liquids		-		-
		Total:		104
Total Probable		Natural Gas		108	$	4.15 /mcf
		Natural Gas Liquids		-		-
		Total:		108
Total Proved Plus Probable		Natural Gas		212	$	4.15 /mcf
		Natural Gas Liquids		-		-
		Total:		212
Aggregate (Canada + USA)
Total Proved		Natural Gas		505	$	4.23 /mcf
		Natural Gas Liquids		50	$	24.11 /bbl
		Total:		555
Total Probable		Natural Gas		158	$	2.68 /mcf
		Natural Gas Liquids		10	$	11.80 /bbl
		Total:		168
Total Proved Plus Probable		Natural Gas		663	$	3.69 /mcf
		Natural Gas Liquids		60	$	21.20 /bbl
		Total:		723

15

Exemptions from Prospectus Form Requirements

No reconciliation of changes in reserves has been provided in this prospectus, as the Corporation significantly refocused its core exploration areas by entering into the Windsor and Beech Hill Farm-In Agreements, and by beginning exploration in the Windsor Block. Relief from the requirement to include a reconciliation, set out in item 4.1 of Form 51-101F1 required pursuant to NI 51-101, will be evidenced through the issuance of a final receipt for the prospectus.

The reserves disclosure in this prospectus is at July 1, 2008. Relief from the requirement to include reserves disclosure as at the end of the most recent financial year (January 31, 2008), set out in item 5.5 of Form 41-101F1 required pursuant to NI 41-101, will be evidenced through the issuance of a final receipt for the prospectus.

Other Material Information

The Corporation's properties on which reserves have been assigned have been designated by Management as non-core due to the Corporation's desire to focus its limited man-power resources on one core project (being the Maritimes Basin in Nova Scotia and New Brunswick) and one secondary project (being a potential shale gas project in Western Canada).

Significant Factors or Uncertainties

Natural gas and oil exploration involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that expenditures by Triangle will result in new discoveries of oil, natural gas or NGLs in commercial quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the increasing demand for drilling rigs, supplies and services; the inherent uncertainties of drilling in unknown formations; the costs associated with encountering various drilling conditions such as over pressured zones; tools lost in the hole; changes in joint venture participants, farmors and joint venture partners; and changes in drilling plans.

Natural gas and oil prices are determined based on world demand, supply and other factors, all of which are beyond the control of Triangle. World prices for natural gas and oil have fluctuated widely in recent years. Any material decline in prices could result in a reduction of net production revenue. Certain wells or other projects may become uneconomic as a result of a decline in world oil prices and natural gas prices, leading to a reduction in the value of Triangle's natural gas and oil reserves. Triangle may also elect not to produce from certain wells at lower prices.

If Triangle's revenues or reserves decline, Triangle may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or equity financing or cash generated from operations will be available or sufficient to meet these requirements or for other corporate purposes or if debt or equity financing is available, that it will be on terms acceptable to Triangle.

Triangle actively competes for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel with a substantial number of other natural gas and oil companies, many of which have significantly greater financial resources than Triangle. Competitors include major integrated natural gas and oil companies and numerous other independent natural gas and oil companies and individual producers and operators.

To the extent that Triangle is not the operator of its natural gas and oil properties, Triangle will be dependent on such operators for the timing of activities related to such properties and will largely be unable to direct or control the activities of the operators.

Future Development Costs

The Corporation is not expecting to incur any future development costs with respect to its Canadian and U.S. assets.

16

Natural Gas Wells

The following table sets forth the number of producing and non-producing natural gas wells, which are located in Canada and the United States, in which the Corporation held a working interest as at July 1, 2008:

			Natural Gas Wells
	Location		Gross(1)		Net(2)
Canada
Producing		Alberta		2		0.51
Non-Producing(3)		(N/A)		0		0
United States
Producing		Texas		1		0.14
Non-Producing(3)		Texas		1		0.14
Total Producing				3		0.65
Total Non-Producing(3)				1		0.14

Notes:

(1) "Gross" means the total number of wells in which Triangle has an interest or a right to earn an interest.

(2) "Net" means Triangle's interest in the wells after deducting the working interests of all other parties.

(3) "Non-Producing Wells" are non-producing wells that are capable of production.

Properties with No Attributed Reserves

The following table sets out the Corporation's developed and undeveloped land position with no attributed reserves effective July 1, 2008:

Property	Location (Province or State)	Developed Acreage				Undeveloped Acreage
		Gross(1)		Net(2)		Gross(1)			Net(2)
Canada
Deep Basin	Alberta		5,120		1,420		18,240			3,656
Beech Hill	New Brunswick		-		-		68,000			47,600
Windsor	Nova Scotia		1,920		1,344		514,080			359,856
United States
Fayetteville	Arkansas		640		320		20,234	(3)		10,117	(3)
Barnett	Texas		478		61		-			-
Rocky Mountains	Colorado		640		160		18,347			4,587
Rocky Mountains	Wyoming		640		160		16,667			4,167

Notes:

(1) "Gross" means the total number of acres in which Triangle has a working interest or a right to earn an interest.

(2) "Net" means the sum of the products obtained by multiplying the number of gross acres by Triangle's percentage working interest therein.

(3) In November 2008, the Corporation sold 530 gross acres (265 net acres) of undeveloped acreage in the Fayetteville Shale. It currently holds 19,704 gross acres (9,852 net acres) of undeveloped acreage in the area.

The Windsor Block is covered by an exploration agreement with the Nova Scotia government, originally issued in 1999, which was due to expire on September 15, 2008, and has now been extended by the Nova Scotia Department of Energy an additional 180 days. Triangle is working with the Nova Scotia government to convert the exploration agreement into a production agreement. Triangle submitted a development plan application in mid June 2008, which triggered an automatic six month extension of the exploration agreement while the Nova Scotia government reviews the application. If the production agreement is not granted, Triangle's right to explore for and develop oil and gas on this block would be forfeited.

17

Additional Information Concerning Abandonment and Reclamation Costs

As at July 1, 2008, Triangle expected to incur abandonment costs in respect of 3 gross (0.65 net) producing wells located on its properties. Ryder Scott estimates the cost to abandon all its producing wells to be Cdn $54,524. Estimated well abandonment and disconnect costs are based on discussions with Triangle and AEUB Directive 011 effective January 1, 2008. Each region was assigned an average cost per well to abandon the wells in that area. The first abandonment costs will not occur until approximately 2021 on producing wells.

The following table sets forth information respecting total proved and probable future abandonment costs (net of estimated salvage values) for wells, which are expected to be incurred for the periods indicated in respect of Triangle's properties and assets.

	Total Proved and Probable Abandonment and Reclamation Costs Undiscounted Using Forecast Prices and Costs (Cdn $'s)		Total Proved and Probable Abandonment and Reclamation Costs Discounted at 10% Using Forecast Prices and Costs (Cdn $'s)
2008		0		0
2009		0		0
2010		0		0
2011		0		0
2012		0		0
2013		0		0
2014		0		0
2015		25,031		12,891
2016		0		0
2017		8,808		3,745
2018		0		0
2019		0		0
2020		0		0
2021		20,685		2,912
Total:		54,524		19,547

The Corporation will be liable for its share of ongoing environmental obligations and for the ultimate reclamation of the properties held by it upon abandonment. Ongoing environmental obligations are expected to be funded out of cash flow.

Costs Incurred

The following table summarizes the estimated capital expenditures made by the Corporation on its natural gas properties for the most recent fiscal year ended January 31, 2008:

	Property Acquisition Costs (Cdn $000's)
	Proved Properties		Unproved Properties		Exploration Costs (Cdn $000's)		Development Costs (Cdn $000's)		Facilities (Cdn $000's)
Canada		0		0		15,737		0		308
United States		0		1,427		6,050		807		0

18

Exploration and Development Activities

The following table sets forth the number of exploration wells and development wells that the Corporation has drilled or has participated in drilling during the most recent fiscal year ended January 31, 2008:

					Number completed as:
	Gross(1)		Net(2)		oil, gas		service wells		dry holes
Canada
Exploratory Wells (3)		2		1.40		1.40		0		0
Development Wells (4)		0		0		0		0		0
United States
Exploratory Wells (3)		1		0.25		0		0		0.25
Development Wells (4)		0		0		0		0		0
Total Wells		3		1.65		1.40		0		0.25

Notes:

(1) "Gross" means the total number of wells in which Triangle has an interest or a right to earn an interest.

(2) "Net" means Triangle's interest in the wells after deducting the working interests of all other parties.

(3) "Exploratory Well" is a well that is not a development well, a service well or a stratigraphic test well.

(4) "Development Well" is a well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

The Corporation intends to pursue its core projects in the provinces of Nova Scotia and New Brunswick pursuant to a work program and budget pertaining to certain acreage interests in the Windsor Block of Nova Scotia as of August 1, 2008. The work program and budget covers an 18-month period from the third quarter of 2008 to the fourth quarter of 2009, inclusive. The work program, including the wells in Avon and Stanley, satisfies the requirements of a 10-well commitment made to the Nova Scotia Department of Energy in support of a production agreement and land tenure application submitted June 24, 2008. The 10 locations must be drilled prior to the end of 2011. Four locations must be drilled in Kennetcook prior to the end of 2009, which is satisfied by the 2008 portion of the work program, and two wells in each of Avon, Stanley and Wolfville, which requirements are partially satisfied by this work program, with the balance to be completed in 2010 and 2011.

Production Estimates

The following table sets forth, by product type, the volume of production estimated for 2008 reflected in the estimates of future net revenue using forecast prices:

	Natural Gas (mmcf)		Natural Gas Liquids (bbls)
Canada
Gross Proved Reserves		17		437
Gross Probable Reserves		0		0
United States
Gross Proved Reserves		6		0
Gross Probable Reserves		1		0
Aggregate (Canada + USA)
Gross Proved Reserves		23		437
Gross Probable Reserves		1		0

19

Production History

The following table sets forth the Corporation's share of average daily production volume (working interest before royalties), for the each quarter of the fiscal year ended January 31, 2008:

	Q1										Q2
	Volume (mcf/d) (bbls/d)		Average Price (Cdn $/mcf) (Cdn $/bbl)		Royalties Paid (Cdn $/mcf) (Cdn $/bbl)		Production Costs (Cdn $)		Resulting Netback (Cdn $)		Volume (mcf/d) (bbls/d)		Average Price (Cdn $/mcf) (Cdn $/bbl)		Royalties Paid (Cdn $/mcf) (Cdn $/bbl)			Production Costs (Cdn $)		Resulting Netback (Cdn $)
Canada
Natural Gas		55		6.53		1.97		0.18		4.38		75.27		7.10		(0.28	)		3.24		4.14
Natural Gas Liquids		-		-		-		-		-		5.29		30.22		-			-		30.22
USA
Natural Gas		113		6.30		1.79		0.14		4.37		129.32		6.76		1.82			4.12		0.82
Natural Gas Liquids		-		-		-		-		-		-		-		-			-		-

	Q3										Q4
	Volume (mcf/d) (bbls/d)		Average Price (Cdn $/mcf) (Cdn $/bbl)		Royalties Paid (Cdn $/mcf) (Cdn $/bbl)		ProductionCosts (Cdn $)		Resulting Netback (Cdn $)		Volume (mcf/d) (bbls/d)		Average Price (Cdn $/mcf) (Cdn $/bbl)		Royalties Paid (Cdn $/mcf) (Cdn $/bbl)			Production Costs (Cdn $)		Resulting Netback (Cdn $)
Canada
Natural Gas		248		5.86		2.54		1.76		1.57		158.08		6.24		(0.84	)		1.89		5.19
Natural Gas Liquids		3		41.06		38.13		-		2.93		3.71		65.72		12.22			-		53.50
USA
Natural Gas		334		5.38		1.63		3.46		0.29		128.26		10.30		3.27			4.89		2.13
Natural Gas Liquids		-		-		-		-		-		-		-		-			-		-

20

			2007 Production
	Volume (mcf/d) (bbls/d)		Average Price (Cdn $/mcf) (Cdn $/bbl)		Royalties Paid (Cdn $/mcf) (Cdn $/bbl)		Production Costs (Cdn $)		Resulting Netback (Cdn $)
Canada
Natural Gas		134		6.21		1.09		1.85		3.28
Natural Gas Liquids		3		43.93		12.42		-		31.51
USA
Natural Gas		177		6.67		1.99		3.32		1.36
Natural Gas Liquids		-		-		-		-		-
Aggregate total (Canada + USA)
Natural Gas		311		6.47		1.60		2.68		2.19
Natural Gas Liquids		3		43.93		12.42		-		31.51
Natural Gas + NGL		329 mmcfe/d		Cdn $6.52/mmcfe		Cdn $1.63/mmcfe		Cdn $2.54/mmcfe		Cdn $2.35/mmcfe

Notes:

The following notes are applicable to all tables in the Disclosure of Reserves Data section of this prospectus:

(1) "Gross Reserves" are the Corporation's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Corporation. "Net Reserves" are the Corporation's working interest (operating or non-operating) share after deduction of royalty obligations, plus the Corporation's royalty interests in reserves.

(2) "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

(3) "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

(4) "Possible" reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

(5) "Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.

(6) "Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

(7) "Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.

(8) "Undeveloped" reserves are those reserves expected to be recovered from know accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

(9) The pricing assumptions used in the Ryder Scott Reserves Report with respect to net values of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth below.

21

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS

USED IN THE RYDER SCOTT RESERVES REPORT

as of July 1, 2008-08-25

FORECAST PRICES AND COSTS (CDN $)

	WTI @ Cushing		Natural Gas Liquids @ Henry Hub		Exchange Rate		Inflation Rate
Year	U.S.$/bbl		U.S.$/mmBtu		$U.S./$Cdn		%/year
1998		14.39		2.08		0.677
1999		19.18		2.27		0.672
2000		30.30		4.23		0.674
2001		25.92		4.07		0.648
2002		26.10		3.33		0.637
2003		31.14		5.63		0.710
2004		41.46		5.85		0.768
2005		56.47		8.79		0.824
2006		66.11		6.76		0.885
2007		72.31		6.95		0.931
2008		110.94		9.95		0.997
2008		134.00		12.50		1.000		2.00
2009		124.00		11.50		1.000		4.00
2010		110.00		10.50		1.000		4.00
2011		100.00		9.50		1.000		3.50
2012		95.00		9.50		1.000		3.00
2013		95.00		9.50		1.000		2.50
2014		95.00		9.50		1.000		2.00
2015		96.90		9.69		1.000		2.00
2016		98.84		9.88		1.000		2.00
2017		100.81		10.08		1.000		2.00
2018		102.83		10.28		1.000		2.00
2019		104.89		10.49		1.000		2.00
2020		106.99		10.70		1.000		2.00
2021		109.13		10.91		1.000		2.00
2022		111.31		11.13		1.000		2.00
2023		113.53		11.35		1.000		2.00
2024+	No Further Escalation

22

SELECTED CONSOLIDATED FINANCIAL INFORMATION

Annual Information of Triangle

The following is a summary of selected financial information of Triangle as at and for the fiscal years ended January 31, 2008, January 31, 2007 and January 31, 2006. This information has been derived from Triangle's audited financial statements appearing elsewhere in this prospectus. This summary financial information should be read in conjunction with the audited financial statements of the Corporation and the notes thereto together with the discussion under the heading "Management's Discussion and Analysis of Triangle" included elsewhere in this prospectus. All references to "$" are to U.S. dollars.

	Fiscal Year ended January 31, 2008 ($)			Fiscal Year ended January 31, 2007 ($)			Fiscal Year ended January 31, 2006 ($)
Revenue, net of royalties		586,804			54,342			-
Net income (loss)		(29,600,747	)		(4,281,969	)		3,355,132
Total operating expenses		26,503,535			9,525,047			5,062,717
Oil and gas properties		24,978,949			21,101,495			7,065,367
Total assets		32,579,190			30,747,272			25,838,569
Total liabilities		22,520,504			35,851,564			36,586,246
Working capital deficit		(7,678,143	)		(16,326,960	)		(14,062,142	)
Total shareholders' equity (deficit)		10,058,686			(5,104,292	)		(10,747,677	)
Basic income (loss) per share		(0.80	)		(0.21	)		0.13
Diluted income (loss) per share		(0.80	)		(0.21	)		0.12

Quarterly Information of Triangle

The following is a summary of selected financial information of Triangle as at and for the six months ended July 31, 2008 and July 31, 2007. This information has been derived from Triangle's unaudited financial statements appearing elsewhere in this prospectus. This summary financial information should be read in conjunction with the unaudited and audited financial statements of the Corporation and the notes thereto together with the discussion under the heading "Management's Discussion and Analysis of Triangle" included elsewhere in this prospectus. All references to "$" are to U.S. dollars.

	Six months ended July 31, 2008 ($)			Six months ended July 31, 2007 ($)
Revenue, net of royalties		259,950			196,226
Net loss		(4,213,248	)		(9,305,984	)
Total operating expenses		2,533,981			7,921,655
Oil and gas properties		22,273,219			24,364,524
Total assets		47,294,130			43,540,355
Total liabilities		14,429,697			29,798,830
Working capital		10,623,175			1,304,128
Total shareholders' equity		32,864,733			14,041,525
Basic and diluted loss per share		(0.08	)		(0.28	)

Dividends

On May 9, 2005, the Corporation declared a stock dividend of six Common Shares for each one Common Share outstanding. The Corporation has not declared or paid any dividends on its Common Shares since changing its principal business to that of acquisition and exploration of oil and gas resource properties. The Corporation does not anticipate paying any cash dividends to Shareholders 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 the financial condition, results of operations and capital requirements of the Corporation, and such other factors as the Board of Directors deem relevant.

23

U.S. GAAP

The preparation of financial statements in conformity with U.S. generally accepted accounting principles, which may differ from Canadian generally accepted accounting principles, requires the Corporation to make estimates and judgements that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, the Corporation evaluates the application of these estimates, including those related to the recoverability of investments, product development costs, revenue recognition and deferred revenue and accounting for income taxes. The Corporation bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgements about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual amounts could differ significantly from these estimates.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF TRIANGLE

The following discussion and analysis has been prepared in accordance with Item 303 of Regulation S-K under the 1934 Act and should be read in conjunction with the financial statements of Triangle included in this prospectus.

Six months ended July 31, 2008 compared to six months ended July 31, 2007

Results of Operations

Daily Sales Volumes, Working Interest before royalties

		Three Months Ended July 31, 2008		Three Months Ended July 31, 2007		Six Months Ended July 31, 2008		Six Months Ended July 31, 2007
Barnett Shale in Texas, USA	mcf/d		35		148		70		130
Deep Basin in Alberta, Canada	mcf/d		100		136		122		86
Total Company	mcf/d		135		284		192		216
Total Company	boe/d		23		47		32		36

Net Operating Results

		Three Months Ended July 31, 2008		Three Months Ended July 31, 2007		Six Months Ended July 31, 2008		Six Months Ended July 31, 2007
Volumes	mcf		12,250		26,025		34,905		39,090
Price	$/mcf		10.53		5.54		9.05		6.16
Revenue		$	128,939	$	144,297	$	315,962	$	240,941
Royalties			21,108		19,661		56,012		47,715
Revenue, net of royalties			107,831		124,636		259,950		193,226
Production expenses			4,154		71,493		63,381		73,802
Net		$	103,677	$	53,143	$	196,569	$	119,424

For the three and six month periods ended July 31, 2008, the Corporation realized $128,939 and $315,962, respectively, in revenue from sales of natural gas and natural gas liquids, as compared to $144,297 and $240,941 in the same periods in 2007. Revenue increased mainly due to higher prices, offset by reduced production volumes since the Corporation sold two Barnett Shale wells. Royalties related to this revenue totalled $21,108 and $56,012 (16% and 18% of revenue) for the three month and six month periods ended July 31, 2008, respectively, compared to 14% and 20% in the same periods in 2007. Production expenses related to this revenue totalled $4,154 and $63,381 ($2.03/Boe and $10.89/Boe) for the three and six month periods ended July 31, 2008, respectively, compared to $16.48/Boe and $11.32/Boe in the same periods in 2007. Production costs are reported as $2.08/Boe for Q2 - 2009 as they were over-accrued in Q1 - 2009 relating to the two Barnett region wells that were sold.

24

Depletion, Depreciation and Accretion ("DD&A")

	Three Months Ended July 31, 2008		Three Months Ended July 31, 2007		Six Months Ended July 31, 2008		Six Months Ended July 31, 2007
DD&A – oil and gas properties	$	13,557	$	107,678	$	51,028	$	181,822
Accretion		9,711		28,043		42,539		29,367
Depletion and Accretion		23,268		135,721		93,567		211,189
Depreciation – property and equipment		9,988		14,834		19,747		21,614
Total	$	33,256	$	150,555	$	113,314	$	232,803
Depletion per Boe	$	6.64	$	24.82	$	8.77	$	27.91

Unproven property costs of $22,482,988 were excluded from costs subject to depletion at July 31, 2008. Depletion expense related to oil and as properties decreased in the three and six months periods ended July 31, 2008 compared to the same periods in 2007 primarily as a result of the U.S. properties having no depletion starting in the second quarter of fiscal 2009 as proved property costs were nil.

General and Administrative ("G&A")

	Three Months Ended July 31, 2008			Three Months Ended July 31, 2007			Six Months Ended July 31, 2008			Six Months Ended July 31, 2007
Salaries, benefits and consulting fees	$	548,143		$	352,454		$	941,005		$	638,696
Office costs		201,609			210,400			467,592			463,600
Professional fees		23,542			97,776			296,946			146,117
Public company costs		172,122			143,919			329,001			204,589
Operating overhead recoveries		(30,488	)		(1,220	)		(32,178	)		(42,715	)
Stock-based compensation		227,756			528,078			341,036			2,153,614
G&A	$	1,142,684		$	1,331,407		$	2,343,402		$	3,563,901

General and administrative expenses have decreased in the three and six month periods ended July 31, 2008 compared to the same periods in 2007 primarily due to decreased stock-based compensation expense mainly as a result of shares issued to its executives that have now been fully expensed. Salaries, wages and consulting fees increased in the three and six month periods ended July 31, 2008 compared to the same periods in 2007 due to increased staff and the payment of bonuses to employees in July 2008. Professional fees and public company costs increased in the six month period ended July 31, 2008 compared to the same period in 2007 due to increased year-end audit and reserve evaluation fees, increased audit and accounting fees for the restatements of the Corporation's 10-K and 10-Q filings with the SEC. Professional fees decreased in the three month period ended July 31, 2008 compared to the same period in 2007 due to the timing difference of professional fees associated with year-end costs that were paid. Public company costs consist mainly of fees for investor relations and also include directors' fees, press release and SEC filing costs, printing costs and transfer agent fees.

25

Accretion of Discounts on Convertible Debentures

Agreement Date	Three Months Ended July 31, 2008		Three Months Ended July 31 2007		Six Months Ended July 31, 2008		Six Months Ended July 31, 2007
June 14, 2005	$	-	$	115,626	$	-	$	515,626
December 8, 2005		186,764		1,311,999		813,337		2,439,940
December 28, 2005		604,278		840,183		1,193,063		1,625,968
Total accretion of discounts	$	791,042	$	2,267,808	$	2,006,400	$	4,608,534

Accretion of discounts on convertible debentures decreased in the three and six month periods ended July 31, 2008 compared to the same periods in 2007 due primarily to the June 14, 2005 debenture discounts being realized prior to fiscal 2009, the conversion of December 8, 2005 debentures throughout fiscal 2008 and fiscal 2009 which reduced the accretion base, the repayment of the December 8, 2005 debentures on June 5, 2008, and the reduction of the December 28, 2005 accretion since the maturity date was extended.

Interest Expense

Agreement Date	Three Months Ended July 31, 2008		Three Months Ended July 31 2007			Six Months Ended July 31, 2008		Six Months Ended July 31, 2007
June 14, 2005	$	-	$	(23,878	)	$	-	$	18,919
December 8, 2005		22,312		141,234			91,360		297,911
December 28, 2005		189,041		189,041			373,973		371,918
Total interest expense	$	211,353	$	306,397		$	465,333	$	688,748

Interest expense decreased for the three and six month periods ended July 31, 2008 compared to the same periods in 2007 due primarily to the conversion and repayment of the December 8, 2005 convertible debentures.

Oil and Gas Properties

	Net Book Value January 31, 2008		Additions		Depletion			Disposition			Gain (Loss)			Net Book Value July 31, 2008
Unproven
Windsor Block Maritimes Shale Nova Scotia, Canada	$	15,441,144	$	1,585,787	$	-		$	(2,943,510	)	$	-		$	14,083,421
Beech Hill Block Maritimes Shale New Brunswick, Canada		21,975		41,334		-			-			-			63,309
Western Canadian Shale Alberta and B.C., Canada		-		25,387		-			-			-			25,387
Arkoma Basin, Arkansas Fayetteville Shale		8,289,901		20,970		-			-			-			8,310,871
U.S. Rocky Mountains Colorado, Montana, Wyoming		812,020		18,488		-			(800,503	)		(30,005	)		-
Proved
Alberta Deep Basin Western Canada		324,162		11,175		(45,106	)		-			-			290,231
Greater Fort Worth Basin, Texas Barnett Shale		89,747		40,450		(5,922	)		(164,985	)		40,710			-
Net	$	24,978,949	$	1,743,591	$	(51,028	)	$	(3,908,998	)	$	10,705		$	22,773,219

During the six month period ended July 31, 2008, the Corporation spent $1,585,787 on the Windsor Block mainly for testing of Kennetcook #1 and #2 ($616,000), installation of an electric submersible pump at Kennetcook #2 ($456,000) and drilling costs for the first well of the second phase of the project that spud in mid-July and was drilling over quarter-end ($387,000).

26

In July 2008, the Corporation received $2,943,510 in cash for the joint venture partner's share of its 30% working interest in exploration costs associated with the Windsor Block in Nova Scotia.

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

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

Net Cash Oil and Gas Additions

	Six Months Ended July 31, 2008
Net additions, per above table	$	1,743,591
Non-cash Asset Retirement Obligation additions		(45,450	)
Non-cash Asset Retirement Obligation dispositions		137,429
Changes in investing working capital		1,900,339
Net oil and gas additions, per Statement of Cash Flows	$	3,735,909

Twelve months ended January 31, 2008 compared to the twelve months ended January 31, 2007

Results of Operations

		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		6.51		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 fiscal year ended January 31, 2008, the Corporation realized $781,696, 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 in 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 totalled $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 totalled $304,537 and $nil ($15.24/Boe and $nil/Boe) for the years ended January 31, 2008 and 2007, respectively.

27

Depletion, Depreciation and Accretion

	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.

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		-
U.S. Rocky Mountains		2,104,663		182,854
Total	$	19,598,916	$	1,281,499

In the fiscal year ended January 31, 2008, the Corporation 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 than anticipated costs to drill and complete the wells 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 were sold for gross proceeds of $983,902 on July 18, 2007. In the year ended January 31, 2007, the Corporation recognized an impairment charge of $1,098,645 related to the Alberta Deep Basin assets primarily as a result of a dry hole.

The Corporation 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 U.S. Rocky Mountains related to the Colorado and Wyoming prospects that the Corporation drilled and has determined to not move forward on. The Corporation recognized an unproven property cost impairment of $6,527,501 in the fiscal year ended January 31, 2008 related to the Fayetteville Shale project since the Corporation has elected to sell all its Fayetteville land in 2008. As a result, the Corporation has written-off $5,971,671 of exploration costs mainly related to the drilling of one well and one seismic program which are no longer recoverable. Also, the Corporation has expensed land costs in the Fayetteville project of $555,830 related to land prospecting fees which resulted in no acreage acquisition.

28

As a result of the above impairments, the net carrying value of the Corporation's 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

The above net carrying values of the Corporation's oil and gas properties are comprised of the following amounts:

	January 31, 2008			January 31, 2007
Maritimes Basin - Eastern Canada shale
Acquisition	$	22,837		$	-
Geological and Geophysical		4,184,653			654,159
Drilling, Completions and Testing		11,255,629			-
		15,463,119			654,159
Arkoma Basin, Arkansas - Fayetteville Shale
Acquisition		8,845,728			7,054,498
Geological and Geophysical		2,292,422			203,908
Drilling, Completions and Testing		3,679,252			310,695
Impairments		(6,527,501	)		-
		8,289,901			7,569,101
U.S. Rocky Mountains (Colorado, Montana, Wyoming)
Acquisitions (net of dispositions)		2,296,721			2,158,767
Geological and Geophysical		68,318			28,624
Drilling, Completions and Testing		1,752,211			1,200,567
Impairments		(3,305,230	)		(1,200,567	)
		812,020			2,187,391
Alberta Deep Basin – Western Canada
Acquisition		399,138			443,759
Geological and Geophysical		1,353,128			1,377,010
Drilling, Completions and Testing		6,737,363			5,432,519
Impairments and Depletion		(8,165,467	)		(1,098,645	)
		324,162			6,154,643
Greater Fort Worth Basin, Texas - Barnett Shale
Acquisitions (net of dispositions)		1,335,216			2,312,711
Geological and Geophysical		217,300			217,300
Drilling, Completions and Testing		2,844,366			2,042,421
Impairments and Depletion		(4,307,135	)		(36,231	)
		89,747			4,536,201
Total
Acquisitions (net of dispositions)		12,899,640			11,969,735
Geological and Geophysical		8,115,821			2,481,001
Drilling, Completions and Testing		26,268,821			8,986,202
Impairments and Depletion		(22,305,333	)		(2,335,443	)
Net Book Value	$	24,978,949		$	21,101,495

29

General and Administrative

	2008			2007		2006
Salaries, benefits and consulting fees	$	1,537,870		$	1,043,594	$	411,946
Stock-based compensation		2,696,143			5,825,356		2,994,399
Office Costs		839,116			514,241		159,057
Professional fees		281,095			157,491		117,067
Public company costs		608,791			674,588		363,404
Operating overhead recoveries		(162,899	)		-		-
G&A	$	5,800,116		$	8,215,270	$	4,045,873

General and administrative expenses 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 the Corporation's executives that have now been fully recognized. Salaries, benefits and consulting fees have increased due to increasing staff to 10 full time employees and one full time consultant. Office costs have increased as a result of increasing office rent and office supply costs to accommodate the increased staffing levels. Professional fees have increased as a result of increased accounting fees and legal fees. Public company costs consist mainly of fees for investor relations and also include directors' fees, press release and SEC filing costs, printing costs and transfer agent fees. Overhead recoveries relate to costs recovered from partners related to capital costs spent on projects the Corporation operated.

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
	$	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.

Twelve months ended January 31, 2007 compared to the twelve months ended January 31, 2006

Results of Operations

For the twelve months ended January 31, 2007, the Corporation realized $54,342 in revenue from natural gas sales, as compared to $nil for the comparable period in fiscal 2006. This revenue was the result of the Corporation realizing initial production from four small working interest wells located in the Barnett Shale in Texas that began producing in early August 2006.

30

General and administrative expenses for the twelve months ended January 31, 2007 totalled $8,215,270. Included in this amount was $5,825,356 of stock based compensation expense. Also included in the above total were salaries, wages and consulting fees of $992,153 for the twelve months ended January 31, 2007. Of the remaining $1,397,761 of general and administrative expenses, $250,000 is attributable to an investor relations contract awarded in the fourth quarter of 2006, while the remainder is comprised of insurance, professional fees, and travel and other office related expenses. For the twelve month period ended January 31, 2006, general and administrative expenses totalled $4,045,873. The majority of the total general and administrative expenses related to stock based compensation expense totalling $3,468,399. The remaining $577,474 for the twelve months ended January 31, 2006 related to consulting fees and general office expenses. General and administrative expenses have increased significantly in the prior year primarily due to increased stock based compensation expense, but also due to an increase in the size and scope of the Corporation's activities. The Corporation's shift to oil and gas exploration from mining necessitated an increase in staffing levels as well as an increase in travel and other administrative expenses in order to properly oversee the Corporation's geographically diverse operations.

Liquidity and Capital Resources

To July 31, 2008, the Corporation has generated minimal revenues and has incurred operating losses in every quarter. The Corporation is an early stage production company, has not generated significant revenues from operations and has incurred significant losses since inception. These factors among others raise substantial doubt about its ability to continue as a going concern.

As at July 31, 2008, the Corporation had working capital of $10,623,175, resulting primarily from its cash and cash equivalents of $23,493,562 offset by payables of $3,549,024, $7,962,069 of convertible debentures and $1,917,122 of associated accrued interest. The Corporation has a cash equivalents balance of $23,383,247 at July 31, 2008, which is held on deposit at a Schedule "1" Canadian Chartered Bank in U.S. term deposits and non-redeemable Guaranteed Investment Certificates ("GIC") that mature in less than 90 days. For the six month period ended July 31, 2008, the Corporation had net cash outflow from operating activities of $2,562,172, mainly related to cash general and administrative expenses.

	July 31, 2008						January 31, 2008
Agreement Date	Face Value		Discount		Carrying Value		Face Value		Discount		Carrying Value
December 8, 2005	$	-	$	-	$	-	$	6,100,140	$	1,321,869	$	4,778,271
December 28, 2005	$	10,000,000	$	2,037,931	$	7,962,069	$	10,000,000	$	3,229,279	$	6,770,721
Total convertible debentures	$	10,000,000	$	2,037,931	$	7,962,069	$	16,100,140	$	4,551,148	$	11,548,992

The Corporation has $10,000,000 of Convertible Debentures outstanding as at July 31, 2008. The Convertible Debentures were issued on December 28, 2005 and mature on June 1, 2009, whereby $10,000,000 plus accrued interest is payable or convertible at the option of the holder at $4.00 per share. Based on the current share price, conversion is not likely and the Corporation will either be required to repay or refinance these debentures.

The December 8, 2005 debentures were convertible at the lower of (i) $5.00 or (ii) 90% of the average of the three lowest daily volume weighted average prices of the Common Shares of the 10 trading days immediately preceding the date of conversion. During the six month period ended July 31, 2008, $2,100,140 of the December 8, 2005 convertible debentures were converted into 2,374,013 Common Shares and the remaining $4,000,000 of these convertible debentures were repaid, subject to a 20% early redemption fee ($800,000).

The Corporation was committed to pay 66% of the drilling and completion costs for one well in its Fayetteville project to earn a 50% working interest. The operator had to spud this well before July 31, 2008 or the Corporation automatically earned its 50% working interest. The operator did not spud this well; therefore, the Corporation has earned its 50% working interest. In November 2008, the Corporation sold 530 gross acres (265 net acres) of undeveloped acreage in the Fayetteville Shale for gross proceeds of $222,466.

The Corporation was also committed to pay 33% of the costs to drill one well in its Rocky Mountains project to earn a 25% working interest. On June 30, 2008, the Corporation sold its Montana acreage position along with this commitment.

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The Corporation expects significant capital expenditures during the next 12 months for drilling programs on its Canadian shale program, overhead and working capital purposes. To partially fund these expenditures, the Corporation closed a private placement on June 3, 2008 for aggregate gross proceeds of $25,560,500. Also, to fund the remaining expenditures, the Corporation entered into the Zodiac Joint Venture Agreement effective May 31, 2008, whereby Zodiac may pay up to 50% of the next Cdn$30,000,000 in gross costs for the next six wells in the Windsor Block of Nova Scotia to earn up to 25% in the Block. There is a risk that neither Zodiac, nor Triangle's 30% joint venture partner in the Windsor Block, will be able to pay for their portion of the well costs, which would slow down or stop exploration on the Windsor Block. The Corporation will have to raise additional funds to complete the exploration and development phase of its programs and, while the Corporation has been successful in doing so in the past, there can be no assurance that it will be able to do so in the future. The continuation of the Corporation as a going concern for a period longer than the current fiscal year 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, earning of its interests in the underlying properties, and the attainment of profitable operations.

By adjusting its operations to the level of capitalization, the Corporation believes that it has sufficient capital resources to meet projected cash flow deficits in the near term. However, if during that period, or thereafter, the Corporation is not successful in generating sufficient liquidity from operations or in raising sufficient capital resources, on acceptable terms, this could have a material adverse effect on its business, results of operations, liquidity and financial condition.

The Corporation presently does not have any available credit, bank financing or other external sources of liquidity. Due to its brief history and historical operating losses, its operations have not been a source of liquidity. The Corporation will need to obtain additional capital in order to expand operations and become profitable. In order to obtain capital, the Corporation may need to sell additional Common Shares or borrow funds from private lenders. There can be no assurance that the Corporation will be successful in obtaining additional funding.

The Corporation will still need additional capital in order to continue operations until it is able to achieve positive operating cash flow. Additional capital is being sought, but the Corporation cannot guarantee that it 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 its Common Shares and a downturn in the North American stock and debt markets could make it more difficult to obtain financing through the issuance of equity or debt securities. Even if the Corporation is able to raise the funds required, it is possible that it could incur unexpected costs and expenses, fail to collect significant amounts owed to it, or experience unexpected cash requirements that would force it to seek alternative financing. Furthermore, if the Corporation issues 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 its Common Shares. If additional financing is not available or is not available on acceptable terms, the Corporation will have to curtail its operations.

June 2008 Private Placement

On June 3, 2008, the Corporation sold an aggregate of 18,257,500 units in a private placement transaction for gross proceeds of $25,560,500. The net proceeds after deducting expenses were $23,537,913. Each unit was priced at $1.40 per unit and consists of one Common Share and one-half of a warrant. One full warrant can be exercised into one Common Share for a period of two years at a price of $2.25 per share. Pursuant to the terms of the sale, the Corporation was required, on a best efforts basis, to file a registration statement with the SEC, and to cause such registration statement to be declared effective by the SEC, within 150 days after closing, to permit the public resale of the shares underlying the warrants. The registration statement was declared effective by the SEC on July 14, 2008. Also, pursuant to the terms of the sale, the Corporation is required, on a best efforts basis, to list its Common Shares on the Toronto Stock Exchange (which includes the TSXV) on or before December 31, 2008. Failure to list the shares for trading by such date shall result in the Corporation paying, pro rata to the purchasers, a penalty equal to 2% of the gross proceeds of the offering for each month or partial month until the shares are listed for trading on the Toronto Stock Exchange (which includes the TSXV), not to exceed 10% in the aggregate. The Corporation paid the placement agents of the offering a cash fee of 7% of the gross proceeds of the offering.

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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 the Corporation 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 Corporation 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 Corporation may differ materially and adversely from its 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

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

Asset Retirement Obligations

The Corporation recognizes a liability for future retirement obligations associated with its 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 the Corporation settles 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

The Corporation records compensation expense in the consolidated financial statements for 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 Corporation's stock price volatility and the Options expected life. Compensation costs are recognized over the vesting period.

Derivative Liabilities

The Corporation 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. Fair values are determined using the Black Scholes option pricing model, which requires and is very sensitive to an estimate of the Corporation'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.

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Recently Issued Accounting Pronouncements

In December 2007, the Financial Accounting Standard Board ("FASB") revised the Statement of Financial Accounting Standard ("SFAS") No. 141, "Business Combinations". SFAS No. 141R requires an acquirer to be identified for all business combinations and applies the same method of accounting for business combinations – the acquisition method – to all transactions. In addition, transaction costs associated with acquisitions are required to be expensed. The revised statement is effective to business combinations in years beginning on or after December 31, 2008. The adoption of this statement will impact business combinations, if any, after the effective date.

In December 2007, the FASB issued SFAS No. 160, "Non-controlling Interests in Consolidated Financial Statements". SFAS No. 160 requires the Corporation 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 Corporation commencing on February 1, 2009 and it will not impact its current financial statements.

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

In May 2008, the FASB issued SFAS No. 162, "The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. SFAS No. 162 directs the GAAP hierarchy to the entity, not the independent auditors, as the entity is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. SFAS No. 162 is effective 60 days following the SEC's approval of the Public Company Accounting Oversight Board amendments to remove the GAAP hierarchy from the auditing standards. SFAS No. 162 is not expected to have a material impact on the Corporation's financial statements.

In May 2008, the FASB directed the FASB Staff to issue FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) (FSP APB 14-1). FSP APB 14-1 applies to convertible debt instruments that, by their stated terms, may be settled in cash (or other assets) upon conversion, including partial cash settlement of the conversion option. FSP APB 14-1 requires bifurcation of the instrument into a debt component that is initially recorded at fair value and an equity component. The difference between the fair value of the debt component and the initial proceeds from issuance of the instrument is recorded as a component of equity. The liability component of the debt instrument is accreted to par using the effective yield method; accretion is reported as a component of interest expense. The equity component is not subsequently re-valued as long as it continues to qualify for equity treatment. FSP APB 14-1 is effective for the Company on February 1, 2009. Early adoption is not permitted. The Corporation is evaluating the impact of adopting FSP APB 14-1 will have on the Corporation's financial statements.

DESCRIPTION OF SHARE CAPITAL

The following is a summary of the rights, privileges, restrictions and conditions attaching to the Common Shares and other outstanding securities.

Common Shares

The Corporation is authorized to issue up to 100,000,000 Common Shares, with a par value of $0.00001. As of the date of this prospectus, there are 67,426,043 Common Shares outstanding. Holders of the Common Shares are entitled to one vote per share on all matters to be voted upon by the Shareholders. Holders of Common Shares are entitled to receive rateably such dividends, if any, as may be declared by the Board of Directors. Upon the liquidation, dissolution, or winding up of the Corporation, the holders of Common Shares are entitled to share rateably in the assets of the Corporation which are legally available for distribution after payment of all debts and other liabilities and the liquidation preference of any preferred shares then outstanding. Holders of Common Shares have no preemptive, subscription, redemption or conversion rights.

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Warrants

In connection with a private placement that closed on June 3, 2008, the Corporation issued Warrants to purchase 9,128,750 Common Shares. The Warrants are exercisable until June 3, 2010 at a purchase price of $2.25 per Common Share. All of the Common Shares issuable upon conversion of the Warrants may be sold without restriction upon the effectiveness of the registration statement dated June 27, 2008 and filed with the SEC. As of the date of this prospectus, Warrants to acquire 9,128,750 Common Shares remain outstanding.

Convertible Debentures

The Corporation issued the Convertible Debentures on December 28, 2005 and January 23, 2006 pursuant to a securities purchase agreement with each of Bank Sal. Oppenheim Jr. & Cie., (Schweiz) AG and Centrum Bank AG. Each of the two accredited investors subscribed for $5,000,000 in Convertible Debentures and warrants to purchase 625,000 Common Shares. The warrants have since expired. The Convertible Debentures are due and payable on June 1, 2009, with 7.5% interest, unless sooner converted into Common Shares, at the holder's option, at a rate of $4.00 per share. The investors have contractually agreed to restrict their ability to convert their respective debentures such that the number of Common Shares held by such investor and its affiliates after such conversion does not exceed 4.99% of the then issued and outstanding Common Shares. All of the Common Shares issuable upon conversion of the Convertible Debentures may be sold without restriction. As at July 31, 2008 there remains issued and outstanding an aggregate of $10,000,000 principal amount of Convertible Debentures and accrued interest of $1,917,122 that may be converted at the option of the holder into Common Shares at $4.00 per share.

CAPITALIZATION

The following table sets forth the capitalization of the Corporation as at July 31, 2008 and as at October 31, 2008. The table must be read in conjunction with the consolidated financial statements and accompanying notes, which appear in this prospectus.

Description of the Security	Authorized		Outstanding as at  July 31, 2008		Outstanding as at  October 31, 2008
Common Shares		100,000,000		67,426,043		67,426,043
Options(1)		4,000,000		3,585,000		3,610,000
Warrants(2)		N/A		9,128,750		9,128,750
Convertible Debentures(3)		N/A		$10,000,000 principal amount convertible into 2,500,000 Common Shares(4)		$10,000,000 principal amount convertible into 2,500,000 Common Shares(5)
Long Term Debt		N/A		Nil		Nil

Notes:

(1) Exercisable at prices ranging from $1.40 to $4.55 per Common Share

(2) Exercisable until June 3, 2010 at a purchase price of $2.25 per Common Share

(3) Due and payable on June 1, 2009, with 7.5% interest, unless sooner converted into Common Shares, at the holder's option, at a rate of $4.00 per share.

(4) As at July 31, 2008, there was accrued interest outstanding of $1,917,122 which is convertible, at the holder's option, at a rate of $4.00 per share.

(5) As at October 31, 2008, there was accrued interest outstanding of $2,106,164 which is convertible, at the holder's option, at a rate of $4.00 per share.

OPTION PLAN

Pursuant to the 2005 Plan, Options vest as to 20% upon granting and 20% every six months thereafter, and Options may be granted at a price that is not less than the 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 Shares. Triangle may issue Options to acquire up to a maximum of 2,000,000 Common Shares under the 2005 Plan. The 2007 Plan has similar terms to the 2005 Plan. Triangle may issue Options to acquire up to a maximum of 2,000,000 Common Shares under the 2007 Plan.

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As of the date of this prospectus, there are issued and outstanding Options to acquire an aggregate of 3,610,000 Common Shares as shown in the table below. None of the Options are currently in-the-money.

Concurrently with the filing of the final prospectus, the Corporation will freeze the 2005 Plan and the 2007 Plan, such that no additional Options may be issued under such Option Plans. All outstanding Options will continue to be governed by the terms of their respective Option Plans. The Corporation anticipates asking its Shareholders to approve a new form of option plan that is in accordance with the policies of the TSXV at the next annual meeting of Shareholders in 2009. Prior to receiving Shareholder approval of a new form of option plan, the Corporation will treat the Option Plans as though they were subject to the requirements of TSXV Policy 4.4 Incentive Option Plans, such that any provisions in the Option Plans that are not in compliance with TSXV Policy 4.4 will be treated as though they have no force or effect.

Group	Number of Common Shares Under Option		Date of Grant	Exercise Price		Market Value on Date of Grant(1)		Expiry Date
Executive Officers (2)	250,000	(7)	August 17, 2007	$	2.00	$	1.45	August 16, 2012
	300,000	(7)	February 21, 2008	$	2.00	$	1.15	January 31, 2013
	400,000	(6)	July 2, 2008	$	1.40	$	1.38	July 1, 2013
Directors (3)	200,000	(6)	August 5, 2005	$	3.23	$	3.80	August 4, 2010
	200,000	(6)	February 21, 2006	$	4.55	$	4.55	February 20, 2011
	400,000	(6)	August 2, 2007	$	2.00	$	2.00	August 1, 2012
	100,000	(7)	August 17, 2007	$	2.00	$	1.45	August 16, 2012
	225,000	(7)	July 2, 2008	$	1.40	$	1.38	July 1, 2013
Employees (4)	50,000	(6)	August 5, 2005	$	3.23	$	3.80	August 4, 2010
	100,000	(6)	September 8, 2006	$	2.13	$	2.13	September 7, 2011
	50,000	(6)	May 1, 2007	$	2.19	$	2.19	April 30, 2012
	250,000	(7)	August 17, 2007	$	2.00	$	1.45	August 16, 2012
	100,000	(7)	December 13, 2007	$	2.00	$	1.30	December 12, 2012
	200,000	(6)	July 2, 2008	$	1.40	$	1.38	July 1, 2013
	25,000	(6)	August 15, 2008	$	1.40	$	0.65	August 14, 2013
Consultants (5)	360,000	(6)	August 5, 2005	$	3.23	$	3.80	August 4, 2010
	100,000	(7)	August 17, 2007	$	2.00	$	1.45	August 16, 2012
	100,000	(7)	December 13, 2007	$	2.00	$	1.30	December 12, 2012
	100,000	(7)	January 14, 2008	$	2.00	$	1.20	January 13, 2013
	100,000	(7)	July 2, 2008	$	1.40	$	1.38	July 1, 2013

Notes:

(1) Determined as the closing price of the Common Shares on the OTC Bulletin Board the date of grant.

(2) Includes all executive officers and past executives officers of the Corporation as a group, of which there are three.

(3) All directors and past directors of the Corporation who are not also executive officers, of which there are three.

(4) Includes all other employees and past employees of the Corporation, of which there are six.

(5) Includes all consultants and past consultants of the Corporation, of which there are eight.

(6) Options issued pursuant to the 2005 Plan.

(7) Options issued pursuant to the 2007 Plan.

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PRIOR SALES

The following table sets forth all securities issued by the Corporation in the past twelve months:

Date of Issuance	Type of Security Issued		Number of Securities		Price Per Security
September 25, 2007		Common Shares(1)		591,203	$	1.26860
November 11, 2007		Common Shares(2)		1,000,000	$	1.00
November 17, 2007		Common Shares(2)		1,500,000	$	1.00
November 26, 2007		Common Shares(2)		1,500,000	$	1.00
November 30, 2007		Common Shares(2)		2,000,000	$	1.00
November 13, 2007		Common Shares(1)		484,872	$	1.03120
November 15, 2007		Common Shares(1)		419,076	$	1.19310
November 21, 2007		Common Shares(1)		402,998	$	1.24070
November 21, 2007		Common Shares(1)		402,998	$	1.24070
November 26, 2007		Common Shares(1)		402,998	$	1.24070
November 27, 2007		Common Shares(1)		926,783	$	1.24070
March 14, 2008		Common Shares(1)		782,554	$	0.76690
April 8, 2008		Common Shares(1)		472,769	$	0.79320
April 11, 2008		Common Shares(1)		310,443	$	0.80530
April 15, 2008		Common Shares(1)		293,462	$	0.85190
May 1, 2008		Common Shares(1)		514,785	$	1.21410
June 3, 2008		Units(3)		18,257,500	$	1.40

Note:

(1) Common Shares issued on the conversion of convertible debentures.

(2) Common Shares issued on the exercise of warrants.

(3) Each Unit was comprised of one Common Share and one half of one Warrant. Each Warrant entitles the holder to purchase one Common Share at a price of $2.25 until June 3, 2010.

TRADING PRICE AND VOLUME

The Common Shares of Triangle are registered under section 12(g) of the 1934 Act and have traded on the OTC Bulletin Board under the symbol "TPLM" since June 7, 2005. The following table sets forth the closing price range and trading volume of the Common Shares as reported by the OTC Bulletin Board for the periods indicated. All references to "$" are to U.S. dollars.

Period	High ($)		Low ($)		Volume
2007
November		1.50		1.27		14,461,500
December		1.55		1.19		4,880,800
2008
January		1.45		0.95		1,521,500
February		1.20		0.72		1,045,200
March		1.10		0.84		1,433,400
April		1.63		0.88		2,869,300
May		2.40		0.85		5,336,300
June		1.98		1.50		3,780,900
July		1.63		0.95		913,000
August		1.08		0.60		1,178,100
September		0.95		0.54		876,611
October		0.65		0.13		17,449,542
November (1-19)		0.34		0.17		822,100

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ESCROWED SECURITIES

The TSXV has conditionally accepted the listing of the Corporation's Common Shares. Certain security holders of the Corporation will be subject to escrow requirements pursuant to TSXV Policy 5.4 - Escrow, Vendor Consideration and Resale Restrictions. TSXV Policy 5.4 requires that all securities held by a "principal" of an issuer be held in escrow. The securities held by these persons will be held in escrow pursuant to the Escrow Agreement dated November 20, 2008 among the Corporation, Olympia Trust Company as Escrow Agent and those Shareholders whose Common Shares are required to be escrowed. The number and percentage of each class of securities of the Corporation that are subject to escrow is as follows:

Class of Securities	Number of Securities Held in Escrow		Percentage of Class
Common Shares		3,341,600		5.0	%
Options		2,075,000		57.5	%
Warrants		125,000		1.4	%

Escrow restricts the ability of certain holders to deal with their escrow securities while they are in escrow. The Escrow Agreement sets out these restrictions and provides that, except to the extent permitted thereunder, a principal cannot sell, transfer, assign, mortgage, enter into a derivative transaction concerning, or otherwise deal in any way with such holder's escrow securities or the related share certificates or other evidence of the escrow securities. A private company, controlled by one or more principals of the Corporation, that holds escrow securities of the Corporation, may not participate in a transaction that results in a change of its control or a change in the economic exposure of the principals to the risks of holding escrow securities.

If the TSXV lists the Common Shares, the Corporation, as a Tier 2 issuer, will have its securities released from escrow over a 36 month period as follows:

(i)	10% immediately following the date of listing;
(ii)	15% 6 months following listing;
(iii)	15% 12 months following listing;
(iv)	15% 18 months following listing;
(v)	15% 24 months following listing;
(vi)	15% 30 months following listing; and
(vii)	15% 36 months following listing.

If the Corporation becomes a Tier 1 issuer subsequent to listing its Common Shares on the TSXV, the release of the escrowed Common Shares will be accelerated. An accelerated escrow release will not commence until the Corporation has made application to the TSXV for listing as a Tier 1 issuer and the TSXV has issued a bulletin that announces the acceptance for listing of the Corporation on Tier 1 of the TSXV.

PRINCIPAL SHAREHOLDERS

To the knowledge of Management, other than as described in the table below, as at the date hereof there are no persons or companies who own, directly or indirectly, or exercise control or direction over shares carrying more than 10% of the voting rights attached to any class of voting securities of the Corporation.

Name	Number of Common Shares Owned, Controlled or Directed		% Ownership of Common Shares			Whether the Securities are owned of Record or Beneficially or Both
Palo Alto Investors, LLC(2)		14,751,350		21.9	%		of record only
Sprott Asset Management Inc.(3)		7,150,000		10.6	%		of record only

Notes:

(1) The information in this table has been derived from public filings with the SEC.

(2) 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. The Common Shares registered to the foregoing limited partnerships, as well as persons affiliated with such entities, have been aggregated for the purpose of this table only. To the knowledge of Triangle, none of the foregoing limited partnerships holds 10% or more of the Common Shares.

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(3) In addition to the Common Shares held, Sprott Asset Management holds 3,575,000 Warrants.

DIRECTORS AND OFFICERS

The name, province of residence, positions held with the Corporation, Common Shares beneficially owned and biography (including principal occupation during the preceding five years and related experience) of each of the directors and officers of the Corporation is presented in the table below. Directors are elected to serve until the next annual meeting of Shareholders and until their successors are elected and qualified. Currently there are four seats on the Board of Directors. Officers are elected by the Board of Directors and serve until their successors are appointed by the Board of Directors.

			Common Shares of the Corporation Beneficially Owned
Name, Province/State of Residence and Age	Position(s) with the Corporation	Director Since	Number of Shares		% of Class		Principal Occupation for the Past 5 Years & Education
J. Howard Anderson Alberta, Canada 50	President, COO & VP Engineering of Triangle, Elmworth & Triangle USA	N/A	509,500	(1)	0.76	%	Occupation: President of Triangle since August 15, 2008; President of Elmworth and Triangle USA since June 30, 2008; and Chief Operating Officer and VP Engineering of Triangle, Elmworth and Triangle USA since February 1, 2008. VP Engineering of Rockyview Energy Inc. (TSX) from June 2005 to January 2008; Manager, Central Business Unit for APF Energy Trust from June 2004 to June 2005; VP Engineering & Development of Pioneer Natural Resources Canada Inc. from April 2002 to April 2004. Education: Professional Engineer with the Association of Professional Engineers, Geologists, & Geophysicists of Alberta. Bachelor of Science (Engineering) from Queen's University.
David L. Bradshaw(7) Colorado, U.S. 54	Director	August 2007	20,000	(2)	0.03	%	Occupation: Owner of Waterton Resources, LLC, an oil and gas exploration investment company. Managing Director of Comet Ridge Ltd. (Australian Stock Exchange) from September to November 2008 and Director from November 2007 to November 2008. Mr. Bradshaw has held various positions at Tipperary Corporation (Amex) since 1990, including Chairman and CEO from 1996 to October 2005. Education: Certified Public Accountant with the Texas State Board of Public Accounting. Bachelor of Business Administration and Master of Business Administration from Texas A&M University.

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			Common Shares of the Corporation Beneficially Owned
Name, Province/State of Residence and Age	Position(s) with the Corporation	Director Since	Number of Shares		% of Class		Principal Occupation for the Past 5 Years & Education
Mark G. Gustafson British Columbia, Canada 48	CEO & Director of Triangle; Director of Elmworth and Triangle USA	May 2005	2,773,500	(3)	4.09	%	Occupation: Chief Executive Officer and director of the Corporation since May 2005. President and CEO of Torrent Energy Corporation (OTC:BB) from September 2004 to January 2006 and President of MGG Consulting, a private company, from April 1999 to August 2004. Education: Chartered Accountant with the Institute of Chartered Accountants of B.C. and the Institute of Chartered Accountants of Alberta. Bachelor of Business Administration from Wilfrid Laurier University.
Stephen A. Holditch(7) Texas, U.S. 61	Director	February 2006	38,600	(4)	0.06	%	Occupation: Head of the Department of Petroleum Engineering at Texas A&M University since January 2004 and faculty member of Texas A&M University since 1976 as an Assistant Professor, Associate Professor, Professor and Professor Emeritus. Engineer at Schlumberger Technology Corporation from October 1997 to January 2004. Education: Professional Engineer in Texas. Bachelor of Science and Doctor of Philosophy from Texas A&M University.
Randal Matkaluk(7) Alberta, Canada 50	Director	August 2007	0	(5)	0	%	Occupation: Director and Officer of Virtutone Networks Inc. (formerly "Sawhill Capital Ltd.") (TSXV) since October 2005. Chief Financial Officer of Relentless Energy Corp. from January 2003 to October 2005. Education: Chartered Accountant with the Institute of Chartered Accountants of Alberta. Bachelor of Commerce from the University of Calgary.
Shaun Toker Alberta, Canada 29	CFO and Secretary of Triangle, Elmworth & Triangle USA	N/A	0	(6)	0	%	Occupation: Chief Financial Officer of the Corporation since August 2007 and of Elmworth and Triangle USA since September 2007. Financial Controller of TransGlobe Energy Corp. (TSX) from April 2004 to August 2007 and Staff Accountant of KPMG LLP from September 2001 to April 2004. Education: Chartered Accountant with the Institute of Chartered Accountants of Alberta. Bachelor of Commerce from the University of Alberta.

Notes:

(1) In addition, Mr. Anderson holds Warrants to purchase an additional 54,000 Common Shares at a price of $2.25 per share until June 3, 2010; Options to purchase an additional 300,000 Common Shares at a price of $2.00 per share until February 1, 2013; and Options to purchase an additional 150,000 Common Shares at a price of $1.40 per share until July 2, 2013.

(2) In addition, Mr. Bradshaw holds Warrants to purchase an additional 10,000 Common Shares at a price of $2.25 per share until June 3, 2010; Options to purchase an additional 200,000 Common Shares at a price of $2.00 per share until August 3, 2012; and Options to purchase an additional 75,000 Common Shares at a price of $1.40 per share until July 2, 2013.

(3) In addition, Mr. Gustafson holds Warrants to purchase an additional 54,000 Common Shares at a price of $2.25 per share until June 3, 2010 and Options to purchase an additional 200,000 Common Shares at a price of $1.40 per share until July 2, 2013.

40

(4) In addition, Mr. Holditch holds Warrants to purchase an additional 7,000 Common Shares at a price of $2.25 per share until June 3, 2010; Options to purchase an additional 200,000 Common Shares at a price of $3.23 per share until August 5, 2010; Options to purchase an additional 200,000 Common Shares at a price of $4.55 until February 21, 2011; Options to purchase an additional 100,000 Common Shares at a price of $2.00 until August 16, 2012; and Options to purchase an additional 75,000 Common Shares at a price of $1.40 per share until July 2, 2013.

(5) Mr. Matkaluk holds Options to purchase 200,000 Common Shares at a price of $2.00 per share until August 3, 2012 and Options to purchase an additional 75,000 Common Shares at a price of $1.40 per share until July 2, 2013.

(6) Mr. Toker holds Options to purchase 250,000 Common Shares at a price of $2.00 per share until August 17, 2012 and Options to purchase an additional 50,000 Common Shares at a price of $1.40 per share until July 2, 2013.

(7) Member of the Audit Committee, the Compensation Committee and the Nominating - Corporate Governance Committee.

As of the date of this prospectus, the directors and officers as a group beneficially owned, directly and indirectly, or exercised control or direction over 3,341,600 Common Shares representing 5% of the Common Shares currently issued and outstanding. Messrs. Anderson, Gustafson and Toker are employees of the Corporation and each devotes his full time and attention to the business and affairs of the Corporation. In addition, each has an employment agreement which contain non-competition and confidentiality provisions. The directors of the Corporation devote their time and attention to the affairs of the Corporation as required. (See "Executive Compensation - Employment Contracts")

Penalties, Sanctions and Bankruptcies

No director or executive officer of the Corporation has, within the 10 years prior to the date of this prospectus, been a director, chief executive officer or chief financial officer of any company that, while such person was acting in that capacity (or after such person ceased to act in that capacity but resulting from an event that occurred while that person was acting in such capacity) was the subject of a cease trade order, an order similar to a cease trade order, or an order that denied the company access to any exemption under securities legislation for a period of more than 30 consecutive days.

No director or executive officer has, within the 10 years preceding the date of this prospectus, been a director or executive officer of any company that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or comprise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.

No director or executive officer has, within the 10 years preceding the date of this prospectus, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the individual.

EXECUTIVE COMPENSATION

The following table sets forth information concerning the total compensation awarded or paid to, or earned by, the Named Executive Officers for the three most recently completed financial years. The Corporation did not have any other officers who received total remuneration in excess of Cdn$150,000 determined on the basis of base salary and bonuses, in the most recently completed fiscal year.

41

Summary Compensation Table

Long-Term Compensation

Awards

Securities

Restricted

Annual��Compensation

Under

Shares or

Other Annual

Options

Restricted

Payouts

Name and

Year ended

Compensation(6)

Granted (1)

Share

LTIP

All Other

Principal Position

January 31

Salary

Bonus

(#)

(#)

Units

Payouts

Compensation

Mark G. Gustafson

2008

Cdn$288,000

nil

Cdn$1,083

nil

nil

nil

Nil

CEO

2007

Cdn$153,000

nil

Cdn$763

nil

nil

nil

Nil

2006

U.S.$50,000

(2)

nil

nil

nil

nil

nil

Nil

Ron Hietala (3)

2008

U.S.$220,000

(3)

nil

nil

nil

nil

nil

Nil

President of

2007

U.S.$240,000

(3)

nil

nil

nil

nil

nil

Nil

Elmworth & Triangle USA

2006

U.S.$160,000

(3)

nil

nil

nil

nil

nil

Nil

Aly Musani (4)

2008

U.S.$65,000

nil

Cdn$3,724

nil

nil

nil

nil

CFO

2007

U.S.$120,000

Cdn$17,500

Cdn$6,278

nil

nil

nil

nil

2006

U.S.$25,000

Nil

nil

200,000

nil

nil

nil

Shaun Toker (5)CFO

2008

Cdn$56,500

Cdn$5,000

Cdn$2,706

250,000

nil

nil

nil

Notes:

(1) Each Option entitles the holder to acquire one Common Share of the Corporation.

(2) Mr. Gustafson was paid through a management consulting agreement between the Corporation and MGG Consulting, a company owned by Mr. Gustafson, until February 1, 2006 when the consulting agreement was amended to an employment agreement.

(3) Mr. Hietala was paid through a series of management consulting agreements between the Corporation and RWH Management Services, a company owned by Mr. Hietala. Mr. Hietala retired from all positions with the Corporation and its subsidiaries on June 30, 2008. Howard Anderson became the President of the subsidiaries on June 30, 2008 and President of Triangle on August 15, 2008.

(4) Mr. Musani resigned effective August 15, 2007 and Mr. Toker became the Chief Financial Officer.

(5) Mr. Toker became the Chief Financial Officer effective August 15, 2007.

(6) Amounts received for perquisites.

Stock Options

The following table sets forth information in respect of all Option grants made during most recent completed financial year to each of the Named Executive Officers. All references to "$" are to U.S. dollars.

Name

Securities under Options/SARs granted (#)

Percentage of total Options/SARs granted to Employees in Financial Year

Exercise or Base Price ($/Security)

Market Value of Securities Underlying Options/SARs on the Date of Grant ($/Security)(1)

Expiration Date

Mark G. Gustafson

nil

(2)

N/A

N/A

N/A

N/A

Ron Hietala

nil

N/A

N/A

N/A

N/A

Aly Musani

nil

N/A

N/A

N/A

N/A

Shaun Toker

250,000

(3)

17.2

%

$

2.00

$

1.45

August 16, 2012

Note:

(1) The market value of the security underlying the Option is the closing market price on August 17, 2007.

(2) Mr. Gustafson was granted 200,000 Options on July 2, 2008 at an exercise price of $1.40.

(3) Mr. Toker was granted an additional 50,000 Options on July 2, 2008 at an exercise price of $1.40.

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The following table sets forth information in respect of the aggregate number of unexercised Options held as at January 31, 2008 and the value of unexercised, in-the-money Options as at January 31, 2008. The actual value of the unexercised in-the-money Options will be determined by the market price of the Corporation's Common Shares on the dates such Options may be exercised by any of the optionees. All references to "$" are to U.S. dollars.

Value of Unexercised

Securities

Aggregate

Unexercised Options

in-the-money Options at

Acquired

Value

at January 31, 2008

January 31, 2008 (1)(2)

on Exercise

Realized

Exercisable

Unexercisable

Exercisable

Unexercisable

Name

(#)

($)

(#)

(#)

($)

($)

Mark G. Gustafson

nil

N/A

nil

nil

N/A

N/A

Ron Hietala

nil

N/A

nil

nil

N/A

N/A

Aly Musani

nil

N/A

nil

nil

N/A

N/A

Shaun Toker

nil

N/A

50,000

200,000

nil

nil

Notes:

(1) The market value of the Common Shares on January 31, 2008 was $1.20, being the closing market price.

(2) Calculated by multiplying the number of Common Shares purchasable on exercise of the Options by the difference between the market price of the Common Shares on January 31, 2008 and the exercise price of the Options.

Employment Contracts

Mark G. Gustafson

Effective March 17, 2008, Elmworth entered into an employment agreement with Mark G. Gustafson as Chief Executive Officer, effective until such time as either party terminates the agreement. Pursuant to the terms of the agreement, Mr. Gustafson receives an annual salary of Cdn$240,000 and 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. Mr. Gustafson may terminate his employment upon 60 days' written notice.

Shaun Toker

Effective January 31, 2008, Elmworth entered into an employment agreement with Shaun Toker as Chief Financial Officer, effective until such time as either party terminates the agreement. Pursuant to the terms of the agreement, Mr. Toker receives an annual salary of Cdn$150,000 and up to an additional Cdn$25,000 for filing the quarterly and annual reports of the Corporation within agreed upon time frames. In addition, Mr. Toker is entitled to receive an annual bonus based upon various criteria targets and 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, effective until such time as either party terminates the agreement. Pursuant to the terms of the agreement, Mr. Anderson receives an annual salary of Cdn$180,000. This amount was increased to Cdn$200,000 per year effective June 30, 2008 when Mr. Anderson became the President of Elmworth and Triangle USA. On February 1, 2008, Mr. Anderson received Options to purchase 300,000 Common Shares, 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 and 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.

43

Compensation of Directors

Currently, independent directors receive $10,000 per quarter for serving on the Corporation's Board of Directors and related committees. Until the third quarter of 2008, independent directors received $5,000 per quarter for their services. Messrs. David L. Bradshaw, Randal Matkaluk and Stephen Holditch are each considered to be independent directors. Mr. Gustafson is not considered independent by virtue of his role as Chief Executive Officer of the Corporation. Directors are also entitled to receive Options under the Corporation's Option Plans as determined by the Board of Directors. The Corporation reimburses directors for expenses incurred in connection with attending Board of Directors' meetings.

Directors who are not also executive officers received compensation for their services for the fiscal year ended January 31, 2008 as set forth below. All references to "$" are to U.S. dollars.

Name	Fees Earned or Paid in Cash ($)		Option Awards (#)
David L. Bradshaw		15,000		200,000	(1)
John D. Carlson		10,000		nil
Stephen A. Holditch		25,000		100,000	(1)
Randal Matkaluk		15,000		200,000	(1)

Notes:

(1) The Options have an exercise price of $2.00. In addition, each director was awarded 75,000 Options on July 2, 2008 with an exercise price of $1.40.

INDEBTEDNESS OF DIRECTORS AND EXECUTIVE OFFICERS

None of the directors or officers of the Corporation nor any associate of any such person are or were, during the most recently completed financial year of the Corporation, indebted to the Corporation or any of its subsidiaries. Additionally, neither the Corporation nor any of its subsidiaries has provided any guarantee, support agreement, letter of credit or similar arrangement or undertaking in respect of any indebtedness of any such person to any other person or entity.

CORPORATE GOVERNANCE DISCLOSURE

Corporate governance relates to the activities of the Board of Directors, the members of which are elected by and are accountable to the Shareholders, and takes into account the role of the individual members of Management who are appointed by the Board of Directors and who are charged with the day to day management of the Corporation. The Board of Directors is committed to sound corporate governance practices, which are both in the interest of its Shareholders and contribute to effective and efficient decision making.

Pursuant to NI 41-101, the Corporation is required to disclose its corporate governance practices in accordance with National Instrument 58-101 - Disclosure of Corporate Governance Practices, as summarized below.

Board of Directors

The Board of Directors is currently comprised of four individuals, three of whom are independent (Stephen A. Holditch, David L. Bradshaw and Randal Matkaluk). Mark G. Gustafson is not considered independent within the meaning of that term set out in NI 52-110 due to his role as Chief Executive Officer of the Corporation. Further, he is not considered independent because of his position as an officer of Elmworth, a wholly owned subsidiary of the Corporation.

44

Directorships

Randal Matkaluk is a Director and Officer of Virtutone Networks Inc. (formerly "Sawhill Capital Ltd."), which is listed on the TSXV.

Orientation and Continuing Education

New directors to the Board of Directors are provided with a director's package containing pertinent information about the Corporation. Directors are provided with ongoing education respecting the Corporation's operations by way of Management presentations.

Ethical Business Conduct

The Corporation has adopted a Code of Ethics and Business Conduct that applies to all of its directors, officers and employees. The Code contains commitments to treating others in an ethical manner; promoting a positive work environment; protecting oneself and others; keeping accurate and complete records; obeying the law; avoiding conflicts of interest; avoiding illegal and questionable gifts and favours; maintaining the integrity of consultants, agents and representatives; protecting proprietary information; obtaining and using company assets wisely; and following the law and using common sense in political contributions and activities. The Board of Directors takes reasonable steps to monitor compliance with the Code and the Audit Committee is empowered to enforce the Code through appropriate means of discipline.

In addition to the Code of Ethics, the Corporation has adopted an insider trading compliance program and whistleblower procedures, which are overseen by the Audit Committee.

Nomination of Directors

Triangle's 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".

The 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.

The Corporate Governance/Nominating Committee seeks to identify director candidates based on input provided by a number of sources, including (1) the Corporate Governance/Nominating Committee members, (2) other directors, (3) Shareholders, (4) Chief Executive Officer or Chairman, and (5) third parties such as professional search firms. In evaluating potential candidates for director, the Corporate Governance/Nominating Committee considers the entirety of each candidate's credentials.

Qualifications for consideration as a director nominee may vary according to the particular areas of expertise being sought as a complement to the existing composition of the Board of Directors. However, at a minimum, candidates for director must possess: (1) high personal and professional ethics and integrity; (2) the ability to exercise sound judgment; (3) the ability to make independent analytical inquiries; (4) a willingness and ability to devote adequate time and resources to diligently perform Board and committee duties; and (5) the appropriate and relevant business experience and acumen.

45

In addition to these minimum qualifications, the Corporate Governance/Nominating Committee also takes into account when considering whether to nominate a potential director candidate the following factors: (1) whether the person possesses specific industry expertise and familiarity with general issues affecting the Corporation's business; (2) whether the person's nomination and election would enable the Board to have a member that qualifies as an "audit committee financial expert" as such term is defined by the SEC in Item 401 of Regulation S-K; (3) whether the person would qualify as an "independent" director under the listing standards of the various stock markets and exchanges; (4) the importance of continuity of the existing composition of the Board of Directors to provide long term stability and experienced oversight; and (5) the importance of diversified Board membership, in terms of both the individuals involved and their various experiences and areas of expertise.

The Corporate Governance/Nominating Committee will consider director candidates recommended by Shareholders provided such recommendations are submitted in accordance with the procedures set forth below. In order to provide for an orderly and informed review and selection process for director candidates, the Board of Directors has determined that Shareholders who wish to recommend director candidates for consideration by the Nominating Committee must comply with the following:

· The recommendation must be made in writing to the Corporate Secretary at the Corporation.

· The recommendation must include the candidate's name, home and business contact information, detailed biographical data and qualifications, information regarding any relationships between the candidate and the Corporation within the last three years and evidence of the recommending person's ownership of the Corporation's Common Shares.

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

· A statement from the Shareholder nominee indicating that such nominee wants to serve on the Board and could be considered "independent" under the Rules and Regulations of the various stock markets and exchanges and the SEC, as in effect at that time.

All candidates submitted by Shareholders will be evaluated by the Corporate Governance/Nominating Committee according to the criteria discussed above and in the same manner as all other director candidates.

Compensation

The Corporation's Compensation Committee currently consists of Messrs. David L. Bradshaw, Randal Matkaluk and Stephen Holditch, with Mr. Matkaluk elected as Chairman of the Committee. The Board of Directors has determined that all of the members are "independent." The Board of Directors has adopted a written charter setting for the authority and responsibilities of the Compensation Committee.

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

Assessments

The Board of Directors takes steps to satisfy itself that the Board, its committees and individual directors are performing effectively by providing each director with the opportunity to attend all meetings either in person or by conference call at the cost of the Corporation.

46

AUDIT COMMITTEE INFORMATION

The following information is provided in accordance with Form 52-110F1 under NI 52-110 - Audit Committees. However, the Corporation is not subject to the requirements of NI 52-110 as it is currently an SEC foreign issuer.

Audit Committee's Charter

The full text of the Audit Committee's charter is included in Appendix "D" of this prospectus.

Composition of the Audit Committee

The Audit Committee of the Board of Directors is currently comprised of three directors, Messrs. David L. Bradshaw (Chairman), Randal Matkaluk and Stephen Holditch, all of whom are independent and financially literate. 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."

The relevant education and experience of each Audit Committee members is outlined below:

Stephen A. Holditch

Stephen A. Holditch has been a director of the 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

David L. Bradshaw has been a director of the Corporation since August 2007. Mr. Bradshaw is currently the owner of Waterton Resources, LLC, an oil and gas exploration investment company. Mr. Bradshaw was the Managing Director of Comet Ridge Ltd. (Australian Stock Exchange) from September to November 2008 and a director from November 2007 to November 2008. 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

Randal Matkaluk has been a director of the 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.

47

Pre-Approval Policies and Procedures

Pursuant to the terms of the Corporation's Audit Committee Charter, the Audit Committee is responsible for the appointment, compensation and oversight of the work performed by the Corporation'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 Corporation'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.

External Auditor Service Fees

Manning Elliott LLP was the Corporation's auditor until March 11, 2008, at which time KPMG LLP was appointed as the Corporation's current auditor. The decision to change accountants was made by the Audit Committee to consolidate the Corporation's accounting and outside accounting functions in Calgary, Alberta. The following table provides information about the fees billed to the Corporation for professional services rendered by the Corporation's auditors during the fiscal years ended January 31, 2008 and 2007:

Category of Fees	Manning Elliott LLP				KPMG LLP
	Year Ended January 31, 2008		Year Ended January 31, 2007		Year Ended January 31, 2008		Year Ended January 31, 2007
Audit Fees(1)	$	75,960	$	46,200		nil		nil
Audit Related Fees(2)	$	7,918	$	4,250		nil		nil
Tax Fees(3)	$	20,000		nil		Cdn$3,675		Cdn$5,078
All Other Fees		nil		nil		nil		nil
TOTAL	$	103,878	$	50,450		Cdn$3,675		Cdn$5,078

Notes:

(1) Audit fees consist of professional services rendered by the Corporation's previous auditors, Manning Elliott LLP, for the audit of the Corporation's annual financial statements during the years ended January 31, 2008 and 2007 and fees for the reviews of the financial statements included in the Corporation's quarterly reports on Form 10-Q.

(2) Audit-related fees are for registration statement consent letters and are not reported under the heading "Audit Fees".

(3) The Corporation's previous independent registered public accounting firm, Manning Elliot LLP, billed $20,000 during the fiscal year ended January 31, 2008 for tax related work including drafting tax returns for the years ended January 31, 2006 and 2007 for Triangle, Triangle USA and Elmworth and did not bill the Corporation during the fiscal year ended January 31, 2007 for tax related work. The Corporation's current independent registered public accounting firm, KPMG LLP, billed Cdn$3,675 for tax related work during the fiscal year ended January 31, 2008, and Cdn$5,078 for tax related work during the fiscal year ended January 31, 2007, which included discussions of transfer pricing policies and reviewing draft tax returns.

INDUSTRY CONDITIONS

The natural gas and oil industry is subject to extensive controls and regulations imposed by various levels of government. Outlined below are some of the more significant aspects of the legislation, regulations and agreements governing the natural gas and oil industry. All current legislation is a matter of public record and the Corporation is unable to predict what additional legislation or amendments may be enacted.

48

Canadian and U.S. Government Regulation

The natural gas and oil industry is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any of these controls or regulations will affect the operations of the Corporation in a manner materially different than they would affect other natural gas and oil companies of similar size.

Pricing and Marketing Oil

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

Pricing and Marketing Natural Gas

In Canada, the price of natural gas sold in interprovincial and international trade is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain criteria prescribed by the NEB. Natural gas export contracts for a term of less than two years, or for a term of two to 20 years if in quantities of not more than 30,000 m3/day, may be made pursuant to an NEB order. Natural gas export contracts for a term of greater than 20 years or for a term of greater than 2 years and in quantities of greater than 30,000m3/day require an exporter to obtain an export licence from the NEB and the issuance of such a licence requires the approval of the Governor in Council. The export of natural gas pursuant to an order or license shall be subject to the terms and conditions included by the NEB in such order or license.

The government of Alberta also regulates the volume of natural gas that may be removed from the province for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations. Natural gas may not be removed from the Province of Alberta without a permit from the ERCB. The ERCB may grant a permit for the removal of less than 3 billion cubic metres of natural gas for a term not exceeding 2 years with the approval of the Minister. All other permits for the removal of natural gas to be granted by the ERCB require the approval of the Lieutenant Governor in Council. The removal of natural gas from the Province of Alberta shall be subject to the terms and conditions included by the ERCB in the permit granted for such removal

The North American Free Trade Agreement

On January 1, 1994, NAFTA became effective among the governments of Canada, the U.S. of America and Mexico. NAFTA carries forward most of the material energy terms contained in the Canada U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the U.S. of America or Mexico will be allowed provided that any export restrictions do not: (i) reduce the proportion of energy resource exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period), (ii) impose an export price higher than the domestic price, and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements.

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

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Royalties and Incentives

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

From time to time the governments of Canada, Alberta, Nova Scotia and New Brunswick have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging natural gas and oil exploration or enhanced planning projects.

Alberta

Regulations made pursuant to the Mines and Minerals Act (Alberta) provide various incentives for exploring and developing oil reserves in Alberta. Oil produced from horizontal extensions commenced at least five years after the well was originally spudded may qualify for a royalty reduction, provided the drilling of the horizontal extension commenced after September 30, 1992 but prior to November 1, 2006. An 8,000m3 exemption is available for production from a well that has not produced for a 24 month period, if resuming production after February 1, 1993. As well, oil production from eligible new field and new pool wildcat wells and deeper pool exploration wells spudded or deepened after September 30, 1992 is entitled to a 12 month royalty exemption (to a maximum of $1 million). Oil produced from low productivity wells, enhanced recovery schemes (such as injection wells) and experimental projects are also subject to royalty reductions.

The royalties reserved to the Crown from oil produced are calculated on a sliding scale that varies depending on the vintage of the pool from which the oil is produced. The old oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 35%. The new oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30%. Third tier oil (oil produced from pools discovered after September 30, 1992) has a base rate of 10% and a rate cap of 25%.

In the Province of 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 5% and 35% in the case of old natural gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying intervals in eligible natural 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 well.

It should be noted that on October 25, 2007 the government of Alberta announced that a new royalty regime would be implemented commencing January 1, 2009. This new royalty regime would apply royalties to production of both natural gas and oil on a sliding scale varying from 0% to 50%.

Nova Scotia

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

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New Brunswick

The Province of New Brunswick employs a sliding scale royalty regime for oil production. The base royalty is 5% of the actual selling price or fair market value at the time and place of production, whichever is the greater, free and clear of any deductions, and varies with production up to 12%. The royalty on natural gas is 10% of the actual selling price or fair market value at the time and place of production, whichever is the greater, free and clear of any deductions. The royalty on all by-products obtained from oil or natural gas by processing or separation, including natural gas liquids and condensate, is 10% of the actual selling price or fair market value at the time and place of production, whichever is the greater, less the producer's proportionate share of production, processing and transportation charges.

Land Tenure

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

Canadian Environmental Regulation

The natural gas and oil industry is currently subject to environmental regulation pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well, facility and pipeline sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines and penalties, including the revocation of operation licenses.

In Alberta, environmental compliance is governed by the EPEA. The EPEA provides a framework for environmental assessments, environmental approval processes, standards for the handling of releases of substances and contaminated sites, conservation and reclamation practices, practices for the reduction and disposal of waste and an enforcement process. The EPEA imposes environmental responsibilities on natural gas and oil operators in Alberta and provides for penalties in cases of violations.

RISK FACTORS

The risks and uncertainties below are not the only ones facing the Corporation. Additional risks and uncertainties not presently known to the Corporation or that the Corporation currently considers immaterial may also impair the business and operations of the Corporation and cause the price of the securities of the Corporation to decline. If any of the following risks actually occur, the Corporation's business may be harmed and the financial condition and results of operation may suffer significantly. In that event, the trading price of the Common Shares could decline. Prospective investors should review the risks with their legal and financial advisors and should consider, in addition to the matters set forth elsewhere in this prospectus, the following risks.

Risks Relating to Triangle's Business

Triangle has a history of losses which may continue and which may negatively impact its ability to achieve its business objectives.

The Corporation incurred net losses of $29,600,747 and $4,281,969 for the years ended January 31, 2008 and 2007, respectively, and $4,213,248 for the six months ended July 31, 2008. There can be no assurance that the Corporation can achieve or sustain profitability on a quarterly or annual basis in the future. The Corporation's 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 the Corporation will be able to continue expansion of its revenue. The Corporation may not achieve its business objectives, and the failure to achieve such goals would adversely impact the Corporation.

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The Corporation's independent auditors have expressed substantial doubt about the Corporation's ability to continue as a going concern, which may hinder the Corporation's ability to obtain future financing.

In their report dated April 24, 2008, the Corporation's independent auditors stated that the Corporation's financial statements for the year ended January 31, 2008 were prepared assuming that the Corporation would continue as a going concern. The Corporation's ability to continue as a going concern is an issue raised as a result of recurring losses from operations. The Corporation continues to experience net operating losses. The Corporation's ability to continue as a going concern is subject to its ability to generate a profit and/or obtain necessary funding from outside sources, including obtaining additional funding from the sale of the Corporation's securities, increasing sales or obtaining loans and grants from various financial institutions where possible. The Corporation's continued net operating losses increase the difficulty in meeting such goals and there can be no assurances that such methods will prove successful.

From time to time, the Corporation may require additional financing in order to execute its acquisition, exploration and development programs. Failure to obtain financing in a timely manner could cause the Corporation to dispose of working interests in properties, pass up acquisition opportunities and reduce or shut-in its operations. If the Corporation's cash flow from operations is not sufficient to satisfy its capital expenditure budget, there can be no assurance that additional financing will be available to meet these requirements.

If alternative sources of financing are required, but are insufficient or unavailable, the Corporation will be required to modify its growth and operating plans in accordance with the extent of available funding, which could have an adverse effect on the Corporation's business and results of operations.

From time to time, the Corporation may enter into transactions to acquire assets or the shares of other corporations. These transactions may be financed partially or wholly with debt, which may increase the Corporation's debt levels above industry standards. Depending on future exploration and development plans, the Corporation may require additional equity and/or debt financing that may not be available or, if available, may not be available on favourable terms. Neither the Corporation's articles nor its by-laws limit the amount of indebtedness that it may incur. The level of the Corporation's indebtedness from time to time could impair its ability to obtain additional financing in the future on a timely basis to take advantage of business opportunities that may arise.

The Corporation has a limited operating history and, if it is not successful in continuing to grow its business, it may have to scale back or even cease its ongoing business operations.

The Corporation has received a limited amount of revenues from operations and has limited assets. The Corporation has yet to generate positive earnings and there can be no assurance that the Corporation will ever operate profitably. Triangle has a limited operating history. Its success is significantly dependent on a successful acquisition, drilling, completion and production program. The Corporation's 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. The Corporation may be unable to locate recoverable reserves or operate on a profitable basis. The Corporation is in the exploration stage and potential investors should be aware of the difficulties normally encountered by enterprises in the exploration stage. If the Corporation's business plan is not successful, and it is not able to operate profitably, investors may lose some or all of their investment in the Corporation.

Because the Corporation is small and does not have much capital, it may have to limit its exploration activity, which may result in a loss of investment.

Because the Corporation is small and does not have much capital, it must limit its exploration activity. As such, the Corporation may not be able to complete an exploration program that is as thorough as Management would like. In that event, existing reserves may go undiscovered. Without finding reserves, the Corporation cannot generate revenues and investors may lose their investments.

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If the Corporation is unable to retain the services of Messrs. Gustafson, Anderson and Toker or if the Corporation is unable to successfully recruit qualified managerial and field personnel having experience in oil and gas exploration, the Corporation may not be able to continue its operations.

The Corporation's success depends to a significant extent upon the continued services of its directors and officers and, in particular: Mr. Mark G. Gustafson, Chief Executive Officer and a director; Mr. J. Howard Anderson, President, Chief Operating Officer and VP Engineering of Triangle, Triangle USA and Elmworth; and Mr. Shaun Toker, Chief Financial Officer and Secretary of Triangle and Chief Financial Officer of Triangle USA and Elmworth. Loss of the services of Messrs. Gustafson or Toker could have a material adverse effect on the Corporation's growth, revenues, and prospective business. The Corporation has not and does not expect to obtain key man insurance on its Management. In addition, in order to successfully implement and manage the Corporation's business plan, the Corporation 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 the Corporation will be able to find, attract and retain existing employees or that the Corporation will be able to find, attract and retain qualified personnel on acceptable terms.

As most of the Corporation's properties are in the exploration stage, there can be no assurance that the Corporation will establish commercial discoveries on it 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 the Corporation's properties are in the exploration stage only and the Corporation has only limited revenues from operations. While the Corporation does have a limited amount of proven reserves of gas, it may not establish commercial discoveries on any of the its properties.

Although the Corporation's estimated natural gas and oil reserve data has been prepared by an independent third party, the estimates may still prove to be inaccurate.

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

The potential profitability of oil and gas ventures depends upon factors beyond the control of the Corporation.

The potential profitability of oil and gas properties is dependent upon many factors beyond the Corporation's 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 the Corporation's financial performance.

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Adverse weather conditions can also hinder drilling operations. A productive well may become uneconomic in the event that water or other deleterious substances are encountered which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is impregnated with water or other deleterious substances. The marketability of oil and gas which may be acquired or discovered will be affected by numerous factors beyond the Corporation's 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 the Corporation not receiving an adequate return on invested capital.

The oil and gas industry is highly competitive and there is no assurance that the Corporation will be successful in acquiring and continuing its leases/permits.

The oil and gas industry is intensely competitive. The Corporation competes with numerous individuals and companies, including many major oil and gas companies, which have substantially greater technical, financial and operational resources and staff. 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. The Corporation cannot predict whether the necessary funds can be raised or that any projected work will be completed.

If the production agreement in the Windsor Block in Nova Scotia is not granted, the Corporation's right to explore for and develop oil and gas on this block would be forfeited.

The Corporation cannot predict whether the Nova Scotia government will convert the Corporation's exploration agreement into a production agreement. The Windsor Block exploration agreement is due to expire on March 15, 2009. If such exploration agreement expires, the Corporation's right to explore for and develop oil and gas on this block would be forfeited.

If the leases in the Beech Hill Block in New Brunswick expire, the Corporation's right to explore for and develop oil and gas on this block would be forfeited.

The Beech Hill Block is covered by leases and licenses to search for oil and natural gas with the New Brunswick government which expire between February 2009 and June 2011. If such licenses expire, the Corporation's right to explore for and develop oil and gas on this block would be forfeited.

The marketability of natural resources will be affected by numerous factors beyond the Corporation's control, which may result in the Corporation 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 the Corporation will be affected by numerous factors beyond the Corporation's 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 the Corporation receiving a return on invested capital that is insufficient to be profitable or viable.

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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 the Corporation.

Oil and gas operations are subject to federal, state, provincial and local laws relating to the protection of the environment, including laws regulating removal of natural resources from the ground and the discharge of materials into the environment. Oil and gas operations are also subject to federal, state, provincial and local laws and regulations which seek to maintain health and safety standards by regulating the design and use of drilling methods and equipment. Various permits from government bodies are required for drilling operations to be conducted; no assurance can be given that such permits will be received. Environmental standards imposed by federal, provincial, or local authorities may be changed and any such changes may have material adverse effects on the Corporation's 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 the Corporation. Additionally, the Corporation may be subject to liability for pollution or other environmental damages. The Corporation generally maintains insurance coverage customary to the industry; however, it is not fully insured against all possible environmental risks. To date, the Corporation has not been required to spend any material amount on compliance with environmental regulations. However, the Corporation may be required to do so in future and this may affect its ability to expand or maintain its operations. Due to the high salinity of the Corporation's 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, the Corporation can provide no assurance that the estimated amounts in the financial statements will not be significantly higher.

Reliance on participants and partners to fund their portion of cost on the Windsor Block.

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

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

In general, the Corporation's 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 the Corporation's operations or financial condition to date. Specifically, the Corporation is 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 the Corporation is unable to predict the ultimate cost of compliance. Generally, environmental requirements do not appear to affect the Corporation any differently or to any greater or lesser extent than other companies in the industry.

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

The Corporation believes that its operations comply, in all material respects, with all applicable environmental regulations. The Corporation's operating partners generally maintain insurance coverage customary to the industry; however, the Corporation is not fully insured against all possible environmental risks.

Exploratory drilling involves many risks and the Corporation may become liable for pollution or other liabilities which may have an adverse effect on its financial position.

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

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Any change in government regulation and/or administrative practices may have a negative impact on the Corporation's ability to operate and on its profitability.

The laws, regulations, policies or current administrative practices of any government body, organization or regulatory agency in the U.S. or Canada or any other jurisdiction may be changed, applied or interpreted in a manner which will fundamentally alter the ability of the Corporation to carry on its 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 the Corporation. Any or all of these situations may have a negative impact on the Corporation's ability to operate and/or its profitability.

Stakeholder consultation and approvals are required and, if not obtained, may result in the Corporation's inability to obtain the necessary licenses and permits.

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

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

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

Aboriginal claims could have an adverse effect on the Corporation and its operations.

Aboriginal peoples have claimed aboriginal title and rights to portions of Canada. The Corporation is not aware that any claims have been made in respect of its property and assets. However, if a claim arose and was successful this could have an adverse effect on the Corporation and its operations.

No assurance can be given that defects in the Corporation's title to natural gas and oil interests do not exist.

Title to natural gas and oil interests is often not possible to determine without incurring substantial expense. An independent title review was completed with respect to certain of the more valuable natural gas and oil rights acquired by the Corporation and the interests in natural gas and oil rights owned by Triangle. Also, legal opinions have been obtained with respect to the spacing units for the wells which have been drilled to date and which have been operated by the Corporation. However, no assurance can be given that title defects do not exist. If a title defect does exist, it is possible that the Corporation may lose all or a portion of the properties to which the title defect relates. The actual interest of the Corporation in certain properties may therefore vary from the Corporation's records.

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Risks Relating to The Corporation's Outstanding Financing Arrangements

If the Corporation fails to have its Common Shares listed for trading on the TSXV by December 31, 2008, it will be required to pay investors a large penalty payment.

On June 3, 2008, the Corporation sold an aggregate of 18,257,500 units to 31 accredited investors for aggregate proceeds of $25,560,500. Pursuant to the terms of sale, the Corporation agreed to have its Common Shares listed for trading on the Toronto Stock Exchange (which includes the TSXV) no later than December 31, 2008. If the Corporation fails to comply with the listing requirement, it will be required to pay the unit purchasers a fee equal to 2% of the aggregate amount invested by the purchasers per each 30 day period of delay, not to exceed 10%.

There are a large number of Common Shares underlying the Corporation's Convertible Debentures and warrants that may be available for future sale and the sale of these Common Shares may depress the market price of the Common Shares.

As of the date of this prospectus, the Corporation had outstanding Convertible Debentures convertible into 2,500,000 Common Shares and outstanding Warrants issued on June 3, 2008 exercisable into 9,128,750 Common Shares. All of the Common Shares issuable upon conversion of the Convertible Debentures may be sold without restriction. All of the Common Shares issuable upon conversion of the Warrants may be sold without restriction. The sale of these Common Shares may adversely affect the market price of the Corporation's Common Shares

If the Corporation is required for any reason to repay the Corporation's outstanding Convertible Debentures, the Corporation would be required to deplete its working capital, if available, or raise additional funds. The Corporation's failure to repay the Convertible Debentures, if required, could result in legal action against the Corporation, which could require the sale of substantial assets.

In December 2005, the Corporation entered into two securities purchase agreements for the sale of an aggregate of $10,000,000 principal amount of Convertible Debentures. The convertible debentures, which remain fully outstanding as of the date hereof, are due and payable, with 7.5% interest, on June 1, 2009, unless sooner converted into Common Shares. In addition, any event of default such as the Corporation's failure to repay the principal or interest when due, the Corporation's failure to issue Common Shares upon conversion by the holder, the Corporation's failure to have the Corporation's 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 the Corporation's property or business, the filing of a money judgment, writ or similar process against the Corporation in excess of $50,000, the commencement of a bankruptcy, insolvency, reorganization or liquidation proceeding against the Corporation and the delisting of the Common Shares could require the early repayment of the Convertible Debentures, including default interest rate on the outstanding principal balance of the Convertible Debentures if the default is not cured with the specified grace period. If the Corporation was required to repay the Convertible Debentures, the Corporation would be required to use the Corporation's limited working capital and raise additional funds. If the Corporation was unable to repay the Convertible Debentures when required, the debenture holders could commence legal action against the Corporation and foreclose on all of the Corporation's assets to recover the amounts due. Any such action would require the Corporation to curtail or cease operations.

Risks Relating to the Corporation's Common Shares

There is limited liquidity for the Common Shares.

The Common Shares are not currently listed on any exchange in Canada and there is no market in Canada through which the securities of the Corporation may be sold. Quotations for the Common Shares are published on the OTC Bulletin Board. The OTC Bulletin Board is an unorganized, inter-dealer, over-the-counter market that provides significantly less liquidity than other markets. Purchasers of the Common Shares may, therefore, have difficulty selling their shares should they desire to do so, and the lack of liquidity could adversely affect the market price for the common stock.

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Investors may be unable to enforce Canadian statutory remedies against the Corporation.

Securities legislation in certain of the provinces and territories of Canada provides investors with various rights and remedies where a public disclosure contains a misrepresentation. The Corporation is organised under the laws of a foreign jurisdiction. It may be difficult for investors to collect from the Corporation judgements obtained in courts in Canada predicated on the civil liability provisions of Canadian securities legislation.

CONFLICTS OF INTEREST

There may be potential conflicts of interest to which the directors, officers, insiders and promoters of the Corporation may be subject in connection with the operations of the Corporation. The directors, officers, insiders and promoters may be engaged in corporations or businesses which may be in competition with the search by the Corporation for businesses or assets. Accordingly, situations may arise where a director, officer, insider or promoter will be in direct competition with the Corporation. Conflicts, if any, will be subject to the procedures and remedies set out in applicable corporate and securities legislation, regulations, rules and policies.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

From time to time, the Corporation may become involved in various lawsuits, legal proceedings and regulatory 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 Triangle's business. Management is currently not aware of any such legal proceedings, claims or regulatory actions that it believes would have, individually or in the aggregate, a material adverse affect on the business, financial condition or operating results of the Corporation.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Management of the Corporation is not aware of any material interest, direct or indirect, of any director or officer of the Corporation, any person beneficially owning, directly or indirectly, more than 10% of the Corporation's voting securities, or any associate or affiliate of such person in any transaction within the last three financial years or in any proposed transaction which in either case has materially affected or will materially affect the Corporation or its subsidiaries.

The Corporation's Code of Ethics and Business Conduct for Officers, Directors and Employees of Triangle Petroleum Corporation contains a policy of avoiding any action that may involve, or may appear to involve, a conflict of interest with the Corporation. Pursuant to the Code, officers, directors and employees should not have any financial or other business relationships with suppliers, customers or competitors that might impair, or even appear to impair, the independence of any judgment they may need to make on behalf of the Corporation.

AUDITOR, TRANSFER AGENT AND REGISTRARS

The auditor of the Corporation is KPMG LLP, Chartered Accountants, at 2700-205 5 Avenue SW, Calgary, Alberta T2P 2V7.

The transfer agent and registrar of the Common Shares of the Corporation is Continental Stock Transfer & Trust Company at 17 Battery Place, New York, New York 10004-1123.

The sub-agent for the transfer of the Common Shares of the Corporation is Olympia Trust Company at 2300-125 9 Avenue SE, Calgary, Alberta T2G 0P6.

MATERIAL CONTRACTS

The only material contracts entered into by the Corporation or on its behalf in the last two years, other than contracts in the ordinary course of business, are as follows:

· Escrow Agreement

· Windsor Block Farm-In Agreement

· Zodiac Joint Venture Agreement

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A copy of these agreements may be inspected at the head office of the Corporation during regular business hours and will also be filed on SEDAR at www.sedar.com.

EXPERTS

KPMG LLP, Chartered Accountants, were the Corporation's auditors for the fiscal year ended January 31, 2008, and such firm has prepared an opinion with respect to the Corporation's consolidated financial statements as at and for the fiscal year ended January 31, 2008. Manning Elliott LLP, Chartered Accountants, were the Corporation's auditors for the fiscal years ended January 31, 2007 and January 31, 2006, and such firm has prepared an opinion with respect to the Corporation's consolidated financial statements as at and for the fiscal years ended January 31, 2007 and January 31, 2006. Information relating to the Corporation's reserves in this prospectus was prepared by Ryder Scott Company Petroleum Consultants as an independent qualified reserves evaluator.

KPMG LLP is independent of Triangle within the meaning of the Rules of Professional Conduct/Code of Ethics of the Alberta Institute of Chartered Accountants and under all of the relevant professional and regulatory standards in the United States.

Manning Elliott LLP is independent of Triangle within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of British Columbia and under all relevant professional and regulatory standards in the United States.

Ryder Scott Company Petroleum Consultants is the Corporation's independent reserves evaluator, and has prepared opinions with respect to the Corporation's reserves and work program (the Ryder Scott Reserves Report and the Ryder Scott Work Program Report). The principals of Ryder Scott Company Petroleum Consultants own beneficially, directly or indirectly, less than 1% of any class of the Corporation's securities.

59

CONSENT OF KPMG LLP

We have read the non-offering prospectus of Triangle Petroleum Corporation (the "Corporation"). We have complied with Canadian generally accepted standards for an auditor's involvement with offering documents.

We consent to the use in the above-mentioned prospectus of our report to the Board of Directors and stockholders of the Corporation on the consolidated balance sheet of the Corporation as at January 31, 2008 and the consolidated statements of operations, stockholders' equity (deficit), and cash flows for the year then ended. Our report is dated April 24, 2008, except as to notes 2(r) and 17 which are as of November 20, 2008.

signed ("KPMG LLP")

Chartered Accountants

Calgary, Canada

November 20, 2008

CONSENT OF MANNING ELLIOTT LLP

We have read the non-offering prospectus of Triangle Petroleum Corporation (the "Corporation"). We have complied with Canadian generally accepted standards for an auditor's involvement with offering documents.

We consent to the use in the above-mentioned prospectus of our report to the Board of Directors and stockholders of the Corporation dated April 2, 2007 on the consolidated balance sheet of the Corporation as at January 31, 2007 and the consolidated statements of operations, cash flows, and stockholders' equity (deficit) for the years ended January 31, 2007 and 2006.

signed ("Manning Elliott LLP")

Chartered Accountants

Vancouver, Canada

November 20, 2008

60

CERTIFICATE OF THE CORPORATION

DATED:November 20, 2008

This prospectus constitutes full, true and plain disclosure of all material facts relating to the securities previously issued by the Corporation as required by the securities legislation of British Columbia, Alberta and Ontario.

(signed) "Mark G. Gustafson" Chief Executive Officer	(signed) "Shaun Toker" Chief Financial Officer
On Behalf of the Board of Directors
(signed) "David L. Bradshaw" Director	(signed) "Stephen A. Holditch" Director
(signed) "Randal Matkaluk" Director

61

APPENDIX "A"

FINANCIAL STATEMENTS

TRIANGLE PETROLEUM CORPORATION

INDEX TO FINANCIAL STATEMENTS

	Page
Reports of Independent Registered Public Accounting Firms	A-2 and A-3
Consolidated Balance Sheets as of January 31, 2008 and 2007	A-4
Consolidated Statements of Operations for the years ended January 31, 2008, 2007 and 2006	A-5
Consolidated Statements of Cash Flows for the years ended January 31, 2008, 2007 and 2006	A-6
Consolidated Statement of Stockholders' Equity (Deficit) for the years ended January 31, 2008, 2007 and 2006	A-7 to A-8
Notes to the Consolidated Financial Statements	A-9 to A-27

A-1

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.

(signed) "KPMG LLP"

CHARTERED ACCOUNTANTS

Calgary, Canada

April 24, 2008, except as to notes 2(r) and 17 which are as of November 20, 2008

A-2

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 sheet 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 (deficit) for the years ended January 31, 2007 and 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Triangle Petroleum Corporation as of January 31, 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.

(signed) "MANNING ELLIOTT LLP"

CHARTERED ACCOUNTANTS

Vancouver, Canada

April 2, 2007

A-3

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 Events (Note 17)
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

A-4

Triangle Petroleum Corporation

Consolidated Statements of Operations

(Expressed in U.S. dollars)

	Year Ended  January 31, 2008  $			Year Ended  January 31, 2007  $			Year Ended  January 31, 2006  $
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			4,617
General and administrative		5,800,116			8,215,270			4,045,873
Foreign exchange (gain) loss		317,656			(34,578	)		(5,486	)
Impairment loss on oil and gas properties		19,598,916			1,281,499			1,017,713
Total Operating Expenses		26,503,535			9,525,047			5,062,717
Loss from Operations		(25,916,731	)		(9,470,705	)		(5,062,717	)
Other Income (Expense)
Accretion of discounts on convertible debentures		(8,525,621	)		(10,149,984	)		(3,007,664	)
Amortization of debt issue costs		(450,521	)		(411,805	)		(51,842	)
Interest expense		(1,283,165	)		(1,707,732	)		(388,258	)
Interest income		622,497			497,285			51,474
Unrealized gain on fair value of derivatives		5,952,794			16,960,972			11,844,139
Total Other Income (Expense)		(3,684,016	)		5,188,736			8,447,849
Net Income (Loss) Before Discontinued Operations		(29,600,747	)		(4,281,969	)		3,385,132
Discontinued Operations (Note 16)		–			–			(30,000	)
Net Income (Loss) for the Year		(29,600,747	)		(4,281,969	)		3,355,132
Net Income (Loss) Per Share - Basic
Continuing Operations		(0.80	)		(0.21	)		0.13
Discontinued Operations		–			–			–
		(0.80	)		(0.21	)		0.13
Net Income (Loss) Per Share - Diluted
Continuing Operations		(0.80	)		(0.21	)		0.12
Discontinued Operations		–			–			–
		(0.80	)		(0.21	)		0.12
Weighted Average Number of Shares Outstanding
Basic		37,192,000			20,582,000			26,057,000
Diluted		37,192,000			20,582,000			28,826,000

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

A-5

Triangle Petroleum Corporation

Consolidated Statements of Cash Flows

(Expressed in U.S. dollars)

	Year Ended  January 31, 2008  $			Year Ended  January 31, 2007  $			Year Ended  January 31, 2006  $
Operating Activities
Net income (loss)		(29,600,747	)		(4,281,969	)		3,355,132
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			3,007,664
Amortization of debt issue costs		450,521			411,805			51,842
Depletion, depreciation and accretion		441,881			36,229			–
Depreciation – property and equipment		40,429			26,627			4,617
Donated Consulting services and rent		–			–			3,000
Impairment loss on oil and gas properties		19,598,916			1,281,499			1,017,713
Stock-based compensation		2,696,143			5,825,356			3,468,399
Unrealized gain on fair value of derivatives		(5,952,794	)		(16,960,972	)		(11,844,139	)
Changes in operating assets and liabilities
Prepaid expenses		(103,837	)		(2,201,259	)		(317,751	)
Other receivables		(1,139,216	)		(255,737	)		(88,605	)
Accounts payable		88,049			3,672,904			494,547
Accrued interest on convertible debentures		655,107			1,707,731			388,259
Accrued liabilities		53,669			(262,243	)		724,605
Cash Provided by (Used in) Operating Activities		(4,246,258	)		(850,045	)		265,283
Investing Activities
Purchase of property and equipment		(39,458	)		(24,453	)		(73,883	)
Oil and gas property expenditures		(23,223,585	)		(15,295,942	)		(8,050,080	)
Oil and gas property divestitures		983,902			���			–
Cash Used in Investing Activities		(22,279,141	)		(15,320,395	)		(8,123,963	)
Financing Activities
Proceeds from issuance of common stock		26,824,000			–			80,000
Common stock issuance costs		(1,515,994	)		–			–
Common stock returned		–			–			(20,000	)
Proceeds from issuance of convertible debentures		–			5,000,000			26,000,000
Debt issue costs		–			(425,000	)		(955,000	)
Cash Provided by Financing Activities		25,308,006			4,575,000			25,105,000
Increase (Decrease) in Cash and Cash Equivalents		(1,217,393	)		(11,595,440	)		17,246,320
Cash and Cash Equivalents – Beginning of Year		5,798,982			17,394,422			148,102
Cash and Cash Equivalents – End of Year		4,581,589			5,798,982			17,394,422
Cash		1,334,635			353,981			9,777,089
Cash equivalents		3,246,954			5,445,001			7,617,333
Non-cash Investing and Financing Activities
Common stock issued for conversion of debentures and warrants		16,851,576			4,100,000			900,000
Supplemental Disclosures:
Interest paid		628,058			–			–

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

A-6

Triangle Petroleum Corporation

Consolidated Statements Stockholders' Equity (Deficit)

For the years ended January 31, 2006, 2007 and 2008

(Expressed in U.S. dollars)

	Common Stock						Additional  Paid-in			Deferred
	Shares #			Amount #			Capital  $			Compensation  $			Deficit $			Total $
Balance – January 31, 2005		46,282,530			463			159,060			–			(47,681	)		111,842
Shares returned for cancellation		(34,300,000	)		(343	)		343			–			–			–
Issuance of common stock for cash at $0.01 per share with related discount of $3,430,000 in May 2005		4,000,000			40			4,819,960			(4,780,000	)		–			40,000
Issuance of common stock for cash at $0.01 per share with related discount of $3,430,000 in June 2005		4,000,000			40			4,819,960			(4,780,000	)		–			40,000
Return of common stock		(2,000,000	)		(20	)		(2,719,980	)		2,700,000			–			(20,000	)
Issuance of common stock for investor relations services at $1.58 in September 2005		300,000			3			473,997			–			–			474,000
Fair value of stock options vested		–			–			621,066						–			621,066
Fair value of warrants issued with convertible debentures on June 14 and July 14, 2005		–			–			2,858,183			–			–			2,858,183
Fair value of beneficial conversion features of convertible debentures issued June 14 and July 14, 2005		–			–			3,141,817			–			–			3,141,817
Reclassification of original fair value of warrants issued with convertible debentures on June 14 and July 14, 2005		–			–			(2,858,183	)		–			–			(2,858,183	)
Reclassification of change in fair value of warrants issued with convertible debentures June 14 and July 14, 2005 to December 8, 2005		–			–			(11,307,823	)		–			(17,218,794	)		(28,526,617	)
Balance – December 8, 2005		18,282,530			183			8,400			(6,860,000	)		(17,266,475	)		(24,117,892	)
Fair value of beneficial conversion features of convertible debentures and warrants issued December 28, 2005 and January 17 and 23, 2006		–			–			6,738,750			–			–			6,738,750
Issuance of common stock on conversion of convertible debentures on January 18, 2006		900,000			9			899,991			–			–			900,000
Amortization of deferred compensation		–			–			–			2,373,333			–			2,373,333
Donated management services and rent		–			–			3,000			–			–			3,000
Net income for the year		–			–			–			–			3,355,132			3,355,132
Balance – January 31, 2006		19,182,530			192			7,650,141			(4,486,667	)		(13,911,343	)		(10,747,677	)

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

A-7

Triangle Petroleum Corporation

Consolidated Statements Stockholders' Equity (Deficit)

For the years ended January 31, 2006, 2007 and 2008

(Expressed in U.S. dollars)

	Common Stock				Additional  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

A-8

Triangle Petroleum Corporation

Notes to 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. Prior to the fourth quarter of fiscal 2008, 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.

A-9

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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.

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.

A-10

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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.

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.

A-11

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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.

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.

A-12

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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

Prior to February 1, 2006, the Company accounted for stock-based awards under the recognition and measurement provisions of Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees” using the intrinsic value method of accounting. Effective February 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123R “Share Based Payments”, using the modified prospective transition method. Under that transition method, compensation cost is recognized for all share-based payments granted prior to, but not yet vested as of February 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and compensation cost for all share-based payments granted subsequent to February 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS 123R. Results for prior periods have not been restated.

As a result of adopting SFAS 123R on February 1, 2006, the Company's loss for the year ended January 31, 2007 was $224,064 higher than if it had continued to account for share-based compensation under APB No. 25, and basic and diluted loss per share for the year ended January 31, 2007 would have been $0.20 per share if APB No. 25 was still being used.

The following table illustrates the effect on net income per share as if the fair value method had been applied to all outstanding and restated awards for employees during the following period:

	Year Ended January 31, 2006 $
Net income - as reported		3,355,132
Add: Stock-based compensation expense included in net loss - as reported		2,410,033
Deduct: Total stock-based compensation expense determined under fair value based method		(2,558,767	)
Net loss - pro forma		3,206,398
Net income - per share:
Basic - as reported		0.13
Basic - pro forma		0.12
Diluted - as reported		0.12
Diluted - pro forma		0.11

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.

A-13

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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. The adoption of this statement will not have a material effect on the Company's financial statements.

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 will not 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 will impact business combinations, if any, after the effective date.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. SFAS No. 162 directs the GAAP hierarchy to the entity, not the independent auditors, as the entity is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. SFAS No. 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to remove the GAAP hierarchy from the auditing standards. SFAS No. 162 is not expected to have a material impact on the Company’s financial statements.

In May 2008, the FASB directed the FASB Staff to issue FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) (FSP APB 14-1). FSP APB 14-1 applies to convertible debt instruments that, by their stated terms, may be settled in cash (or other assets) upon conversion, including partial cash settlement of the conversion option. FSP APB 14-1 requires bifurcation of the instrument into a debt component that is initially recorded at fair value and an equity component. The difference between the fair value of the debt component and the initial proceeds from issuance of the instrument is recorded as a component of equity. The liability component of the debt instrument is accreted to par using the effective yield method; accretion is reported as a component of interest expense. The equity component is not subsequently re-valued as long as it continues to qualify for equity treatment. FSP APB 14-1 is effective for the Company on February 1, 2009. Early adoption is not permitted. The Company is evaluating the impact of adopting FSP APB 14-1 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.

A-14

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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

5.Oil and Gas Properties

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

	January 31, 2008 $			January 31, 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

A-15

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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; 2006 - $nil) was recorded in the U.S. cost center and $127,819 (2007 and 2006 - $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., $8,289,901 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; 2006 – $1,017,713) 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.

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

A-16

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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 feetBbls – 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 Company Petroleum Consultants.

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.

	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	)

A-17

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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, 2005		-			-			-			-
Issued		6,000,000			10,000,000			10,000,000			26,000,000
Discount		(6,000,000	)		(7,417,339	)		(10,000,000	)		(23,417,339	)
Converted		(900,000	)		-			-			(900,000	)
Accretion		2,493,750			230,809			283,105			3,007,664
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		2,990,624			3,825,916			3,333,446			10,149,986
Balance, January 31, 2007		2,234,374			7,154,807			3,616,551			13,005,732
Modification		-			-			(82,500	)		(82,500	)
Converted		(2,750,000	)		(7,149,860	)		-			(9,899,860	)
Accretion		515,624			4,773,326			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	%

A-18

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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; 2006 - $7,763,400) 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.

A-19

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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.

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 agreements in 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 – 2006 - $230,809) 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; January 31, 2006 – gain of $2,534,739) 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.

A-20

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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.

10.Derivative Liabilities

	Warrants #			Warrants Weighted average exercise price $			Warrants Fair Value $			Conversion Feature Fair Value $			Total Fair Value $
January 31, 2005		-			-			-			-			-
Warrants issued June 15, 2005 and July 14, 2005		6,000,000			1.00			31,384,800			-			31,384,800
Conversion features issued December 8, 2005		-			-			-			3,722,339			3,722,339
Warrants issued December 28, 2005		625,000			4.00			1,708,750			-			1,708,750
Conversion features issued January 17, 2006		-			-			-			3,695,000			3,695,000
Warrants issued January 23, 2006		625,000			4.00			1,552,500			-			1,552,500
Change in fair value		-			-			(9,309,400	)		(2,534,739	)		(11,844,139	)
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

A-21

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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
January 31, 2006		78.2	%		4.49	%		–		2.91

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
January 31, 2006		78.2	%		4.54	%		–		2.27

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)		-		-		5,825,354
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		-		-		3,372,110
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)		-		-		2,522,642
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, 2008, $606,667 (2007 - $2,080,000; 2006 - $1,473,333) 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, 2008, $450,000 (2007 - $1,350,000; 2006 - $900,000) was charged to operations.

A-22

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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.

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		8		747,992		748,000
May 11, 2007		130,494		2		249,998		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.

A-23

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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.

The weighted average grant date fair value of stock options granted during the year ended January 31, 2008 was $1.06 per share (2007 - $2.96 per share; 2006 - $2.66 per share). No stock options were exercised during the years ended January 31, 2008 and 2007. During the years ended January 31, 2008, 2007 and 2006, the Company recorded stock-based compensation of $2,696,143, $5,825,356, $2,994,399, respectively, as general and administrative expense.

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

	Options #			Weighted Average Exercise Price $		Aggregate Intrinsic Value $
Outstanding, January 31, 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			Year Ended January 31, 2006
Expected dividend yield		0	%		0	%		0	%
Expected volatility		71	%		173	%		118	%
Expected life (in years)		3.5			2.7			2.5
Risk-free interest rate		4.23	%		4.72	%		4.11	%

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 year ended January 31, 2008 was $1,465,986 (2007 - $2,395,354; 2006 - $621,066).

A-24

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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	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

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
		906,000

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%; 2006 - 35%) to income tax expense as reported is as follows:

	2008 $			2007 $			2006 $
Expected income tax benefit (expense)		11,038,396			1,498,689			(1,174,296	)
Non-deductible stock-based compensation		(557,071	)		(1,338,875	)		(478,754	)
Non-deductible interest and accretion for convertible debentures		(3,727,339	)		(4,150,200	)		(1,188,573	)
Non-taxable gain on change in fair value of derivatives		2,262,062			5,936,340			4,145,449
Change in enacted tax rate		213,367			–			–
Other and changes in valuation allowance		(9,229,415	)		(1,945,954	)		(1,303,826	)
Provision for income taxes		–			–			–

A-25

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

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.Related Party Transactions

The former President of the Company provided consulting services to the Company commencing June 1, 2005 valued at $1,000 per month to August 31, 2005. (See Note 11(a)).

The Company paid the former Secretary of the Company $18,000 during the year ended January 31, 2006 for consulting services provided.

During the year ended January 31, 2006, the Company repaid $28,416 owing to the former President of the Company. During the year ended January 31, 2006, donated management services of $3,000 provided by the former President of the Company were recorded.

16.Discontinued Operations

In December 2003, the Company, through its former President and director, acquired 100% of the rights, title and interest in six mining claims representing six units in the Greenwood Mining Division in the Province of British Columbia, Canada. Payment of $1,912 was required to record these mining claims and paid by the former President of the Company. The claims were originally purchased by the former President, however, title to the claims has been conveyed to the Company via an unrecorded deed. During fiscal 2006, the Company abandoned its mineral property as a result of poor exploration results.

17.Subsequent Event

Subsequent to January 31, 2008, the Company issued 2,374,013 shares of common stock for the conversion of $2,100,140 of the December 8, 2005 secured convertible debentures that bore interest at 5% per annum. The Company repaid the remaining $4,000,000 of these convertible debentures that were due to mature on December 8, 2008, plus an early redemption fee of $800,000 and associated accrued interest of $1,299,860.

On June 3, 2008, 18,257,500 units were issued in a private placement for gross proceeds of $25,560,500. The net proceeds after deducting expenses was $23,537,913. The Company paid the placement agents of the offering a cash fee of 7% of the gross proceeds of the offering. Each unit was priced at $1.40 per unit and consists of one common stock (relative fair value of $19,300,630 or $1.168 per share) and one-half share purchase warrant (relative fair value of $4,237,100 or $0.232 per unit). One full warrant can be exercised into one share of common stock for a period of two years at a price of $2.25 per share. Pursuant to the terms of the sale, the Company was required, on a best efforts basis, to file a registration statement with the SEC, and to cause such registration statement to be declared effective by the SEC, within 150 days after closing, to permit the public resale of the shares underlying the warrants. The registration statement was declared effective by the SEC on July 14, 2008. Also, pursuant to the terms of the sale, the Company is required, on a best efforts basis, to list the Company’s shares on the Toronto Stock Exchange (which includes the TSX Venture Exchange) on or before December 31, 2008. Failure to list the shares for trading by such date results in a payment by the Company, pro rata to the purchasers, of a penalty equal to 2% of the gross proceeds of the offering for each month or partial month until the shares are listed for trading on the Toronto Stock Exchange (which includes the TSX Venture Exchange), not to exceed 10% in the aggregate.

A-26

Triangle Petroleum Corporation

Notes to Consolidated Financial Statements

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

In June 2008, the company sold its 25% working interest in 9,692 acres in the Phat City area of Montana (Rocky Mountains project) for cash of $800,503.

In June 2008, the Company sold its interests in two Barnett shale wells for gross proceeds of $164,985.

In July 2008, the Company received cash of $2,943,510 for a partner’s share of its 30% working interest in exploration costs associated with the Windsor Block of Nova Scotia when they elected to remain a working interest partner instead of converting to a gross overriding royalty.

A-27

TRIANGLE PETROLEUM CORPORATION

INDEX TO FINANCIAL STATEMENTS

	Page
Consolidated balance sheets at July 31, 2008 and January 31, 2008 (unaudited)	A-29
Consolidated statements of operations for the three and six months ended July 31, 2008 and 2007 (unaudited)	A-30
Consolidated statements of stockholder's equity for the six months ended July 31, 2008 and 2007 (unaudited)	A-31
Consolidated statements of cash flows for the three and six months ended July 31, 2008 and 2007 (unaudited)	A-32
Notes to unaudited consolidated financial statements	A-33 to A-39

A-28

Triangle Petroleum Corporation

Consolidated Balance Sheets

(Expressed in U.S. dollars)

	July 31, 2008 $ (Unaudited)			January 31, 2008 $
ASSETS
Current Assets
Cash and cash equivalents		23,493,562			4,581,589
Prepaid expenses		488,063			797,307
Other receivables		488,971			1,689,391
Total Current Assets		24,470,596			7,068,287
Debt Issue Costs, net		-			465,833
Property and Equipment		50,315			66,121
Oil and Gas Properties (Note 4)		22,773,219			24,978,949
Total Assets		47,294,130			32,579,190
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable		3,549,024			3,533,833
Accrued interest on convertible debentures		1,917,122			2,751,096
Accrued liabilities		419,206			420,384
Derivative liabilities (Note 7)		-			3,262,846
Convertible debentures less unamortized discount of $2,037,931 and $1,321,869, respectively (Note 6)		7,962,069			4,778,271
Total Current Liabilities		13,847,421			14,746,430
Asset Retirement Obligations (Note 5)		582,276			1,003,353
Convertible Debentures, less unamortized discount of $nil and $3,229,279, respectively (Note 6)		-			6,770,721
Total Liabilities		14,429,697			22,520,504
Going Concern (Note 2)
Contingency (Note 8)
Stockholders’ Equity
Common Stock (Note 8)
Authorized: 100,000,000 shares, par value $0.00001 Issued: 67,426,043 shares (2008 – 46,794,530 shares)		674			468
Additional Paid-In Capital (Note 8)		80,633,966			57,852,277
Warrants (Note 9)		4,237,100			-
Deficit		(52,007,307	)		(47,794,059	)
Total Stockholders’ Equity		32,864,433			10,058,686
Total Liabilities and Stockholders’ Equity		47,294,130			32,579,190

A-29

Triangle Petroleum Corporation

Consolidated Statements of Operations

(Expressed in U.S. dollars)

(Unaudited)

	Three Months Ended July 31, 2008 $			Three Months Ended July 31, 2007 $			Six Months Ended July 31, 2008 $			Six Months Ended July 31, 2007 $
Revenue, net of royalties		107,831			124,636			259,950			193,226
Operating Expenses
Oil and gas production		4,154			71,493			63,381			73,802
Depletion, depreciation and accretion		23,268			135,721			93,567			211,189
Depreciation – property and equipment		9,988			14,834			19,747			21,614
General and administrative		1,142,684			1,331,407			2,343,402			3,563,901
Impairment of oil and gas properties		-			3,891,403			-			3,891,403
Gain on sale of assets		(10,705	)		-			(10,705	)		-
Foreign exchange loss		28,595			163,752			24,589			159,746
		1,197,984			5,608,610			2,533,981			7,921,655
Loss from Operations		(1,090,153	)		(5,483,974	)		(2,274,031	)		(7,728,429	)
Other Income (Expenses)
Accretion of discounts on convertible debentures		(791,042	)		(2,267,808	)		(2,006,400	)		(4,608,534	)
Amortization of debt issue costs		(73,056	)		(113,645	)		(182,640	)		(231,353	)
Loss on debt extinguishment		(160,662	)		-			(160,662	)		-
Interest expense		(211,353	)		(306,397	)		(465,333	)		(688,748	)
Interest income		65,014			203,243			82,229			395,666
Unrealized gain (loss) on fair value of derivatives		(125,741	)		2,087,874			793,589			3,555,414
Total Other Expenses		(1,296,840	)		(396,733	)		(1,939,217	)		(1,577,555	)
Net Loss for the Period		(2,386,993	)		(5,880,707	)		(4,213,248	)		(9,305,984	)
Net Loss Per Share – Basic and Diluted		(0.04	)		(0.16	)		(0.08	)		(0.28	)
Weighted Average Number of Shares Outstanding – Basic and Diluted		60,673,000			36,019,000			54,126,000			33,344,000

A-30

Triangle Petroleum Corporation

Statement of Stockholders' Equity

Period from January 31, 2008 to July 31, 2008

(Expressed in U.S. dollars)

(Unaudited)

	Common Stock				Additional Paid-in
	Shares #		Amount $		Capital $			Warrants $		Deficit $			Total $
Balance – January 31, 2008		46,794,530		468		57,852,277			-		(47,794,059	)		10,058,686
Issuance of common stock for cash pursuant to private placement at $1.40 per unit in June 2008		18,257,500		183		21,323,217			4,237,100		-			25,560,500
Share issuance costs		-		-		(2,022,587	)		-		-			(2,022,587	)
Issuance of common stock on conversion of convertible debentures at a weighted average price of $0.88 per share		2,374,013		23		2,100,117			-		-			2,100,140
Fair value of conversion features of convertible debentures converted		-		-		1,039,906			-		-			1,039,906
Stock based compensation		-		-		341,036			-		-			341,036
Net loss for the period		-		-		-			-		(4,213,248	)		(4,213,248	)
Balance – July 31, 2008		67,426,043		674		80,633,966			4,237,100		(52,007,307	)		32,864,433

Triangle Petroleum Corporation

Statement of Stockholders' Equity

Period from January 31, 2007 to July 31, 2007

(Expressed in U.S. dollars)

(Unaudited)

	Common Stock				Additional Paid-in
	Shares #		Amount $		Capital $			Deficit $			Total $
Balance – January 31, 2007		22,475,866		225		13,088,795			(18,193,312	)		(5,104,292	)
Issuance of common stock for cash pursuant to private placement at $1.40 per unit in June 2008		10,412,000		104		20,823,896			-			20,824,000
Share issuance costs		-		-		(1,515,994	)		-			(1,515,994	)
Issuance of common stock on conversion of convertible debentures at a weighted average price of $1.31 per share		4,175,736		41		5,499,959			-			5,500,000
Fair value of conversion features of convertible debentures converted		-		-		1,490,181			-			1,490,181
Investor relation services		50,000		1		108,499			-			108,500
Stock based compensation		-		-		2,045,114			-			2,045,114
Net loss for the period		-		-		-			(9,305,984	)		(9,305,984	)
Balance – July 31, 2007		37,113,602		371		41,540,450			(27,499,296	)		14,041,525

A-31

Triangle Petroleum Corporation

Consolidated Statement of Cash Flows

(Expressed in U.S. dollars)

(Unaudited)

	Three Months Ended July 31, 2008 $			Three Months Ended July 31, 2007 $			Six Months Ended July 31, 2008 $			Six Months Ended July 31, 2007 $
Operating Activities
Net loss		(2,386,993	)		(5,880,707	)		(4,213,248	)		(9,305,984	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Accretion of discounts on convertible debentures		791,042			2,267,808			2,006,400			4,608,534
Amortization of debt issue costs		73,056			113,645			182,640			231,353
Depletion, depreciation and accretion		23,268			135,721			93,567			211,189
Depreciation – property and equipment		9,988			14,834			19,747			21,614
Impairment of oil and gas properties		-			3,891,403			-			3,891,403
Stock-based compensation		227,756			528,078			341,036			2,153,614
Gain on sale of assets		(10,705	)		-			(10,705	)		-
Loss on debt extinguishment		160,662			-			160,662			-
Unrealized loss (gain) on fair value of derivatives		125,741			(2,087,874	)		(793,589	)		(3,555,414	)
Asset retirement costs		(200,937	)		-			(371,637	)		-
Changes in operating assets and liabilities
Prepaid expenses		102,925			(1,793,853	)		54,639			(49,853	)
Other receivables		1,221,540			553,078			1,130,437			(45,633	)
Accounts payable		(502,391	)		2,348,267			(297,740	)		209,412
Accrued interest on convertible debentures		(1,087,957	)		(321,663	)		(833,977	)		60,688
Accrued liabilities		(77,896	)		690,346			(30,404	)		224,234
Cash Provided by (Used in) Operating Activities		(1,530,901	)		459,083			(2,562,172	)		(1,344,843	)
Investing Activities
Purchase of property and equipment		(2,216	)		(23,021	)		(3,941	)		(31,676	)
Oil and gas property expenditures		(1,382,851	)		(4,791,854	)		(3,735,909	)		(7,426,729	)
Cash advances from partners, net		2,567,084			-			2,567,084			-
Proceeds received from sale of oil and pas properties		3,908,998			983,902			3,908,998			983,902
Cash Provided by (Used in) Investing Activities		5,091,015			(3,830,973	)		2,736,232			(6,474,503	)
Financing Activities
Proceeds from issuance of common stock		25,560,500			-			25,560,500			20,824,000
Share issuance costs		(2,022,587	)		-			(2,022,587	)		(1,515,994	)
Convertible debenture repayment		(4,800,000	)		-			(4,800,000	)		-
Cash Provided by Financing Activities		18,737,913			-			18,737,913			19,308,006
Increase (Decrease) in Cash and Cash Equivalents		22,298,027			(3,371,890	)		18,911,973			11,488,660
Cash and Cash Equivalents – Beginning of Period		1,195,535			20,659,532			4,581,589			5,798,982
Cash and Cash Equivalents – End of Period		23,493,562			17,287,642			23,493,562			17,287,642
Cash								110,315			505,157
Cash equivalents								23,383,247			16,782,485
Non-cash Investing and Financing Activities:
Common stock issued for conversion of debentures		625,000			3,600,000			2,100,140			5,500,000

A-32

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

(Unaudited)

Triangle Petroleum Corporation, together with its consolidated subsidiaries ("Triangle" or the "Company"), is an independent oil and gas company focused primarily on the acquisition, exploration and development of resource properties consisting mainly of shale gas reserves. Our primary exploration and development acreage is located in the Horton Bluff formation of the Maritimes Basin in Canada and in the Fayetteville Shale of the Arkoma Basin in the United States. We have producing properties in the Fort Worth Basin and in the Alberta Deep Basin.

1.Basis of Presentation

The accompanying consolidated financial statements of Triangle have been prepared in accordance with generally accepted accounting principals ("GAAP") in the U.S. In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position at July 31, 2008 and our operations and cash flows for the three and six month periods ended July 31, 2008 and 2007. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they should be read along with the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended January 31, 2008. In the prior year, the Company was accounted for as an exploration stage entity. Starting in the fourth quarter of fiscal 2008, the Company was no longer accounted for as an exploration stage entity.

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

2.Going Concern

The Company is primarily engaged in the acquisition, exploration and development of oil and gas resource properties. 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.

3.Accounting Policies

a) Recently Adopted Accounting Pronouncements

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

A-33

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

(Unaudited)

On February 1, 2008 Triangle elected to implement SFAS 157 with the one-year deferral for certain non-financial assets and liabilities. Beginning February 1, 2009, the Company will adopt the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis. We are in the process of evaluating this portion of the standard and have not yet determined the impact that it will have on our financial statements upon adoption in 2009.

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

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

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

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

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

The fair value of the Company’s derivative liabilities were measured using Level III inputs. The significant unobservable inputs to the fair value measurement include estimates of volatility of the share price and term of the contract. The inputs are calculated based on historical data as well as current estimated costs. See Note 7.

The estimated fair values of derivative liabilities, being the conversion feature of the December 8, 2005 convertible debenture, included in the consolidated balance sheets at July 31, 2008 and January 31, 2008 are summarized below. The decrease in the derivative liability from January 31, 2008 to July 31, 2008 is primarily attributable to the settlement of derivatives as a result of the repayment of the underlying debentures.

	July 31, 2008 $ Significant Unobservable Inputs (Level III)		January 31, 2008 $ Significant Unobservable Inputs (Level III)
Derivative liability – conversion feature		-		3,262,846

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

A-34

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

(Unaudited)

b) Recently Issued Accounting Pronouncements

In December 2007, the Financial Accounting Standard Board (FASB) revised the Statement of Financial Accounting Standard (SFAS) No. 141, "Business Combinations". SFAS No. 141R requires an acquirer to be identified for all business combinations and applies the same method of accounting for business combinations – the acquisition method – to all transactions. In addition, transaction costs associated with acquisitions are required to be expensed. The revised statement is effective to business combinations in years beginning on or after December 31, 2008. The adoption of this statement will impact business combinations, if any, after the effective date.

In December 2007, the FASB issued SFAS No. 160, "Non-controlling Interests in Consolidated Financial Statements". SFAS no. 160 requires the Company to report 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 March 2008, the FASB has issued SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities", which requires disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective on February 1, 2009 and is not anticipated to significantly effect the Company's financial statements.

In May 2008, the FASB issued SFAS No. 162, "The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. SFAS No. 162 directs the GAAP hierarchy to the entity, not the independent auditors, as the entity is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. SFAS No. 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to remove the GAAP hierarchy from the auditing standards. SFAS No. 162 is not expected to have a material impact on the Company’s financial statements.

In May 2008, the FASB directed the FASB Staff to issue FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) (FSP APB 14-1). FSP APB 14-1 applies to convertible debt instruments that, by their stated terms, may be settled in cash (or other assets) upon conversion, including partial cash settlement of the conversion option. FSP APB 14-1 requires bifurcation of the instrument into a debt component that is initially recorded at fair value and an equity component. The difference between the fair value of the debt component and the initial proceeds from issuance of the instrument is recorded as a component of equity. The liability component of the debt instrument is accreted to par using the effective yield method; accretion is reported as a component of interest expense. The equity component is not subsequently re-valued as long as it continues to qualify for equity treatment. FSP APB 14-1 is effective for the Company on February 1, 2009. Early adoption is not permitted. The Company is evaluating the impact of adopting FSP APB 14-1 on the Company’s financial statements.

4.Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas operations whereby all costs of exploring for and developing oil and gas reserves are initially capitalized on a country-by-country (cost center) basis. Capitalized costs, less estimated salvage value, are depleted using the units-of-production method whereby historical costs and future development costs are amortized over the total estimated proved reserves. Costs of acquiring and evaluating unproven properties and major development projects are initially excluded from the depletion and depreciation calculation until it is determined whether or not proved reserves can be assigned to such properties. These costs are assessed periodically to ascertain whether impairment has occurred (i.e., "impairment tests"). There were no impairment charges in either the first or second quarter of fiscal 2009. All of the Company’s oil and gas properties are located in the United States and Canada. The following table summarizes information regarding the Company's oil and gas acquisition, exploration and development activities:

A-35

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

(Unaudited)

			Costs									Accumulated Depletion							Net Book
	Opening $		Additions $		Dispositions $			Closing $		Opening $		Depletion $		Loss (Gain) $			Closing $		Value $
Proved Properties		12,886,510		51,625		(164,985	)		12,773,150		12,472,601		51,028		(40,710	)		12,482,919		290,231
Unproven Properties		34,397,768		1,691,966		(3,744,013	)		32,345,721		9,832,728		-		30,005			9,862,733		22,482,988
Total		47,284,278		1,743,591		(3,908,998	)		45,118,871		22,305,329		51,028		(10,705	)		22,345,652		22,773,219

Proved Properties

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

	July 31, 2008 $		January 31, 2008 $
Alberta – Canada		290,231		324,162
Barnett Shale (Texas) – United States		-		89,747
Total proved acquisition and exploration costs		290,231		413,909

In Canada, depletion and depreciation expense for the three and six month periods ended July 31, 2008 was $18,200 and $45,106 (2007 - $47,224 and $59,753), respectively.

In the U.S., depletion and depreciation expense for the three and six month periods ended July 31, 2008 was $nil and $5,922 (2007 - $89,822 and $151,435), respectively. In June 2008, the Company sold its interests in two Barnett shale wells for gross proceeds of $164,985. The net book value of the US proven property costs at the time of the sale was $131,820 and the related properties had an asset retirement obligation of $7,545. As such the Company recorded a gain on the sale of assets of $40,710.

Unproven Properties

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

	July 31, 2008 $		January 31, 2008 $
Windsor Block of Maritimes Basin (Nova Scotia)		14,083,421		15,441,144
Beech Hill Block of Maritimes Basin (New Brunswick)		63,309		21,975
Western Canadian Shale (Alberta and B.C.)		25,387		-
Canada		14,172,117		15,463,119
Fayetteville Shale (Arkansas)		8,310,871		8,289,901
Rocky Mountains (Colorado, Montana, Wyoming)		-		812,020
United States		8,310,871		9,101,921
Total unproven acquisition and exploration costs		22,482,988		24,565,040

o In Canada, $14,172,117 of unproven property costs were excluded from costs subject to depletion which relate to Canadian shale gas exploration costs mainly in the Windsor Block of the Maritimes Basin. The Company anticipates that these costs will be subject to depletion in fiscal 2011, when the Company anticipates having pipelines built and commissioned to market potential gas from the Windsor Block.

o In July 2008, the Company received cash of $2,943,510 for a partner’s share of its 30% working interest in exploration costs associated with the Windsor Block of Nova Scotia. Also, the related properties had an asset retirement obligation that was reduced by $129,884 for the partners share of its 30% working interest.

A-36

Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

(Unaudited)

o In the U.S., $8,310,871 of unproven property costs were excluded from costs subject to depletion which relate to Fayetteville Shale gas acquisition costs. The Company anticipates selling its acreage position related to these costs in fiscal 2009.

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

5.Asset Retirement Obligations

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

A reconciliation of the changes in the asset retirement obligations is as follows:

	Six Months  July 31, 2008  $			Six Months  July 31, 2007  $
Balance, beginning of period		1,003,353			90,913
Liabilities incurred		45,450			153,264
Liabilities settled as part of dispositions		(137,429	)		-
Liabilities settled in cash		(371,637	)		-
Accretion		42,539			30,837
Balance, end of period		582,276			275,014

6.Convertible Debentures

Agreement Date	December 8, 2005 $			December 28, 2005 $			Total $
Balance, January 31, 2008		4,778,271			6,770,721			11,548,992
Converted		(2,100,140	)		-			(2,100,140	)
Repaid		(4,000,000	)		-			(4,000,000	)
Accretion - expensed		815,052			1,191,348			2,006,400
Accretion - settled		506,817			-			506,817
Balance, July 31, 2008		-			7,962,069			7,962,069
Amount classified as current		-			7,962,069			7,962,069
Face value at July 31, 2008		-			10,000,000			10,000,000
Interest rate		5.0	%		7.5	%

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

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Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

(Unaudited)

7.Derivative Liabilities

The Company was required to bifurcate and separately account for the embedded conversion feature contained in the December 8, 2005 convertible debenture as a derivative. The Company was required to record the derivative at the estimated fair value on each balance sheet date with changes in fair values reflected in the statement of operations.

	Conversion Feature  Fair Value  $
January 31, 2008		3,262,846
Conversion features settled on conversion		(1,039,906	)
Change in fair value		(793,589	)
Conversion features settled on repayment		(1,429,351	)
July 31, 2008		-

The Company used 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, 2005 convertible debenture.

	Strike Price		Volatility			Risk Free Rate			Dividend  Yield		Term in  Years
Weighted Average Assumptions at:
June 3, 2008 (repayment date)	$	1.34		110.50	%		1.99	%		–		0.51

8.Common Stock

	Shares #		Common  Stock $		Additional  Paid-In Capital $
January 31, 2008		46,794,530		468		57,852,277
Private Placement, net of share issuance costs of $2,022,587		18,257,500		183		19,300,630
Conversion of debentures		2,374,013		23		3,140,023
Stock based compensation						341,036
July 31, 2008		67,426,043		674		80,633,966

During the six month period ended July 31, 2008, 2,374,013 shares were issued upon the conversion of convertible debentures in the amount of $2,100,140. The fair value of the conversion feature related to the converted debentures was $1,039,906, which was transferred from the derivative liability to additional paid-in capital upon conversion.

On June 3, 2008, 18,257,500 units were issued in a private placement for gross proceeds of $25,560,500. The net proceeds after deducting expenses was $23,537,913. The Company paid the placement agents of the offering a cash fee of 7% of the gross proceeds of the offering. Each unit was priced at $1.40 per unit and consists of one common stock (relative fair value of $19,300,630 or $1.168 per share) and one-half share purchase warrant (relative fair value of $4,237,100 or $0.232 per unit – see Note 9). One full warrant can be exercised into one share of common stock for a period of two years at a price of $2.25 per share. Pursuant to the terms of the sale, the Company was required, on a best efforts basis, to file a registration statement with the SEC, and to cause such registration statement to be declared effective by the SEC, within 150 days after closing, to permit the public resale of the shares underlying the warrants. The registration statement was declared effective by the SEC on July 14, 2008. Also, pursuant to the terms of the sale, the Company is required, on a best efforts basis, to list the Company’s shares on the Toronto Stock Exchange (which includes the TSX Venture Exchange) on or before December 31, 2008. Failure to list the shares for trading by such date results in a payment by the Company, pro rata to the purchasers, of a penalty equal to 2% of the gross proceeds of the offering for each month or partial month until the shares are listed for trading on the Toronto Stock Exchange (which includes the TSX Venture Exchange), not to exceed 10% in the aggregate.

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Triangle Petroleum Corporation

Notes to the Consolidated Financial Statements

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

(Unaudited)

9.Warrants

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

10.Stock Options

The weighted average grant date fair value of stock options granted during the three and six month periods ended July 31, 2008 was $0.4618 and $0.7018, respectively. No stock options were exercised during the three and six month periods ended July 31, 2008. During the three and six month periods ended July 31, 2008, the Company recorded stock-based compensation of $227,756 and $341,036, respectively, as general and administrative expense.

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

	Options #			Weighted Average Exercise Price $		Aggregate Intrinsic Value $
Outstanding, January 31, 2008		2,580,000			2.54
Granted		1,225,000			1.55
Forfeited		(220,000	)		3.33
Outstanding, July 31, 2008		3,585,000			2.15		-
Exercisable, July 31, 2008		1,725,000			2.56		-

The weighted average remaining contractual life of stock options outstanding as of July 31, 2008 was 3.89 years.

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

	Three Months  Ended  July 31, 2008			Six Months  Ended  July 31, 2008
Expected dividend yield		0	%		0	%
Expected volatility		80	%		79	%
Expected life (in years)		3.5			3.5
Risk-free interest rate		2.87	%		2.71	%
Estimated Forfeiture rate		30	%		30	%

As at July 31, 2008, there was $1,363,008 of total unrecognized compensation costs related to non-vested share-based compensation arrangements which are expected to be recognized over a weighted-average period of 18 months.

A summary of the status of the Company’s non-vested share options as of July 31, 2008, and changes during the six month period ended July 31, 2008, is presented below:

	Options #			Weighted-Average Grant-Date Fair Value $
Non-vested at January 31, 2008		1,250,000			0.93
Granted		1,225,000			0.70
Vested		(615,000	)		1.08
Non-vested at July 31, 2008		1,860,000			0.73

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APPENDIX "B"

FORM 51-101F2

REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR

To the board of directors of Triangle Petroleum Corporation (the "Corporation"):

1. We have evaluated the Corporation's reserves data as of July 1, 2008. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as of July 1, 2008, estimated using forecast prices and costs.

2. The reserves data are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

3. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

4. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions in the COGE Handbook.

5. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated by us for the year ended July 1, 2008, and identifies the respective portions thereof that we have evaluated and reported on to the Corporation's board of directors:

Preparation Date of	Location of Reserves (Country or Foreign		Net Present Value of Future Net Revenue (before income taxes, 10 percent discount rate)  ($MM)
Evaluation Report	Geographic Area)		Audited		Evaluated		Reviewed		Total
July 1, 2008		Canada		0		0.511		0		0.511
		USA		0		0.212		0		0.212

6. In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. We express no opinion on the reserves data that we have reviewed but did not audit or evaluate.

7. We have no responsibility to update our reports referred to in paragraph 5 for events and circumstances occurring after their respective preparation dates.

8. Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

Executed as to our report referred to above:

Ryder Scott Company Petroleum Consultants, Calgary, Alberta, Canada, Dated September 30, 2008

(signed) "Jane L. Tink, P.Eng."

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APPENDIX "C"

FORM 51-101F3

REPORT OF MANAGEMENT ON RESERVES DATA AND OTHER INFORMATION

Management of Triangle Petroleum Corporation (the "Corporation") are responsible for the preparation and disclosure of information with respect to the Corporation's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which are estimates of proved reserves and probable reserves and related future net revenue as at July 1, 2008, estimated using forecast prices and costs and the related estimated future net revenue.

An independent qualified reserves evaluator has evaluated the Corporation's reserves data. The report of the independent qualified reserves evaluator is presented in Appendix "B" to this Prospectus.

The board of directors of the Corporation has:

(a) reviewed the Corporation's procedures for providing information to the independent qualified reserves evaluator;

(b) met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and

(c) reviewed the reserves data with management and the independent qualified reserves evaluator.

The board of directors has reviewed the Corporation's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has approved:

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;

(b) the filing Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and

(c) the content and filing of this report.

Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

    (signed) "Mark G. Gustafson"

    Chief Executive Officer

    (signed) "Shaun Toker"

    Chief Operating Officer

    (signed) "Randal Matkaluk"

    Director

    (signed) "Stephen A. Holditch"

    Director

Dated September 30, 2008

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APPENDIX "D"

CHARTER - AUDIT COMMITTEE

Signature of Chairman of the Board of Directors

Date approved: October 19, 2007

Organization

There shall be a committee appointed by the Board of Directors (the “Board”) of Triangle Petroleum Corporation, a Nevada corporation (the “Corporation”), of members of the Board of Directors all of which shall be independent non-employee directors to be known as the audit committee (the “Committee”). The number of Committee members shall be as determined by the Board consistent with the Corporation’s certificate of incorporation and by-laws as the same may be amended from time to time. The Committee shall be composed of directors who are independent of the management of the Corporation and are free of any relationship that, in the opinion of the Board, would interfere with their exercise of independent judgment as a Committee member. All members of the Committee shall have a working familiarity with basic finance and accounting practices and at least one member of the Committee shall be a “financial expert” as defined by the Securities and Exchange Commission in its rules. The Committee Chair and members shall be designated annually by a majority vote of the full Board, and may be removed, at any time, with or without cause, by a majority vote of the full Board. Vacancies shall be filled by a majority vote of the full Board.

Statement of Purpose

The Committee shall provide assistance to the Board in fulfilling their responsibility to the shareholders, potential shareholders and investment community relating to corporate accounting, reporting practices of the Corporation, the quality and integrity of the financial reports of the Corporation and the Corporation’s compliance with legal and regulatory requirements. In so doing, it is the responsibility of the Committee to maintain free and open means of communication between the directors, the independent auditors and the financial management to the Corporation.

Responsibilities

In carrying out its responsibilities, the Committee believes its policies and procedures should remain flexible, in order to best react to changing conditions and to ensure to the directors and shareholders that the corporate accounting and reporting practices of the Corporation are in accordance with all requirements and are of the highest quality.

In carrying out these responsibilities, the Committee will:

· Serve as an independent and objective party to monitor the Corporation’s financial reporting process and internal control system and complaints or concerns relating thereto;

· Recommend, for shareholder approval, the independent auditor to examine the Corporation’s accounts, controls and financial statements. The Committee shall have the sole authority and responsibility to select, evaluate and if necessary replace the independent auditor. The Committee shall have the sole authority to approve all audit engagement fees and terms and the Committee, or a member of the Committee, must pre-approve any non-audit service provided to the Corporation by the Corporation’s independent auditor;

· Meet with the independent auditors and financial management of the Corporation to review the scope of the proposed audit for the current year and the audit procedures to be utilized, and at the conclusion thereof review such audit, including any comments or recommendations of the independent auditors;

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· Obtain and review at least annually, a formal written report from the independent auditor setting forth its internal quality–control procedures; material issues raised in the prior five years by its internal quality–control reviews and their resolution. The Committee will review at least annually all relationships between the independent auditor and the Corporation;

· Ensure that the lead audit partner assigned by the independent auditor as well as the audit partner responsible for reviewing the audit of the corporation’s financial statements shall be changed at least every five years;

· Review and appraise the audit efforts of independent auditors of the Corporation and, where appropriate, recommend the replacement of the independent accountants;

· Consider and approve, if appropriate, major changes to the Corporation’s accounting principles and practices as suggested by the independent auditors or management;

· Establish regular and separate systems of reporting to the Committee by management and the independent auditors regarding any significant judgements made in management’s preparation of the financial statements and the view of each as to appropriateness of such judgments and additional items as required under the Sarbanes-Oxley Act including critical accounting policies;

· Review with the independent auditors and financial accounting personnel, the adequacy and effectiveness of the accounting and financial controls of the Corporation, and elicit any recommendations for the improvement of such internal control procedures or particular areas where new or more detailed controls or procedures are desirable. Particular emphasis should be given to the adequacy of such internal controls to assess and manage financial risk exposure and to expose any payments, transactions or procedures that might be deemed illegal or otherwise improper;

· Review and approve the internal corporate audit staff functions, including (i) purpose, authority and organizational reporting lines; (ii) annual audit plan, budget and staffing; (iii) concurrence in the appointment, compensation and rotation of the internal audit management function; and (iv) results of internal audits;

· Review the financial statements contained in the annual report and quarterly report to shareholders with management and the independent auditors to determine that the independent auditors are satisfied with the disclosure and content of the financial statements to be presented to the shareholders. Any changes in accounting principles should be reviewed;

· Prepare and publish an annual Committee report in the proxy statement of the Corporation;

· Review with management of the Corporation any financial information, earnings press releases and earnings guidance filed with the Securities and Exchange Commission or disseminated to the public, including any certification, report, opinion or review rendered by the independent auditors;

· Provide sufficient opportunity for the independent auditors to meet with the members of the Committee without members of management present. Among the items to be discussed in these meetings are the independent auditors’ evaluation of the Corporation’s financial, accounting and auditing personnel, and the cooperation that the independent auditors received during the course of the audit;

· Establish procedures for receiving and treating complaints received by the Corporation regarding accounting, internal accounting controls and auditing matters, and the confidential anonymous submission by employees of concerns regarding questionable accounting or auditing matters;

· Submit the minutes of all meetings of the Committee to, or discuss the matters discussed at each Committee meeting with, the Board; and

D-2

· Investigate any matter brought to its attention within the scope of its duties, with the power to retain outside advisors for this purpose if, in its judgment, that is appropriate.

Committee Performance Evaluation

The Committee shall annually conduct an evaluation of its performance in fulfilling its responsibilities and meeting its goals, as outlined above.

Meetings

A majority of Committee members shall constitute a quorum for the transaction of business. The action of a majority of those present at a meeting at which a quorum is attained, shall be the act of the Committee. The Committee may delegate matters within its responsibility to subcommittees composed of certain of its members. The Committee shall meet in executive session without the presence of any members of management as often as it deems appropriate. The Committee shall meet as required, keep a record of its proceedings, if appropriate or needed, and report thereon from time to time to the Board.

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