10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(mark one)

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

For the fiscal year ended January 31, 2012

or

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

Commission file number 001-34945

TRIANGLE PETROLEUM CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

Nevada		98-0430762
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)
1660 Wynkoop St., Suite 900, Denver, CO	80202	(303) 260-7125
(Address of Principal Executive offices)	(Zip Code)	(Registrant’s telephone number, including area code)

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

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

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes þ No ¨      Not Required ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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

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

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

The aggregate market value of the voting common equity held by non-affiliates as of July 31, 2011, based on the closing sales price of the common stock was $320,531,418. For purposes of this computation, all officers, directors, and 5 percent beneficial owners of the registrant are deemed to be affiliates.  Such determination should not be deemed an admission that such directors, officers, or 5 percent beneficial owners are, in fact, affiliates of the registrant.

As of March 31, 2012, there were 44,154,253 shares of registrant’s common stock outstanding.

The information required to be furnished pursuant to Part III of this Form 10-K will be set forth in, and incorporated by reference from, the registrant’s definitive proxy statement for the 2012 Annual Meeting of Stockholders.

TRIANGLE PETROLEUM CORPORATION

FORM 10-K FOR THE FISCAL YEAR ENDED JANUARY 31, 2012

TABLE OF CONTENTS

		Page
Part I
Item 1.	Business	3
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	26
Item 2.	Properties	27
Item 3.	Legal Proceedings	33
Item 4.	Mining Safety Disclosures	33
Part II
Item 5.	Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
Item 6.	Selected Financial Data	35
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	43
Item 8.	Consolidated Financial Statements and Supplementary Data	44
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosures	66
Item 9A.	Controls and Procedures	66
Item 9B.	Other Information	69
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	69
Item 11.	Executive Compensation	69
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	69
Item 13.	Certain Relationships and Related Transactions, and Director Independence	69
Item 14.	Principal Accounting Fees and Services	69
Part IV
Item 15.	Exhibits; Financial Statement Schedules	70
Signatures.

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PART I

Unless the context otherwise requires, this annual report’s references to “we,” “us,” “our,” “Company” or “Triangle” refer to Triangle Petroleum Corporation (including its subsidiaries). Throughout this annual report, we make statements that may be classified as “forward looking.” At the end of Item 1, we provide an explanation of the term forward looking statements, followed by a glossary of oil and natural gas terms used in this annual report. Our fiscal year end is January 31^st. The terms fiscal year 2012 and fiscal year 2011 herein refers to the fiscal years ended January 31, 2012, and 2011, respectively.

ITEM 1.  BUSINESS

OVERVIEW

We are an exploration and production company currently focused on the development of unconventional shale oil and natural gas resources in the Bakken Shale and Three Forks formations in the Williston Basin of North Dakota and Montana. As of January 31, 2012, we owned approximately 83,000 net acres primarily in McKenzie and Williams Counties of North Dakota and Roosevelt and Sheridan Counties of Montana. Having identified an area of focus in the Bakken Shale and Three Forks formations that we believe will generate attractive returns on invested capital, we are continuing to explore further opportunities in the region. Our proved oil and natural gas reserves as of January 31, 2012 totaled 1,477,091 Boe. Our daily production for fiscal year 2012 averaged approximately 306 Boepd, with an average daily production in January 2012 of approximately 530 Boepd from non-operated wells (i.e., not operated by us, but by third parties). All production in fiscal year 2012 is from wells in North Dakota, primarily from the Bakken Shale formation and the rest from the Three Forks formation.

We commenced drilling of our first operated well in October 2011. As of April 10, 2012, we had nearly finished drilling our fourth operated well. Over a five week period beginning on April 23, 2012, subject to the weather and other external uncontrollable factors, we expect to complete and place on production our first four gross (1.8 net) operated wells. By January 31, 2013, we anticipate having drilled and completed at least 15 gross (6.8 net) operated, horizontal wells -- all in North Dakota or eastern Montana, for completion in the Bakken Shale or Three Forks formations.

In the core area of North Dakota and eastern Montana, Triangle is directing resources toward its operated program to develop its approximately 30,000 net acres, primarily in McKenzie and Williams County, North Dakota. In Roosevelt County, Montana, our “Station Prospect” is a largely contiguous position within the thermally mature area of the Williston Basin. Our approximate 53,000 net acre position in the Station Prospect is predominantly operated acreage with an average remaining lease term of four years and provides us with a development area that we believe is scalable for the future.

With a focus on establishing an efficient development model, the company is utilizing pad drilling, which expedites our operated program, while controlling costs and minimizing environmental impact. We also intend to use innovative completion, collection and production techniques to optimize reservoir production while also reducing costs. Additionally, with the ability to utilize the completion capacity of RockPile Energy Services, LLC, our majority-owned subsidiary ("RockPile"), we are positioned to lower implied production cost and have greater control over drilling and completion schedules.

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Our Strategy

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

• Focus on the Williston Basin. We believe the Bakken Shale and Three Forks formations in the Williston Basin represent one of the largest oil deposits in North America. A report issued by the United States Geological Survey in April 2008 classified these formations as the largest continuous oil accumulation ever assessed in the contiguous United States. North Dakota’s Industrial Commission reported in January 2012 that the state had surpassed 545,000 barrels of oil production per day, making it the third-largest oil-producing state in the nation. We believe that the Williston Basin is still in the very early stages of what may be a 20+ year development program. We expect to continue to pursue additional leasehold positions where our geologic model suggests the Bakken Shale and/or the Three Forks formations are believed to be prospective. We believe horizontal wells drilled on our acreage will generate attractive returns on invested capital given our outlook for the price of oil and the exploration and development costs associated with converting the acreage from resource potential to proven and producing reserves.

• Continue to pursue leasehold acquisitions at attractive costs. We believe significant additional acreage in the Williston Basin, prospective for the Bakken Shale and Three Forks formations, is and will be available for acquisition, allowing us to reach our long-term goal of 100,000 net acres, subject to availability of attractive sources of financing. We believe many of the active operators in the area have assembled sizeable leasehold positions and have shifted from a leasehold acquisition strategy to a development strategy. We plan to explore various techniques to add predominantly operated acreage, including (i) participating in state and federal lease sales, (ii) pursuing leasehold acquisitions, (iii) entering into farm-in agreements with existing operators, (iv) pursuing farm-in opportunities on lease positions that are about to expire and (v) executing acreage trades with other operators in the Williston Basin.

• Focus leasehold efforts on converting non-operated to operated acreage. Through our non-operated positions, we intend to continue to broaden our operating experience by teaming with operators that we believe are some of the most active and knowledgeable in the Williston Basin. We believe that this approach also provides significant opportunities to expand our collective acreage position. Often a smaller non-operated position can grow into an operated position via further acquisition or acreage trades. As such, we have significantly expanded our operated leasehold positions and are now, or are expecting to be, the operator on approximately 9,600 of our approximately 30,000 core-area net acres in North Dakota and eastern Montana and on approximately 36,000 of our approximately 55,000 Station Prospect net acres in Montana.

• Maximize efficiencies and lower costs within our operated units. We intend to use a multi-well pad design in order to more efficiently drill and reduce completion time and cost. We believe a multi-well pad design increases our oil recovery factor by increasing reservoir-stimulated rock volume. Using a rig’s skid system to move between wells on a pad will lower mobilization costs. Applying zipper-fracture techniques via batch completions is likely to optimize reservoir stimulation and decrease completion time. We intend to condense and centralize production equipment and infrastructure to single locations on co-located drilling units in order to reduce equipment required on a per well basis and reduce production costs. We believe that all of the above activities minimize total site cost and truck movements, thus reducing surface and environmental footprint and increasing overall safety.

Our Competitive Strengths

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

• We benefit from the increasing activity in the Bakken Shale and Three Forks formations acreage. Activity levels in the Williston Basin continue to increase with a drilling rig count of 212 at March 1, 2012 versus 162 at April 1, 2011. We benefit from the increasing number of wells drilled and the corresponding data available from public sources, including the North Dakota Industrial Commission. This activity and data has begun to define the geographic extent of the Bakken Shale and Three Forks formations, which we believe reduces the amount of risk we face on future leasehold acquisitions and development operations. In addition, the leading operators in the Williston Basin have developed drilling and completion technologies that have significantly reduced production risk, decreased per unit drilling and completion costs and enhanced returns.

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

• Experienced and capable management and operations team with history of proven success. Dr. Peter Hill, our Chief Executive Officer, has 40 years of oil and natural gas experience, including over 20 years with British Petroleum in a variety of roles including Chief Geologist, Chief of Staff for BP Exploration, President of BP Venezuela and Regional Director for Central and South America. Jon Samuels, our President and Chief Financial Officer joined the Company in December 2009, after over five years as a member of an energy focused investment management firm. Over the past year, Triangle has assembled a seasoned operations team with significant Bakken experience. Our Subsurface Manager has over 30 years of experience, including years of exploring and mapping the Williston Basin. Our Operations Manager has over 23 years of experience, with recent years related to horizontally drilling and completing wells in the Williston and other basins. Our Reservoir Engineer, our Vice President of Land and our Vice President of Accounting each have over 30 years’ experience with U.S. oil and gas exploration and production, including recent years of Bakken experience prior to joining Triangle Petroleum.

• We have a healthy balance sheet. As of January 31, 2012, we had approximately $69.6 million in cash, other current assets of approximately $10.0 million and current liabilities of $20.1 million.

Operations and Oil and Natural Gas Properties

Williston Basin

We own operated and non-operated leasehold positions in the Williston Basin. We commenced drilling of our first operated well in October 2011. As of April 10, 2012, we had nearly finished drilling our fourth operated well. Over a five week period beginning on April 23, 2012, subject to the weather and other external uncontrollable factors, we expect to complete and place on production our first four gross (1.8 net) operated wells.

Triangle is currently running a 1+ rig drilling program, meaning one rig, the Xtreme 7, is contracted full-time and drilling approximately one well per month. We have temporarily contracted a second rig, Pioneer 42, to drill two to three wells during a three-month window, between April and July 2012. The focus of our near-term drilling program is on our core North Dakota acreage in McKenzie and Williams Counties. RockPile is expected to be available for completions starting in July 2012. Triangle will explore expanding the drilling program and number of rigs under management upon the availability of attractive funding sources.

Our non-operated leasehold positions are primarily conducted through agreements with major operators in the Williston Basin, including Hess Corporation (“Hess”), Continental Resources, Inc. (“Continental”), Statoil (formerly Brigham Exploration Company) (“Statoil”), Newfield Production Co. (“Newfield”), EOG Resources, Inc. (“EOG”), XTO Energy Inc. (now a part of ExxonMobil) (“XTO”), Whiting Petroleum Corporation (“Whiting”), Slawson Exploration, Inc. (“Slawson”), and Kodiak Oil and Gas Corporation (“Kodiak”). These companies are experienced operators in the development of the Bakken Shale and Three Forks formations. As of March 31, 2012, we have participated in the drilling of 101 gross non-operated wells, including 66 producing wells and 35 wells in various stages of permitting, drilling or completion.

Using industry accepted well-spacing parameters and long lateral well bores, we believe that there could be over 75 operated drill spacing units and over 450 well locations for the Bakken Shale and Three Forks formations on our acreage in the Williston Basin. Based on current industry expectations, we believe we can drill six to eight 9,500+ foot lateral wells on 1,280 acre spacing units within our acreage. Consistent with leading field operators, we plan to perform multi-stage fracs, with 25 to 30 stages on each lateral well. We also plan to drill shorter lateral wells on smaller units as dictated by our leasehold position. Separately, we have approximately 120 non-operated drill spacing units with greater than 2% working interest in our core area of North Dakota and Montana.

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Other Properties

We have an 87% working interest in approximately 474,625 gross acres (approximately 412,924 net acres) of Nova Scotia oil and natural gas leases in the Windsor Sub-Basin of the Maritimes Basin. The leases are to expire in 2019, but can be extended pending agreement of further development plans with the Nova Scotia regulators. Nova Scotia is currently conducting an extensive hydraulic fracturing review to determine whether and how hydraulic fracturing will be allowed in the future. The review is expected to be completed in calendar year 2012. Nova Scotia also does not currently allow the common industry practice of using salt water disposal wells. While such government restrictions remain in place, it is uneconomic to proceed in further exploration and development of these leases. We do not know if and when the restrictions might be lifted, and we do not know if Nova Scotia would grant an extension to the leases due to Nova Scotia’s existing hydraulic fracturing review. As of January 31, 2012, we have fully impaired and expensed the $4.4 million carrying value of our oil and natural gas leases in the Maritimes Basin.

Pricing and Marketing of Oil and Natural Gas

Substantially all of our sales of crude oil, natural gas and natural gas liquids in fiscal years 2012 and 2011 were sold (i) through arrangements made by the wells’ operators and (ii) at sales points at or close to the producing wells. We have the right to take and sell our proportionate share of production, rather than have the operator arrange such sale; however, we did not do so in fiscal years 2012 and 2011. The operators collect the sales proceeds and pass on to us our proportionate share of sales, net of severance taxes and royalties paid either by the purchaser or the operator on our behalf. In the U.S., sales of produced crude oil, natural gas and natural gas liquids are not regulated and are made at negotiated prices.

Major Customers

For fiscal 2012 and fiscal 2011, we relied on our operating partners to market and sell our production. Our operating partners include a variety of exploration and production companies, from large publicly-traded companies to small, privately-owned companies. We do not believe the loss of any single operator’s customer would have a material adverse effect on our company as a whole.

We are currently in discussions with several companies as to their expressed interest in transporting or purchasing the oil and/or natural gas to be produced from our first five operated wells.

Royalties and Incentives

Royalty Regimes are a significant factor in the profitability of oil, natural gas and natural gas liquids production. In the U.S., all royalties are determined in the lease agreements between the mineral rights owner (the lessor) and the oil and natural gas exploration and Production Company (the lessee). For our production in the Williston Basin for fiscal years 2011 and 2012, we typically paid royalties and overriding royalties, which in total ranged from 17% to 21% of our pre-royalty revenues for a particular well.

Competitors

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

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Governmental Regulation

Our business is affected by numerous laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the oil and natural gas industry. Failure to comply with any laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on business. In view of the many uncertainties with respect to future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

We believe that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive an effect on our operations than on other similar companies in the oil and natural gas industry.

Environmental Laws and Regulations

United States

Like the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state and local laws and regulations designed to protect and preserve natural resources and the environment. The recent trend in environmental legislation and regulation in the oil and natural gas industry is generally toward stricter standards, and this trend is likely to continue. These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, especially in wilderness areas and areas with endangered or threatened plant or animal species; impose restrictions on construction, drilling and other exploration and production activities; regulate air emissions, wastewater and other production and waste streams from our operations; impose substantial liabilities for pollution that may result from our operations; and require the reclamation of certain lands.

The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, compliance orders, and other enforcement actions. We are not aware of any material noncompliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements; however, given the complex regulatory requirements applicable to our operations, and the rapidly changing nature of environmental laws in our industry, we cannot predict our future exposure concerning such matters, and our future costs to achieve compliance, or remedy potential violations, could be significant. Our operations require permits and are regulated under environmental laws, and current or future noncompliance with such laws, as well as changes to existing laws or interpretations thereof, could have a significant impact on us, as well as the oil and natural gas industry in general.

Waste Disposal and Contamination Issues

The federal Comprehensive Environmental Response, Compensation and Liability Act and comparable state laws may impose strict and joint and several liability on owners and operators of contaminated sites and on persons who disposed of or arranged for the disposal of hazardous substances found at such sites. Under these and other laws, the government, neighboring landowners and other third parties may recover the costs of responding to soil and groundwater contamination and threatened releases of hazardous substances, and seek recovery for related natural resources damages, personal injury and property damage. Some of our properties have been used for exploration and production activities for a number of years by third parties, and such properties could result in unknown cleanup liabilities for us.

The federal Resource Conservation and Recovery Act (the “RCRA”) and comparable state statutes govern the management, storage, treatment and disposal of solid waste and hazardous waste and authorize imposition of substantial fines and penalties for noncompliance. Although RCRA classifies certain of our oil field wastes as “non-hazardous” (for example, the waters produced from hydraulic fracturing operations), such wastes could be reclassified as hazardous wastes in the future, thereby making them subject to more stringent handling and disposal requirements which could have a material impact on us.

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Water Regulation

The federal Clean Water Act (the “CWA”), the federal Safe Drinking Water Act (the “SWDA”) and analogous state laws restrict the discharge of wastewater and other pollutants into surface waters or underground wells and the construction of facilities in wetland areas without a permit. Federal regulations also require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters. In addition, the Oil Pollution Act (the “OPA”) contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. For onshore and offshore facilities that may affect waters of the United States, the OPA requires an operator to demonstrate financial responsibility. Regulations are currently being developed or considered under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on us.

These and similar state laws also govern the management and disposal of produced waters from our extraction process. Currently, wastewater associated with oil and natural gas production from shale formations is prohibited from being directly discharged to waterways and other waters of the U.S. While some of our wastewater is reused or re-injected, a significant amount still requires disposal. As a result, some wastewater is transported to third-party treatment plants. In October 2011, citing concerns that third-party treatment plants may not be properly equipped to handle wastewater from shale gas operations, the United States Environmental Protection Agency (the “EPA”) announced that it will consider federal pre-treatment standards for these wastewaters. We cannot predict the EPA’s future actions in this regard, but future regulation of our produced waters or other waste streams could have a material impact on us.

Air Emissions And Climate Change

The federal Clean Air Act (“CAA”) imposes permit requirements and operational restrictions on certain sources of emissions used in our operations. In July 2011, the EPA published proposed New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAPs”) that would, if adopted, amend existing NSPS and NESHAP standards for oil and natural gas facilities and create new NSPS standards for oil and natural gas production, transmission and distribution facilities. Importantly, these standards would include standards for hydraulically fractured wells, which are widely used in our operations. The standards would apply to newly drilled and fractured wells as well as existing wells that are refractured. A court has directed the EPA to issue final rules by April 3, 2012. In a report issued in late 2011, the Shale Gas Production Subcommittee of the Department of Energy (the “DOE Shale Gas Subcommittee”) called on the EPA to complete the rulemaking quickly and recommended expanding the shale gas emission sources to be covered by the new rules. The DOE Shale Gas Subcommittee also encouraged states to take similar action, and included several other recommendations for studying and reducing air emissions from shale gas production activities. Because the EPA’s regulations have not yet been finalized, we cannot at this time predict the impact they may have on our financial condition or results of operation.

The issue of climate change has received increasing regulatory attention in recent years. The EPA has issued regulations governing carbon dioxide, methane and other greenhouse gas (“GHG”) emissions citing its authority under the CAA. Several of these regulations have been challenged in litigation that is currently pending before the federal D.C. Circuit Court of Appeals. In December 2011, the EPA issued amendments to a final rule issued in 2010 requiring reporting of GHG emissions from the oil and natural gas industry. Under this rule, we are obligated to report to the EPA certain GHG emissions from our operations. We do not expect that the costs of this new reporting will be material to us. In a late 2011 report, the DOE Shale Gas Subcommittee recommended that the EPA expand reporting requirements for GHG emissions from shale gas emission sources, and include methane in reporting requirements. More generally, several proposals to regulate GHG emissions have been proposed in the U.S. Congress, and various states have taken steps to regulate GHG emissions. The adoption and implementation of regulations or legislation imposing restrictions or other regulatory obligations on emissions of GHGs from oil and natural gas operations could require us to obtain permits or allowances for our GHG emissions, install new pollution controls, increase our operational costs, limit our operations or adversely affect demand for the oil and natural gas produced from our lands.

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Regulation of Hydraulic Fracturing

Our industry uses hydraulic fracturing to recover oil and natural gas in deep shale and other previously inaccessible subsurface geological formations. Hydraulic fracturing (or “fracking”) is a process to significantly increase production in drilled wells by creating or expanding cracks, or fractures, in underground formations by injecting water, sand and other additives into formations at high pressures. Like others in our industry, we use this process as a means to increase the productivity of our wells. Although hydraulic fracturing has been an accepted practice in the oil and natural gas industry for many years, its use has dramatically increased in the last decade, and concerns over its potential environmental effects have received increasing attention from regulators and the public.

Under the Safe Drinking Water Act (“SDWA”), the EPA is prohibited from regulating the injection of fracking fluids through its underground injection control program, except in limited circumstances (for example, the EPA has asserted that it has authority to regulate when diesel is a component of the fluids). Waters produced from fracking operations must be disposed of in accordance with federal and state regulations. As discussed above, the EPA has announced an intention to propose pre-treatment standards for produced waters that are to be disposed of at third-party wastewater treatment plants. Separately, the EPA is studying the effects of fracking on drinking water as a result of Congressional and public concern over fracking’s potential to impact groundwater supplies, and the EPA has indicated that it expects to issue its findings later this year.

In that regard, the EPA recently issued a study indicating that contamination may have resulted from certain fracking operations in Wyoming. The operator of the wells has challenged the EPA’s findings, contending that other activities may be to blame for contaminated groundwater in the area, but the EPA’s findings can be expected to draw increased attention to potential groundwater impacts from fracking. In late 2011, the DOE Shale Gas Subcommittee recommended further study and coordination of federal, state and local efforts to determine and monitor potential groundwater impacts from fracking activities.

Other federal agencies, including the DOE and the Department of Interior, and the U.S. Congress are also investigating the potential impacts of fracking. In addition, bills have been introduced in the U.S. Congress to amend the SWDA to allow the EPA to regulate the injection of fracking fluids, which could require our and similar operations to meet federal permitting and financial assurance requirements, adhere to certain construction and testing specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. In addition, the federal Bureau of Land Management is developing draft regulations that would require companies drilling on federal land to disclose details of chemical additives, test the integrity of wells and report on water use and waste management. In November 2011, the EPA announced that it would solicit public input on possible reporting requirements for chemicals used in fracking under the authority of the federal Toxic Substances Control Act.

States, which traditionally have been the primary regulators of exploration and production wells, are also considering or have recently adopted, or may in the future adopt, additional regulations governing fracking activities. For example, North Dakota recently adopted regulations, effective April 1, 2012, to require disclosure of the chemical components of hydraulic fracturing fluids. We believe that compliance with these new reporting requirements will not have a material adverse impact on us. Nonetheless, these disclosures could make it easier for third parties who oppose fracking to initiate legal proceedings based on allegations that chemicals used in fracking could contaminate groundwater. North Dakota also recently amended its current regulations to require additional pollution control equipment and emergency response procedures for fracking operations, as well as other measures designed to minimize impacts on the environment. We believe that compliance with these additional requirements will not have a material impact on us.

In addition, concerns have been raised about the potential for fracking to cause earthquakes through the disposal of produced waters into Class II underground injection control (“UIC”). The EPA’s current regulatory requirements for such wells do not require the consideration of seismic impacts when issuing permits. Some environmentalists have asked the EPA to consider reversing an exemption that excludes such wastewaters from hazardous waste rules, which would subject the wastes to more stringent management and disposal requirements. We cannot predict the EPA’s future actions in this regard. Certain states, such as Ohio, where earthquakes have been alleged to be linked to fracking activities, have proposed regulations that would require mandatory reviews of seismic data and related testing and monitoring as part of the future permitting process for UIC wells. In addition, certain other states, including New York, New Jersey and Vermont have sought to place moratoria on fracking or subject it to more stringent permitting and well construction and testing requirements. As discussed elsewhere, Nova Scotia, where we own oil and natural gas properties, is currently evaluating how fracking should be regulated.

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Canada

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

Nova Scotia is currently undergoing a hydraulic fracturing review that is examining the potential impacts of hydraulic fracturing in oil and gas operations. The review is expected to be completed in the 2012 calendar year. Nova Scotia also does not currently allow the common industry practice of using salt water disposal wells.

Neither the government of Canada nor Nova Scotia has implemented GHG legislation and regulations, and it is unclear how and when they will do so. The implementation of any such regulations could affect the value of our oil and natural gas leases in the Maritimes Basin of Nova Scotia and, should we decide to develop those leases, could affect our operations and costs.

Formation

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

Employees

As of March 31, 2012, we had 61 full time employees (including 32 employed by RockPile). We consider our relations with our employees to be good.

Offices

We maintain our principal office at 1660 Wynkoop St., Suite 900, Denver, Colorado, 80202.  Our telephone number is (303) 260-7125 and our facsimile number is (303) 260-5080. Our current office space consists of approximately 9,144 square feet in our 1660 Wynkoop office, 2,370 square feet in our 1625 Broadway office and 2,475 square feet in our Calgary, Alberta office.  The 1625 Broadway lease runs until September 2013 and is currently subleased by RockPile. The Calgary, Alberta lease runs until September 2013 and is subleased to an unrelated entity. The 1660 Wynkoop lease began on April 18, 2011 and runs through July 2015. Monthly rental payments under the leases are $4,816 for the 1625 Broadway office, $19,812 for the 1660 Wynkoop and Cdn $6,460 for the Calgary, Alberta office.

Research and Development

As an oil and natural gas exploration and production company, we do not normally engage in research and product development activities, and we had no research and development expenditures in the last two fiscal years.

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Legal Proceedings

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

Reports to Security Holders

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

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

The practice of preparing production and reserve quantities data under NI 51-101 differs from the U.S. Rules. The primary differences between the two reporting requirements include: (i) NI 51-101 requires disclosure of proved and probable reserves and the U.S. Rules require disclosure of proved reserves and now allow for disclosure of probable reserves; (ii) NI 51-101 requires the use of forecast prices in the estimation of reserves and the U.S. Rules require the use of 12-month average historical prices which are held constant; (iii) NI 51-101 requires disclosure of reserves on a gross (before royalties) and net (after royalties) basis and the U.S Rules require disclosure on a net (after royalties) basis; and (iv) the Canadian standards require disclosure of production on a gross (before royalties) basis and the U.S. Rules require disclosure on a net (after royalties) basis.

Forward-Looking Statements

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

· history of losses and any future performance;

· drilling results;

· results of acquisitions;

· our relationships with our partners;

· our ability to acquire additional leasehold interests or other oil and natural gas properties;

· our ability to manage growth in our business;

· our ability to control properties we do not operate;

· our ability to protect against certain liabilities associated with our properties;

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· lack of diversification;

· substantial capital requirements and access to additional capital;

· our plans for RockPile;

· competition in the oil and natural gas industry;

· global financial conditions;

· oil and natural gas realized prices;

· seasonal weather conditions;

· marketing and distribution of oil and natural gas;

· the influence of our significant stockholders;

· government regulation of the oil and natural gas industry;

· potential regulation affecting hydraulic fracturing;

· environmental regulations, including climate change regulations;

· uninsured or underinsured risks;

· defects in title to our oil and natural gas interests;

· material weaknesses in our internal accounting controls; and

· foreign currency exchange risks.

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

GLOSSARY OF ABBREVIATIONS AND TERMS

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

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

AMI. Area of mutual interest.

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

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

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

Boepd. Boe per day.

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

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

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

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

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

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

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

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

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

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

Mboe. Thousand stock tank barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

Mcf. Thousand cubic feet of natural gas.

Mcfpd. Mcf per day.

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

Mmcf. Million cubic feet of natural gas.

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

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

Non-operated acreage. Lease acreage owned by the Company for which another oil and natural gas company serves or is expected to serve as the Operator of the wells to be drilled and completed. The oil and natural gas company with the largest working interest in a proposed well usually serves as that well’s Operator who oversees the well operations on behalf of all the well’s working interest owners.

Operated acreage. Lease acreage owned or controlled by the Company and to be developed with the Company serving as Operator of the wells to be drilled and completed.

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

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

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

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

Proved properties. Properties with proved reserves.

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

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

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

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

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

Unproved properties. Properties with no proved reserves.

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

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

ITEM 1A.  RISK FACTORS

You should carefully consider the following risk factors and all other information contained in this annual report in evaluating our business and prospects. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties, other than those we describe below, that are not presently known to us or that we currently believe are immaterial, may also impair our business operations. If any of the following risks occur, our business and financial results could be harmed. You should also refer to the other information contained in this annual report, including the Forward-Looking Statement section in Item 1, our consolidated financial statements and the related notes and “ Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for a further discussion of the risks, uncertainties and assumptions relating to our business.

Risks Relating to Our Business

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

We incurred net losses attributable to common stockholders of $23,832,355 and $20,277,197 for the fiscal years ended January 31, 2012 and 2011, respectively. We cannot assure you that we can achieve or sustain profitability on a quarterly or annual basis in the future. Our operations are subject to the risks and competition inherent in the oil and natural gas industry. We cannot assure you that future operations will be profitable. Revenues and profits, if any, will depend upon various factors, including whether we will be able to expand our revenues. We may not achieve our business objectives, and the failure to achieve such goals would have an adverse impact on our business, financial condition and result of operations.

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

An investment in us should be considered speculative due to the nature of our involvement in the exploration for, and the acquisition, development and production of, oil and natural gas. Oil and natural gas operations involve many risks, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that commercial quantities of oil or natural gas will be discovered or acquired by us or, even if discovered or acquired, that any such reserves would be economically recoverable. Further, any changes in the regulations to which our business is subject, including those related to the hydraulic fracturing production method, could also have a material adverse effect on our business, financial condition, results of operations or prospects.

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

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

We may have to limit our exploration and development activity, which may result in a loss of investment.

We have a relatively small asset base and limited access to additional capital. Due to our brief operating history and historical operating losses, our operations to date have not been a source of liquidity. We expect significant cash requirements during fiscal year 2013 for our well drilling and completion programs, potential land acquisitions and overhead and working capital purposes. We cannot assure you that we will have, or be able to obtain, sufficient capital to complete our planned exploration and development programs. If additional financing is not available, or is not available on acceptable terms, we will have to curtail our operations, and investors may lose some or all of their investment.

We may not adhere to our proposed drilling schedule.

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

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

· economic and industry conditions at the time of drilling;

· prevailing and anticipated prices for oil and natural gas;

· the availability of sufficient capital resources;

· the results of our well drilling and completion programs;

· the acquisition, review and interpretation of seismic data; and

· our ability to obtain permits for drilling locations.

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

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

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

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

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

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

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

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

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

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

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

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

Certain United States federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.

On September 12, 2011, President Obama sent to Congress a legislative package that included proposed legislation that, if enacted into law, would eliminate certain key United States federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, among other proposals:

· the repeal of the limited percentage depletion allowance for oil and natural gas production in the United States;

· the replacement of expensing intangible drilling and development costs in the year incurred with an amortization of those costs over several years;

· the elimination of the deduction for certain domestic production activities; and

· an extension of the amortization period for certain geological and geophysical expenditures.

It is unclear whether these or similar changes will be enacted. The passage of this legislation or any similar changes in federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to U.S. oil and natural gas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

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

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

Our agreements with operators and other joint venture partners as well as other operational agreements that we may enter into, present a number of challenges that could have a material adverse effect on our business, financial condition or results of operations.

Our agreements with well operators and other joint venture partners, as well as other operational agreements (including agreements with mineral rights owners and suppliers of services, equipment and product transportation), represent a significant portion of our business. In addition, as part of our business strategy, we plan to enter into other similar transactions, some of which may be material. These transactions typically involve a number of risks and present financial, managerial and operational challenges, including the existence of unknown potential disputes, liabilities or contingencies that arise after entering into these arrangements related to the counterparties to such arrangements. We could experience financial or other setbacks if such transactions encounter unanticipated problems, including problems related to execution or integration. Any of these risks could reduce our revenues or increase our expenses, which could adversely affect our business, financial condition or results of operations.

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We depend on the successful acquisition, exploration and development of oil and natural gas properties to develop any future reserves and grow production and revenue in the future.

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

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

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

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

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

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

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

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

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

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

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

We follow the full cost method of accounting for oil and natural gas properties. Accordingly, all costs associated with the acquisition, exploration and development of oil and natural gas properties, including costs of undeveloped leasehold, geological and geophysical expenses, dry holes, leasehold equipment and other costs directly related to acquisition, exploration and development activities, are capitalized. Capitalized costs of oil and natural gas properties also include estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. The capitalized costs plus future development and dismantlement costs are depleted and charged to operations using the equivalent unit-of-production method based on proved oil and natural gas reserves as determined annually by our independent petroleum engineers and determined in the interim quarterly periods by an experienced petroleum engineer on our staff. To the extent that such capitalized costs, net of their accumulated depreciation and amortization, exceed the sum of (i) the present value (discounting at 10% per annum) of estimated future net revenues from proved oil and natural gas reserves and (ii) the capitalized costs of unevaluated properties (both adjusted for income tax effects), such excess costs are charged to operations, which may have a material adverse effect on our business, financial condition and results of operations. We have recognized such impairment expense in each of the past two fiscal years. Once incurred such a write-down of oil and natural gas properties is not reversible at a later date, even if oil or natural gas prices substantially increase or if estimated proved reserves substantially increase.

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

We currently do not operate most of the properties in which we have an interest; however, we currently control and intend to operate 52.5% of our acreage. As a result, we have limited ability to exercise influence over, and control the risks associated with, operations of our non-operated properties. The failure of an operator of our non-operated wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology.

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

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

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

We encounter competition from other oil and natural gas companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies and individuals. Many of our competitors have been engaged in the oil and natural gas business much longer than we have and possess substantially larger operating staffs and greater capital resources than us. These companies may be able to pay more for exploratory projects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry, particularly in the Bakken Shale and Three Forks formations in which we focus. Such competitors may also be in a better position to secure oilfield services and equipment on a timely basis or on more favorable terms, particularly in light of the equipment and personnel shortages in the areas in which we focus. We may not be able to conduct our operations, evaluate and select suitable properties and consummate transactions successfully in this highly competitive environment, which could adversely affect our business, financial condition, results of operations and prospects.

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

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

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

The potential profitability of oil and natural gas properties is dependent upon many factors beyond our control. For instance, world prices and markets for oil and natural gas are unpredictable, highly volatile, potentially subject to governmental fixing, pegging, controls or any combination of these and other factors, and respond to changes in domestic, international, political, social and economic environments. Additionally, due to worldwide economic uncertainty, the availability and cost of funds for production and other expenses have become increasingly difficult, if not impossible, to project. These changes and events may materially affect our financial performance. In addition, a productive well may become commercially unproductive in the event that water or other deleterious substances are encountered which impair or prevent the commercial production of oil and/or natural gas from the well. These factors cannot be accurately predicted and the combination of these factors may result in us not receiving an adequate return on invested capital, which could adversely affect the value of our common stock.

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

Our revenues, operating results and future rate of growth depend highly upon the prices we receive for our oil and natural gas production. The markets and prices for oil and natural gas depend on numerous factors beyond our control. These factors include demand for oil and natural gas, which fluctuate with changes in market and economic conditions, and other factors, including:

· worldwide and domestic supplies of oil and natural gas;

· actions taken by foreign oil and natural gas producing nations;

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

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

· the price and level of foreign imports;

· the level of consumer demand;

· the price and availability of alternative fuels;

· the availability of pipeline or other takeaway capacity;

· weather conditions;

· terrorist activity;

· new recovery technology developments;

· new recoverable discoveries;

· domestic and foreign governmental regulations and taxes; and

· the overall worldwide and domestic economic environment.

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

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

· reduce our revenues, operating income and cash flow;

· limit our access to sources of capital; and

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

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

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

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

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

Our operations could be adversely affected by weather conditions. In the Williston Basin, drilling and other oil and natural gas activities cannot be conducted as effectively during the winter months. Winter and severe weather conditions limit and may temporarily halt the ability to operate during such conditions. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and state transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. These constraints and the resulting shortages or high costs could delay or temporarily halt our oil and natural gas operations and materially increase our operating and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

If we are unable to retain or recruit qualified managerial, operations and field personnel, we may not be able to continue our operations.

Our success depends to a significant extent upon the continued services of our directors and officers and that of key managerial, operational, land, finance and accounting staff. We have not and do not expect to obtain key man insurance on directors, officers or any key personnel. In addition, in order to successfully implement and manage our business plan, we will be dependent upon, among other things, successfully recruiting qualified managerial and field personnel having experience in the required aspects of our oil and natural gas exploration business. Competition for qualified individuals is intense. We cannot assure you that we will be able to retain existing employees or that we will be able to find, attract and retain qualified personnel on acceptable terms.

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

Oil and natural gas operations are subject to federal, state, and local laws relating to the protection of the environment, including laws regulating removal of natural resources from the ground and the discharge of materials into the environment. Oil and natural gas operations are also subject to federal, state and local laws and regulations which seek to maintain health and safety standards by regulating the design and use of drilling methods and equipment. Various permits from government authorities are required for drilling operations to be conducted and no assurance can be given that such permits will be received. The failure or delay in obtaining the requisite approvals or permits may adversely affect our business, financial condition and results of operations.

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

Recently there has been increasing public and regulatory attention focused on the potential environmental impact of hydraulic fracturing (or “fracking”) operations. This process, which involves the injection of water, sand and certain additives deep underground to release natural gas, natural gas liquids and oil deposits, is central to our operations and future regulation of these activities could have a material adverse impact on our business, financial condition and results of operations.

Various government agencies, political representatives and public interest groups have raised concerns about the potential for fracking to lead to groundwater contamination, and various regulatory and legislative measures have been proposed or adopted at the federal, state and local level to study or monitor related concerns, to regulate well operations and related production and waste streams, or to ban fracking entirely. For example, various states and federal regulatory authorities require or are considering requiring public disclosure of the chemicals contained in fracking fluids, and testing and monitoring obligations relating to well integrity and operation. North Dakota, a state in which we conduct operations, recently amended its current regulations to require additional pollution control equipment at well sites and enhanced emergency response procedures in addition to other measures designed to reduce potential environmental impacts. In 2011, the EPA announced its intention to consider pre-treatment standards for produced waters that are sent to third party wastewater treatment plants.

In addition, bills have been proposed in the U.S. Congress to allow the EPA to regulate the injection of fracking fluids under the federal Safe Drinking Water Act, which could require hydraulic fracturing operations to meet federal permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The proposed legislation also would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, in light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are considering additional requirements related to seismic safety. Other concerns have been raised regarding water usage, air emissions (including greenhouse gas emissions) and waste disposal, and certain jurisdictions have imposed moratoria on fracking operations while the potential impacts are studied. The EPA, Congress and other government representatives continue to investigate the impacts of fracking, and additional studies and regulatory or legislative initiatives are possible. See “Item 1 – Business Overview – Environmental Laws and Regulations” for further discussion of applicable environmental laws.

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

The sale of our oil and natural gas production depends in part on gathering, transportation and processing facilities. Any limitation in the availability of, or our access to, those facilities would interfere with our ability to market the oil and natural gas that we produce and could adversely impact our drilling program, cash flows and results of operations.

We deliver oil and natural gas through gathering, processing and pipeline systems that we do not own. The amount of oil and natural gas that we can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering, processing and pipeline systems. In particular, natural gas produced in the Bakken has a high Btu content that requires gas processing to remove the natural gas liquids before it can be redelivered into transmission pipelines. Industry-wide in the Williston Basin, there is currently a shortage of gas gathering and processing capacity. Such shortage has limited our ability to sell our gas production. As a result, the majority of our gas from the Bakken wells to date has been flared.

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The lack of availability of capacity in any of the gathering, processing and pipeline systems, and in particular the processing facilities, could result in our inability to realize the full economic potential of our production or in a reduction of the price offered for our production. Additionally, if we were prohibited from flaring natural gas due to environmental or other regulations, then we would be forced to shut-in producing wells, which would also adversely impact our drilling program. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities or any changes in regulatory requirements affecting flaring activities, could harm our business and, in turn, our financial condition, results of operations and cash flows.

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

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

In October, 2011, the EPA announced that it will consider federal pre-treatment standards for certain of our wastewater streams, which we would be required to meet before disposing of these waste streams at third party wastewater treatment plants. Also in 2011, the EPA promulgated additional restrictions on emissions from oil and natural gas production and exploration activities, as well as amended GHG reporting obligations. We are assessing the potential impact of these regulatory initiatives on our operations. See “Item 1 – Environmental Laws and Regulations” for further discussion of applicable environmental laws. These or future regulatory initiatives may impose substantial restrictions on our future operations, and could have a material impact on our business, financial condition or results of operations.

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

In recent years, the U.S. Congress, the EPA and various states have proposed various regulatory and legislative initiatives to address greenhouse gas (“GHG”) emissions in the United States. Recently, the EPA has issued multiple regulations designed at monitoring and limiting GHG emissions. While certain of such regulations have been challenged in litigation, there can be no assurance that such litigation will be successful. On November 30, 2010, the EPA issued a final rule requiring reporting of greenhouse gas emissions from the oil and natural gas industry. We are currently assessing the costs of complying with these new reporting requirements, which were amended in 2011. In addition, a subcommittee of the Department of Energy recently recommended that the EPA enhance its GHG reporting for our sector, by including additional sources of emissions and by including methane in reporting requirements. Canada, where we also hold oil and gas leases, is also implementing laws concerning GHG emissions. These or future federal, state, regional or international monitoring or regulatory requirements relating to climate change could require us to obtain permits or allowances for our GHG emissions, install new pollution controls, increase our operational costs, limit our operations or adversely affect demand for the oil and natural gas produced from our lands. See “Item 1 – Business Overview – Environmental Laws and Regulations.”

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

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

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

Any change in government regulation and/or administrative practices may have a negative impact on our ability to operate and on our profitability. The laws, regulations, policies or current administrative practices of any government body, organization or regulatory agency in the United States or any other jurisdiction in which we operate may be changed, applied or interpreted in a manner which will fundamentally alter our ability to carry on our business. The actions, policies or regulations, or changes thereto, of any government body or regulatory agency, or other special interest groups, may have a detrimental effect on us. Any or all of these situations may have a negative impact on our ability to operate and/or our profitability.

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

Aboriginal peoples have claimed aboriginal title and rights to portions of Montana where we operate. We are not aware that any claims have been made in respect of our property or assets. However, if a claim arose and was successful, it could have an adverse effect on us and our business operations, financial conditions or prospects.

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

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

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

· abnormally pressured formations;

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

· fires and explosions;

· personal injuries and death;

· regulatory investigations and penalties; and

· natural disasters.

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

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

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

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

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

Risks Relating to Our Common Stock

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

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

· actual or anticipated fluctuations in our quarterly results of operations;

· liquidity;

· sales of common stock by our stockholders;

· changes in oil and natural gas prices;

· changes in our cash flow from operations or earnings estimates;

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

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

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

· changes in market valuations of similar companies;

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

· additions or departures of key management personnel;

· actions by our stockholders;

· commencement of or involvement in litigation;

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

· speculation in the press or investment community regarding our business;

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

· general market and economic conditions; and

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

Financial markets have recently experienced significant price and volume fluctuations that have affected the market prices of equity securities of companies and that have, in many cases, been unrelated to the operating performance, underlying asset values or prospects of such companies. Accordingly, the market price of our common stock may decline even if our results of operations, underlying asset values or prospects improve or remain consistent. Additionally, these factors, as well as other related factors, may cause decreases in asset values that are deemed to be other than temporary.

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

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

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

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

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

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

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

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

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

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

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

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ITEM 2.  PROPERTIES

All of our oil and natural gas properties are located in the United States and Canada, but our Canadian holdings and operations, as explained in “Item 1 – Business Overview – Operations and Oil and Natural Gas Properties – Other Properties,” have become immaterial to our asset base and development plans. We are currently participating in oil and natural gas exploration activities in the states of North Dakota and Montana. The Bakken Shale play in the Williston Basin is our core area of operations in the United States.

United States

Williston Basin

As of January 31, 2012, we own approximately 83,000 acres of operated and non-operated leasehold positions in the Williston Basin of North Dakota and Montana. Approximately 30,000 acres are in our core area of North Dakota and Montana, of which 8,500 acres are considered operated acreage. Approximately 53,000 acres are in our Station Prospect area of Montana, of which approximately 36,000 acres are considered operated acreage. Our primary areas of initial operations are focused in the Rough Rider area of McKenzie and Williams Counties, North Dakota.

We commenced drilling of our first operated well in October 2011. As of April 10, 2012, we had nearly finished drilling our fourth operated well. Over a five week period beginning on April 23, 2012, subject to the weather and other external uncontrollable factors, we expect to complete and place on production our first four gross (1.8 net) operated wells. By January 31, 2013, we anticipate having drilled and completed at least 15 gross (6.8 net) operated, horizontal wells — all in North Dakota or eastern Montana, for completion in the Bakken Shale or Three Forks formations. In addition, we anticipate participating in the drilling and completion of approximately 90 gross (4 net) non-operated wells begun in fiscal year 2013, with most of the completions occurring in fiscal year 2013.

The operations of our non-operated leasehold positions are primarily conducted through agreements with major operators in the Williston Basin, including Hess, Continental, Statoil, Newfield, EOG, XTO, Whiting, Slawson and Kodiak. These companies are experienced operators in the development of the Bakken Shale and Three Forks formations. As of March 31, 2012, we have participated in the drilling of 101 gross (5.32 net) non-operated wells, including 66 (3.5 net) non-operated producing wells. In addition, we have 23 non-operated gross (1.22 net) wells in various stages of drilling and completion and 12 non-operated gross (.63 net) wells already permitted to drill.

Using industry accepted well-spacing parameters and long lateral well bores, we believe that there could be over 75 operated drill spacing units and over 450 well locations for the Bakken Shale and Three Forks formations on our acreage in the Williston Basin. Based on current industry expectations, we believe we can drill six to eight 9,500+ foot lateral wells on 1,280 acre spacing units within our acreage. Consistent with leading field operators, we plan to perform multi-stage fracs with 25 to 30 stages on each lateral well. We also plan to drill shorter laterals on smaller units as dictated by our leasehold position. Separately, we have approximately 120 non-operated drill spacing units with greater than 2% working interest in our core area of North Dakota and Montana.

Oil and Natural Gas Reserves

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

All of our proved reserves are located in North Dakota, in the Bakken Shale formation or Three Forks formation. Ryder Scott Petroleum Consultants (“Ryder Scott”), an independent petroleum engineering firm, estimated our proved oil and natural gas reserves as of January 31, 2012 and determined the projected future cash flows (before income taxes) from those proved reserves and the present value, discounted at 10% per annum, of those future cash flows (“PV-10 Value”) at January 31, 2012. MHA Petroleum Consultants (“MHA”), an independent petroleum consulting firm, estimated our proved oil and natural gas reserves as of January 31, 2011 and determined the projected future cash flows (before income taxes) from those proved reserves and the PV-10 Value at January 31, 2011. Those estimates by Ryder Scott and MHA and their respective PV-10 Values are summarized in the following table and are further discussed in the Ryder Scott report and MHA report filed as exhibits to this annual report.

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In estimating the proved reserves, Ryder Scott and MHA used the SEC definition of proved reserves. Projected future cash flows were based on economic and operating conditions as of the respective January 31^st estimation date except that future oil and natural gas prices used in the projections reflected a simple average of prices for the well or property on the first day of the twelve months in the fiscal year ended on the January 31^st estimation date.

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

	As of January 31,
	2012		2011
Proved developed:
Oil (Mbbls)		538		214
Natural gas (Mmcf)		202		-
Proved Undeveloped:
Oil (Mbbls)		827		1,021
Natural gas (Mmcf)		472		-
Total proved oil reserves (MBbls)		1,365		1,236
Total proved natural gas reserves (Mmcf)		674		-
Total proved oil and natural gas reserves (MBoe)		1,477		1,236
PV-10 Values (in thousands) of oil and natural gas proved reserves:
PV-10 Value of proved developed reserves	$	19,393	$	4,109
PV-10 Value of proved undeveloped reserves	$	10,035	$	9,047
PV-10 Value of total proved reserves	$	29,428	$	13,156

The following table reconciles (a) the Standardized Measure of Discounted Future Net Cash Flows (GAAP) related to total proved oil and gas reserves to (b) PV-10 Value (Non-GAAP) of total proved oil and gas reserves. The difference is due to the PV-10 Value excluding the impact of income taxes.

	As of January 31,
(in thousands)	2012			2011
Standardized Measure, for total proved reserves	$	29,428		$	12,867
Add back: Discounting at 10% per annum		26,246			30,403
Future cash flow, after income taxes		55,674			43,270
Add: future undiscounted income taxes		-			2,627
Undiscounted future net cash flows before taxes		55,674			45,897
Less: Discounting at 10% per annum		(26,246	)		(32,741	)
PV-10 Value of total proved oil and gas reserves	$	29,428		$	13,156

The Standardized Measure is presented more fully and discussed further in Note 13 Unaudited Supplemental Oil and Gas Disclosures to the consolidated financial statements referenced in Part II, Item 8 of this report.

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No estimates of our proved reserves have been filed with, or included in reports to, any U.S. federal authority or agency, other than the SEC in fiscal year 2012 and fiscal year 2011.

Proved Undeveloped Reserves

At January 31, 2012, we had proved undeveloped oil and natural gas reserves of 905 MBoe, down 116 MBoe from 1,021 Mboe at January 31, 2011. Changes in our proved undeveloped reserves are summarized in the following table:

	Mboe
At January 31, 2011 (Mboe)		1,021
Net revisions		(819	)
Became developed reserves in fiscal year 2012		(53	)
Acquisitions of proved undeveloped property		-
Extensions and discoveries of proved reserves		756
Oil and gas produced and sold in fiscal year 2012		-
At January 31, 2012 (Mboe)		905

Of the 19 gross (3 net) proved undeveloped locations at January 31, 2011, 13 gross (2.6 net) locations (with 840 net Mboe of proved reserves at January 31, 2012) were viewed by our Senior Reservoir Engineer as unproved as of January 31, 2012 because the available geological and engineering data did not support reasonable certainty of sufficient reserves to provide a positive PV10 Value, net of estimated future development costs. Ryder Scott excluded those 13 gross (2.6 net) locations from proved reserves at January 31, 2012.

Additions to proved undeveloped reserves are for 17 drilling locations, whose status is summarized in the following table:

	PUD Locations		Development wells
				Gross	Net
Proved undeveloped locations for which
Triangle operated wells are anticipated to be drilled by 01/31/2013		4		4	1.61
Non-operated wells were in-progress at January 31, 2012 and are expected to be completed in fiscal year 2013		6		6	0.31
The outside operator already has obtained the drilling permit and expressed plans to start drilling in fiscal year 2013		6		6	0.58
We expect non-operated wells to be drilled by 01/31/2015		1		1	0.11
Total		17		17	2.61

None of our first four gross (1.8 net) operated wells can be considered as development wells for proved undeveloped reserves at this time. Our first four gross (1.8 net) wells are to undergo completion and initial production before an estimation of proved reserves related to those wells can be provided. We expect completion to take place in late April and in May, with initial sales in May and June 2012.

Internal Controls Over Reserve Estimation

Ryder Scott’s year-end reserve report, dated March 23, 2012, is prepared based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geoscience and engineering data, and other information we provide to them. This information is reviewed by knowledgeable members of our Company, including our Senior Reservoir Engineer, to ensure accuracy and completeness of the data prior to submission to Ryder Scott. Upon analysis and evaluation of data provided, Ryder Scott issues a preliminary report of our reserves which is reviewed by our Senior Reservoir Engineer, Subsurface Manager, Chief Financial Officer and Chief Executive Officer for completeness of the data presented and reasonableness of the results obtained. Once all questions have been addressed, Ryder Scott issues the final report, reflecting their conclusions.

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Our Senior Reservoir Engineer is the technical person primarily responsible for overseeing the preparation of the Company’s reserve estimates. Our Senior Reservoir Engineer has been a Registered Professional Engineer in Colorado since 1984, and has over 15 years’ experience as a petroleum engineer and is a member of the Society of Petroleum Engineers. He holds an undergraduate degree in geological engineering and a master’s degree in computer systems. The Company’s internal estimates of proved reserves are based on available geoscience and engineering data, including North Dakota online files of monthly production for wells in which we have an interest and wells adjacent to drill spacing units in which we have an interest. The internal reserve schedules and certain supporting schedules are reviewed by various members of management before our Senior Reservoir Engineer prepares a final internal summary of proved reserves and a final listing (by well and drilling location) of proved reserves.

Mr. Thomas E. Venglar was the primary technical person responsible for the Ryder Scott report estimating proved reserves at January 31, 2012. As stated more fully in the Ryder Scott report, Mr. Venglar has more than 30 years’ experience in the estimation and evaluation of petroleum reserves; he is a registered Professional Engineer in Colorado; he is a member of the Society of Petroleum Engineers; and he holds a Bachelor of Science degree in Petroleum Engineering from Texas A&M University.

Developed and Undeveloped Acreage

The table below presents the approximate gross acres and our approximate net acres as to our interests in oil and natural gas mineral leases as of January 31, 2012.

	Developed Acres				Undeveloped Acres				Total Acres
Project	Gross		Net		Gross		Net		Gross		Net
Williston Basin, ND		20,344		3,987		200,954		79,098		221,298		83,085
Maritimes Basin, Canada		-		-		474,625		412,924		474,625		412,924
Acreage Totals		20,344		3,987		675,579		492,022		695,923		496,009

We are subject to lease expirations if we or the operator of our non-operated acreage do not commence the development of operations within the agreed terms of our leases.  All of our leases for undeveloped acreage will expire at the end of their respective primary terms except for leases where we either (i) make extension payment(s) under the lease terms, (ii) renew the existing lease, (iii) establish commercial production paying royalties to the lessor or (iv) exercise some other “savings clause” in the respective lease.  We expect to establish production from most of our acreage prior to expiration of the applicable lease terms. However, there can be no guarantee we can do so.  

The table below shows by future fiscal year (i) costs of available lease extensions, (ii) net acres expiring without the lease extensions and (iii) net acres expiring with the lease extensions (assuming the leases were not developed and not held by production):

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			Net Acres Expiring
Fiscal Year	Future Extension Cost		If no extension		With all extensions
2013	$	161,380		4,220		3,705
2014		669,545		7,130		4,081
2015		2,107,665		22,950		15,052
2016		230,680		17,396		22,085
2017		-		17,993		24,882
2018		-		-		1,157
Total	$	3,169,270		69,689		70,962
Already extended				1,273		n/a
				70,962		70,962
Held by production				8,136		8,136
Total undeveloped net acres				79,098		79,098

Of the 3,705 net acres expiring (after extension payments) in fiscal year 2013 if no drilling or other actions are taken to further extend the lease life, we anticipate that less than 1,200 acres will expire. We are taking steps to minimize expirations.

Drilling and Other Exploratory and Development Activities

The following table presents the gross and net number of exploration wells and development wells drilled in fiscal years 2012, 2011 and 2010.

	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Exploration wells operated by Triangle		2		0.84		-		-		-		-
Exploration wells (non-operated)		60		2.10		4		0.94
Development wells (non-operated)		7		0.38		-		-		-		-

As of January 31, 2012, we had 63 gross productive wells and 3.43 net productive wells, which were all located in North Dakota.  Our count of productive wells does not include wells that were awaiting completion, in the process of completion or awaiting flowback subsequent to fracture stimulation.  We have not participated in any wells solely targeting natural gas reserves.  

Costs Incurred and Capitalized Costs

The table below presents costs incurred in oil and natural gas acquisition, exploration and development activities in fiscal years 2012 and 2011:

	2012		2011
Property acquisition	$	87,225,544	$	13,654,462
Exploration		40,727,797		4,575,424
Development		4,705,568		-
Total	$	132,658,909	$	18,229,886

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The table below summarizes capitalized costs excluded from amortization as of January 31, 2012 and 2011, respectively, by country. We anticipate the excluded costs at January 31, 2012 will be included in the amortization computation over the next five years. We are unable to predict the future impact on amortization rates.

	January 31,
	2012		2011
United States	$	111,716,360	$	11,206,667
Canada		-		4,000,000
Total	$	111,716,360	$	15,206,667

Sales Volumes and Prices and Production Costs

Our oil and natural gas production and proved reserves are located in the United States. The table below summarizes our oil and natural gas sales volumes, average sales price and average production costs per barrel of oil equivalent for the three most recent fiscal years, in total. Our sales volumes are attributable to our direct interests in producing properties after deducting royalty interests and similar interests. The lease operating expenses reflected below include production taxes on our net volumes sold and relate to our net working interest in producing properties.

	2012		2011		2010
Net Sales Volume
Oil (Bbls)		109,473		6,174		-
Natural Gas (Mcf)		12,883		23,689		34,965
Natural gas liquids (gallons)		9,076		-		-
Total equivalent barrels (6 mcf = 1 boe)		111,836		10,122		5,828
Average Sales Price Per Unit
Oil price (per Bbl)	$	73.16	$	74.20		n/a
Natural Gas price (per Mcf) (1)	$	8.27	$	4.46	$	3.75
Natural gas liquids price (per gallon)	$	2.26		n/a		n/a
Weighted average price (per Boe)	$	72.75	$	55.69	$	22.52
Lease Operating Expenses (per Boe)	$	16.26	$	13.82	$	16.45

(1) Most of our natural gas sales in fiscal year 2012 were for ‘wet’ gas sold before processing to extract natural gas liquids from the wet gas. Most of our natural gas sales in fiscal year 2011 were for ‘dry’ gas after extraction of natural gas liquids. Hence the average natural gas sales price was higher in fiscal year 2012 than in fiscal year 2011.

Office Facilities

We maintain our principal office at 1660 Wynkoop St., Suite 900, Denver, Colorado, 80202.  Our telephone number is (303) 260-7125 and our facsimile number is (303) 260-5080. Our current office space consists of approximately 9,144 square feet in our 1660 Wynkoop office, 2,370 square feet in our 1625 Broadway office and 2,475 square feet in our Calgary, Alberta office.  The 1625 Broadway lease runs until September 2013 and is currently subleased by RockPile Energy Services. The Calgary, Alberta lease runs until September 2013 and is subleased to an unrelated entity. The 1660 Wynkoop lease began on April 18, 2011 and runs through July 2015.

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As of January 31, 2012, our obligations to provide aggregate annual office rental payments were as follows:

Fiscal year ending January 31,		Annual Rental Amount
	2013	$	313,865
	2014	$	294,796
	2015	$	51,435

ITEM 3.  LEGAL PROCEEDINGS

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

ITEM 4.  MINE SAFETY DISCLOSURES

The disclosures are not applicable to us.

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PART II

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

MARKET INFORMATION

Our common stock is traded on the NYSE Amex LLC under the symbol “TPLM.” The table below sets forth the high and low sales price for our common stock in each quarter of the last two fiscal years (adjusted for the 10-for-1 stock split effective November 5, 2010).

	Fiscal Year 2011
	High		Low
February 1, 2010 to April 30, 2010	$	9.00	$	3.30
May 1, 2010 to July 31, 2010	$	7.50	$	4.10
August 1, 2010 to October 31, 2010	$	6.00	$	4.50
November 1, 2010 to January 31, 2011	$	7.92	$	5.65

	Fiscal Year 2012
	High		Low
February 1, 2011 to April 30, 2011	$	9.16	$	6.84
May 1, 2011 to July 31, 2011	$	7.79	$	5.86
August 1, 2011 to October 31, 2011	$	7.45	$	3.29
November 1, 2011 to January 31, 2012	$	7.38	$	4.89

HOLDERS

Our 44,154,253 shares of common stock outstanding at March 31, 2012 were held by approximately 25 stockholders of record. The number of holders was determined from the records of our transfer agent and does not include the thousands of beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, and registered clearing agencies. The transfer agent of our common stock is Continental Stock Transfer & Trust Company, 17 Battery Place, New York, New York 10004.

DIVIDENDS

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

RECENT SALE OF UNREGISTERED SECURITIES AND EQUITY PURCHASES BY THE COMPANY

On February 15, 2011, as partial consideration for the purchase of certain oil and natural gas interests from Williston Exploration LLC pursuant to the Purchase and Sale Agreement, dated October 5, 2010, between Triangle Petroleum Corporation, Triangle USA Petroleum Corporation and Williston Exploration LLC, we issued 433,500 shares of our common stock. We relied on this exemption based on applicable facts, including that (i) the offers and sales were made to a limited number of persons, all of whom represented that they were “accredited investors” (as such term is defined in Regulation D), (ii) no general solicitation or advertising was used in connection with the offering and sale of our common stock and (iii) the investors’ represented that they were acquiring our common stock for investment only.

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On April 1, 2011, as partial consideration for the purchase of certain oil and natural gas interests from Slawson pursuant to the Purchase and Sale Agreement, dated March 4, 2011, between Triangle Petroleum Corporation and Slawson, we issued 1,004,199 shares of our common stock. Our common stock was offered and sold in reliance on the private placement exemption from registration under Section 4(2) of the Securities Act, and Regulation D promulgated thereunder, or Regulation D. We relied on this exemption based on applicable facts, including that (i) the offers and sales were made to a limited number of persons, all of whom represented that they were “accredited investors” (as such term is defined in Regulation D), (ii) no general solicitation or advertising was used in connection with the offering and sale of our common stock and (iii) the investors’ represented that they were acquiring our common stock for investment only.

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

In fiscal 2012, the Company purchased shares of Triangle Common stock from employees solely for the purpose of offset tax withholding obligations that occurred upon the delivery of outstanding shares underlying restricted stock units delivered under the terms of grants under the 2011 Omnibus Incentive Plan.

Equity Compensation Plan Information

The following table sets forth certain information about the common stock that may be issued upon the vesting of restricted stock units and upon the exercise of options under the equity compensation plans as of January 31, 2012.

Number of shares to be issued upon vesting of Restricted Stock Units previously granted		2,581,443
Number of shares to be issued upon exercise of outstanding Stock options		235,832
		2,817,275
Weighted-Average Exercise Price of Outstanding Options	$	1.50
Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding the 2,817,275 shares reserved above )		1,418,557

ITEM 6.  SELECTED FINANCIAL DATA

As of January 31, 2012, the Company transitions from being a “smaller reporting company” to an “accelerated filer” under Rule 12b-2 of the Exchange Act. Accordingly, the disclosures of this annual report on Form 10-K for the fiscal year ended January 31, 2012 are those of a Smaller Reporting Company, and Item 6 disclosures are omitted.

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

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

Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC. The following Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Company should be read in conjunction with the Consolidated Financial Statements and notes related thereto included in this annual report on Form 10-K.

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Important  factors  currently known to our management could cause actual results to differ  materially  from  those in forward-looking  statements.  We undertake no obligation to update or revise forward-looking statements to reflect changed assumptions, the occurrence of unanticipated events or changes in the future operating results over time. We believe that our assumptions are based upon reasonable data derived from and known about our business and operations.  No assurances are made that actual results of operations or the results of our future activities will not differ materially from our assumptions.  Factors that could cause differences include, but are not limited to, expected market demand for our products, fluctuations in pricing for materials, and competition.

Overview

We are an exploration and production company currently focused on development of unconventional shale oil resources in the Bakken Shale and Three Forks formations in the Williston Basin of North Dakota and Montana. As of March 31, 2012, we have acquired approximately 83,000 net acres primarily in McKenzie and Williams Counties of North Dakota and Roosevelt and Sheridan Counties of Montana. Having identified an area of focus in the Bakken Shale and Three Forks formations that we believe will generate attractive returns on invested capital, we are continuing to explore further opportunities in the region. Proved oil and natural gas reserves as of January 31, 2012, totaled 1,477,091 Boe. Our FY2012 production averaged 270 Boe/day and we exited January 2012 with approximately 530 Boe/day of non-operated production.

In the core area of North Dakota, Triangle is directing resources toward its operated program to develop its consolidated positions in McKenzie and Williams County, roughly 30,000 net acres. In Roosevelt County, Montana, the “Station Prospect” is a largely contiguous position within the thermally mature area of the Williston Basin. The approximate 53,000 net acre position is predominantly operated acreage with longer lease term and provides Triangle with a scalable development area for the future. The combination of Triangle’s value-accretive and high-growth acreage in North Dakota and Montana, provides stockholders with a balanced portfolio of pure-play exposure to the upside of the Williston Basin.

With a focus on establishing an efficient development model, the Company is pad drilling, which expedites the operated program, while controlling costs and minimizing environmental impacts. We also intend to use innovative completion, collection, and production techniques which will optimize reservoir drainage while also reducing costs. Additionally, with access to well completion capacity via vertical integration (majority owned RockPile Energy Services), Triangle is positioned to lower implied production cost and have greater control over drilling and completions schedule.

Plan of Operations

We own operated and non-operated leasehold positions in the Williston Basin. We commenced drilling of our first operated well in October 2011. As of April 10, 2012, we had nearly finished drilling our fourth operated well. Over a five week period beginning on April 23, 2012, subject to the weather and other external uncontrollable factors, we expect to complete and place on production our first four gross (1.8 net) operated wells.

Triangle is currently running a 1+ rig drilling program, meaning one rig, the Xtreme 7, is contracted full-time and drilling approximately one well per month. We have temporarily contracted a second rig, Pioneer 42, to drill two to three wells during a three-month window, between April and July 2012. The focus of our near-term drilling program is on our core North Dakota acreage in McKenzie and Williams County. RockPile is expected to be available for completions by July 2012. Triangle will explore the potential to expand the drilling program and number of rigs under management upon the availability of attractive financing.

Our non-operated leasehold positions are primarily conducted through agreements with major operators in the Williston Basin, including Hess, Continental, Statoil, Newfield, EOG, XTO, Whiting, Slawson and Kodiak. These companies are experienced operators in the development of the Bakken Shale and Three Forks formations. As of March 31, 2012, we have participated in the drilling of 88 gross non-operated wells, including 66 producing wells and 12 wells in various stages of permitting, drilling or completion.

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Using industry accepted well-spacing parameters and long lateral well bores, we believe that there could be over 75 operated drill spacing units and over 450 well locations for the Bakken Shale and Three Forks formations on our acreage in the Williston Basin. Based on current industry expectations, we believe we can drill six to eight 9,500+ foot lateral wells on 1,280 acre spacing units within our acreage. Consistent with leading field operators, we plan to perform multi-stage fracs with 25 to 30 stages on each lateral well. We also plan to drill shorter laterals on smaller units as dictated by our leasehold position. Separately, we have approximately 120 non-operated drill spacing units with greater than 2% working interest in our core area of North Dakota and Montana.

Non-Core Properties

We have an 87% working interest in approximately 474,625 gross acres (approximately 412,924 net acres) of Nova Scotia oil and natural gas leases in the Windsor Sub-Basin of the Maritimes Basin. The leases are to expire in 2019, but can be extended pending agreement of further development plans with the Nova Scotia regulators. Nova Scotia is currently conducting an extensive hydraulic fracturing review to determine whether and how hydraulic fracturing will be allowed in the future. The review is expected to be completed in calendar year 2012. Nova Scotia also does not currently allow the common industry practice of using salt water disposal wells. While such government restrictions remain in place, it is uneconomic to proceed in further exploration and development of these leases. We do not know if and when the restrictions might be lifted, and we do not know if Nova Scotia would grant an extension to the leases due to Nova Scotia’s existing hydraulic fracturing review. As of January 31, 2012, we have fully impaired and expensed the $4.4 million carrying value of our oil and natural gas leases in the Maritimes Basin.

At January 31, 2012, we have recorded asset retirement obligations of $1,539,872 for our 87% share in costs to clean out frac water ponds, to plug well bores and to restore surface areas in fiscal year 2013 relating to our previous exploration and development activities in the Maritimes Basin.

We may in the future sell our Maritimes Basin leases, but will likely not do so until meeting our current asset retirement obligations and until we know whether and how hydraulic fracturing will be allowed in the Windsor Sub-Basin of the Maritimes Basin.

Results of operations for the year ended January 31, 2012 compared to the year ended January 31, 2011

For the fiscal year ended January 31, 2012, we recorded a net loss attributable to common stockholders of $23,832,355 ($0.78 per common share, basic and diluted) as compared to a net loss attributable to common stockholders of $20,277,197 ($1.63 per common share, basic and diluted) for the fiscal year ended January 31, 2011.

Oil and Natural Gas Operations

For fiscal year 2012, we had total oil and natural gas revenues of $8,135,972 compared with $563,670 for fiscal year 2011.  Oil and natural gas sales and production costs for each year are summarized in the table that follows.  Oil sales revenues increased $7.6 million to $8.1 million for fiscal year ended January 31, 2012, as compared to oil sales of $0.6 million for the fiscal year ended January 31, 2011. In fiscal year 2012, our oil sales averaged 306 Boe per day. Our oil sales volume increased 1673% to 109,473 barrels in fiscal year 2012, as compared to 6,174 barrels in fiscal year 2011. The volume increase is due to our ongoing Bakken exploration and development program. These increases are primarily due to 2.45 net wells commencing production in fiscal year 2012.

For our non-operated wells, natural gas is typically flared or used at the wellsite due to (i) newness of the well, (ii) lack of local natural gas distribution systems, (iii) more North Dakota natural gas production than the available North Dakota natural gas processing facilities can process and (iv) low prices for natural gas. Most of our natural gas sales in fiscal year 2012 were for ‘wet’ gas sold before processing to extract natural gas liquids from the wet gas. Most of our natural gas sales in fiscal year 2011 were for ‘dry’ gas after extraction of natural gas liquids. Hence the average natural gas sales price was higher in fiscal year 2012 than in fiscal year 2011.

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	Fiscal Year Ended January 31,
	2012			2011
U.S. oil and natural gas operations
Oil sold (barrels)		109,473			6,174
Average oil price	$	73.16		$	74.20
Oil revenue	$	8,008,912		$	458,111
Natural gas sold (mcf)		12,883			23,689
Average gas price	$	8.27		$	4.46
Natural gas revenue	$	106,557		$	105,559
Natural gas liquids sold (gallons)		9,076			-
Average gas liquids price	$	2.26		$	-
Natural gas liquids revenue	$	20,503		$	-
Total oil and gas revenues	$	8,135,972		$	563,670
Less production taxes		(896,062	)		(94,654	)
Less lease operating expense		(922,750	)		(45,231	)
Less impairment of oil and natural gas properties		(6,000,000	)		-
Less oil and natural gas amortization expense		(3,022,000	)		(96,000	)
Less accretion of asset retirement obligations		(6,950	)		(5,148	)
Loss from U.S. oil and natural gas operations		(2,711,790	)		322,637
Canadian oil and natural gas operations
Lease operating expense		(640,650	)		(31,628	)
Impairment of oil and natural gas properties		(4,416,202	)		(14,917,356	)
Gain on sale of oil and natural gas properties		-			1,006,294
Accretion of asset retirement obligations		(159,975	)		(245,171	)
Loss from Canadian oil and natural gas operations		(5,216,827	)		(14,187,861	)
Total loss from oil and natural gas operations		(7,928,617	)		(13,865,224	)
Other income		546,171			59,373
Foreign exchange gain (loss)		(21,938	)		35,615
Less depreciation of furniture and equipment		(85,122	)		(39,296	)
Less general and administrative expenses		(16,398,307	)		(6,467,665	)
Net loss	$	(23,887,813	)	$	(20,277,197	)
Total U.S. barrels of oil equivalent (“boe”) sold		111,836			10,122
U.S. Oil and natural gas revenue per boe sold	$	72.75		$	55.69
U.S. Lease operating expense per boe sold	$	16.26		$	13.82
U.S. Amortization expense per boe sold	$	27.02		$	9.48

Impairment of Oil and Natural Gas Properties

During fiscal year 2012 and 2011, we recorded impairments of $4.4 million and $14.9 million, respectively, in connection with our properties in the Maritimes Basin of Nova Scotia. We assess all unproved property for possible impairment annually or upon a triggering event. The assessment includes consideration of, among others, intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, governmental restrictions and the assignment of proved reserves. Nova Scotia is currently conducting an extensive hydraulic fracturing review to determine whether and how hydraulic fracturing will be allowed in the future. The review is expected to be completed in calendar year 2012. Nova Scotia also does not currently allow the common industry practice of using salt water disposal wells. While such government restrictions remain in place, it is uneconomic to proceed in further exploration and development of these leases. We do not know if and when the restrictions might be lifted, and we do not know if Nova Scotia would grant an extension to the leases due to Nova Scotia’s existing hydraulic fracturing review. These conditions are the primary factors that contributed to the full impairment of our Nova Scotia properties as of January 31, 2012. Since we have no proved oil and natural gas reserves in Canada, the “ceiling test” of our Canadian oil and natural gas properties results in the expensing of the impairment of our unproved Canadian properties

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During the fourth quarter of fiscal year 2012, we recorded a $6 million “ceiling test” impairment expense of the capitalized costs of our U.S. oil and natural gas properties. The ceiling reflected the proved reserves at January 31, 2012 estimated by Ryder Scott. Because all of our production in fiscal year 2012 is relatively new, from relatively small working interests in non-operated wells (many of which do not offset older wells that are similarly completed), it becomes relatively difficult (and sometimes impossible) to timely obtain from the operators adequate information on the wells to understand variations in well costs, operating costs and production patterns to support as reasonably certain at January 31, 2012 future production that was expected. Despite the thousands of wells that have been drilled in recent years in the Bakken formation in North Dakota, the proved (i.e., “reasonably certain”) reserves for a new well or for a proved undeveloped location are largely dependent on the production history of the new well or the well(s) immediately offsetting the new well or the undeveloped location. In such an environment of limited well and production information, estimations should be lower as to how much future production from a given well is proved, i.e., reasonably certain.

For example, we have a small working interest in a new non-operated well that had produced for only three months and the third month production was unusually low for reasons unknown to us. Due to the rapid decline in production, the estimate of the well’s proved and reasonably certain reserves was rather low. After the Ryder Scott reserve report was completed, the operator made public that the fourth month of production was three times greater than that of the previous month. The production improvement was indicative that if such information had been available for the estimation of our proved reserves at January 31, 2012, our ceiling impairment would likely have been reduced by $2 million.

A secondary factor contributing to the impairment was poor results from a small area on the southern edge of our acreage position in McKenzie County, North Dakota. We had participated in three wells to test that area, but their disappointing fiscal 2012 production history (relative to the three wells’ high capital and operating costs) led to the removal in the fall of 2012 of proved reserves from eight undeveloped locations that had $7.3 million in PV10 Value at January 31, 2011.

General and Administrative Expenses

The following table summarizes increases in general and administrative expenses for the fiscal years 2012 compared with 2011. The increases are primarily due to significant increases in the number of employees (6 on September 30, 2010, 10 by January 31, 2011, 21 by June 30, 2011 and 32 by January 31, 2012) as we greatly expanded our acquisition, exploration, development and production activities in North Dakota and Montana in fiscal year 2012 compared with fiscal year 2011.

	2012		2011		Increase
Stock-based compensation	$	7,567,312	$	1,066,311	$	6,501,001
Salaries, benefits and consulting fees		5,016,540		2,916,982		2,099,558
Office costs		1,689,220		1,355,007		334,213
Professional fees		1,517,735		817,369		700,366
Public company costs		607,500		311,996		295,504
Total general and administrative expenses	$	16,398,307	$	6,467,665	$	9,930,642

Stock-based compensation expense increased approximately $6.5 million primarily because we had 18 additional employees who received grants of restricted stock units in fiscal year 2012 as compared to the same period in fiscal year 2011 and because we delayed recognition of certain share-based compensation expense until stockholder approval on July 22, 2011 of our 2011 Omnibus Incentive Plan, as explained in Note 8 of the consolidated financial statements within this annual report on Form 10-K.

Professional fees increased $0.7 million primarily for increased legal expenses on various matters including our proxy statement filing, registration statements and due diligence work.

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Income Taxes

Our fiscal year 2012 provision for deferred income taxes is zero due to recognition of 100% valuation allowances against our net deferred tax assets of $29.2 million and $21.3 million at January 31, 2012 and 2011, respectively.  If facts and circumstances indicate that all or a portion of the deferred tax asset is more likely than not to be realized in the future, then the valuation allowance would be correspondingly reduced and a deferred tax benefit recognized.

Liquidity and Capital Resources

Our primary cash requirements are for exploration, development and acquisition of oil and natural gas properties.  We currently anticipate capital requirements for fiscal year 2013 to be approximately $90 million to $131 million. These funds will be allocated primarily towards our operated drilling program ($59 to $68 million). In the absence of additional financing, we will allocate $5 million to $10 million toward additional acreage acquisitions.  We expect to be able to fund these expenditures, as well as other commitments and working capital requirements, using existing capital, additional capital raised through the sale of debt or equity securities, our new reserve-based lending facility, or through participation in joint ventures and/or asset sales. We may expand or reduce our capital expenditures depending on, among other things, the results of future wells and our available capital.

As of January 31, 2012, we had cash of $69.6 million consisting primarily of cash held in bank accounts with Wells Fargo, Royal Bank of Canada and JP Morgan Chase, as compared to $57.8 million at January 31, 2011.  Working capital was $59.4 million as of January 31, 2012, as compared to $53.3 million at January 31, 2011. Our ability to continue to acquire property, accelerate our drilling program, and grow our oil and natural gas reserves and cash flow would be impacted if we are unable to obtain sufficient additional capital  

On April 12, 2012, our subsidiary Triangle USA Petroleum Corporation entered into a senior secured Credit Agreement with Wells Fargo Bank, National Association, as administrative agent and as Issuing Lender. The $300 million Credit Agreement has an initial borrowing base of $10.0 million, subject to quarterly redeterminations in 2012 and semi-annual redeterminations thereafter. As of April 12, 2012, there were no revolving borrowings or letters of credit outstanding under the Credit Agreement. All borrowings under the new revolving credit facility mature on April 12, 2017. We may prepay borrowings under the new revolving credit facility at any time without premium or penalty (other than customary LIBOR breakage costs). The revolving credit facility is secured by certain of TUSA’s assets and the obligations are guaranteed by Triangle Petroleum Corporation. The Credit Agreement contains representations, warranties and covenants that are customary for similar credit arrangements.

Net Cash Used By Operating Activities

Cash flow used by operating activities was $12.0 million and $3.5 million for the fiscal years ended January 31, 2012 and 2011, respectively.  The $8.5 million increase in cash used in fiscal year 2012 compared with fiscal year 2011 is due primarily to an approximate $3.4 million increase in general and administrative expenses, an approximate $2.3 million increase in lease operating expenses and approximately $3.9 million in costs paid for drilling our operated wells (which is recorded as an account receivable from various working interest partners). We also had an increase in cash flow from operating activities of approximately $2.7 million due to increased revenues from oil and natural gas operations.

Net Cash Used By Investing Activities

In fiscal year 2012, investing activities used $111.0 million in cash as compared to $16.1 million used in fiscal year 2011.  Cash used in investing activities increased due to the following: (i) approximately $107.5 million for the acquisition of oil and natural gas properties, (ii) approximately $1.3 million to purchase additional property and equipment, (iii) approximately $0.7 million of prepaid drilling and completion costs paid to operators and (iv) approximately $5.6 million for deposits paid for hydraulic fracturing equipment under construction for our 83.33% owned subsidiary, RockPile. The cash used in investing activities in fiscal year 2012 was offset by $4.0 million of proceeds received in connection with the sale of the non-controlling interest in RockPile.

40

Net Cash Provided By Financing Activities

Cash flow provided by financing activities was $134.9 million compared to $72.5 million provided in fiscal year 2011. The $62.3 million increase is primarily a result of the sale of 18,975,000 shares of our common stock for $7.50 per share in March 2011. Issuance costs in connection with the sale of these securities were approximately $7.6 million. During fiscal year 2012, we also received proceeds of $110,651 from the exercise of stock options. Cash flows provided by financing activities in fiscal year 2011 was a result of the sale of equity securities during the year. In November 2010, we sold 12,420,000 shares of our common stock at $5.50 per share, providing net proceeds of approximately $63 million in cash after offering and issuance costs. In March 2010, we sold 2,799,394 shares at a price of $3.30 for net proceeds of approximately $8.5 million. In August 2010, we sold 204,419 shares at a price of $4.30 for net proceeds of approximately $856,000. During fiscal year 2011, we also received proceeds of $235,000 for the exercise of stock options.

Contractual Obligations as of January 31, 2012

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

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

Fiscal year ending January 31,	Annual Rental Amount
2013	$	317,429
2014		298,360
2015		51,435

As of January 31, 2012 the Company was subject to commitments on a drilling rig contract. The contract expires in September 2013. In the event of early termination of the contract, the Company would be obligated to pay an aggregate amount of approximately $12.4 million as of January 31, 2012 as required under the terms of the contract. Subsequent to year-end, the Company assumed an additional drilling rig contract commencing on April 12, 2012 for a term of 120 days. In the event of early termination under this contract, the Company would be obligated to pay an additional $2.4 million.

Off-Balance Sheet Arrangements

None.

Critical Accounting Policies

Use of Estimates

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

41

Full Cost Accounting Method

We use the full cost method of accounting for our oil and natural gas operations. All costs associated with property acquisition, exploration and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and natural gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and natural gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves.

Companies that follow the full cost accounting method are required to make quarterly “ceiling test” calculations on country-wide cost pools. This test limits total capitalized costs for oil and natural gas properties (net of accumulated depreciation, depletion and amortization (“DD&A”) and deferred income taxes) to the sum of the present value (discounted at 10% per annum) of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. Revenue calculations in the reserves are based on the unweighted average first-day-of-the-month prices for the prior twelve months. Changes in proved reserve estimates (whether based upon quantity revisions or commodity prices) will cause corresponding changes to the full cost ceiling limitation. If net capitalized costs subject to amortization exceed this limit, the excess would be charged to expense. Any recorded impairment of oil and natural gas properties is not reversible at a later date.

Amortization of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement obligations, are amortized over total estimated proved reserves. The capitalized costs of unproved properties, including those in connection with wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred.

Asset Retirement Obligations

We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and natural gas producing companies incur this liability in connection with costs related to the plugging of wells, the removal of facilities and equipment and site restorations upon acquiring or drilling a successful well. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool.

Estimates of Proved Oil and Natural Gas Reserves

The process of estimating quantities of oil and natural gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures.

We use the units-of-production method to amortize the cost of our oil and natural gas properties. Changes in our estimate of reserve quantities and commodity prices will cause corresponding changes in amortization expense in periods subsequent to these changes, or in some cases, a full cost ceiling limitation charge in the period of the revision.

42

Income Taxes

Income taxes are provided for the tax effects of transactions reported in the consolidated financial statements and consist of taxes currently payable plus deferred income taxes. We compute deferred income taxes using the liability method whereby deferred income taxes are provided on all temporary differences between the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized.

We assess quarterly the likelihood of realization of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as historical performance and future operating conditions (particularly as related to prevailing oil and natural gas prices).

Stock-Based Compensation

We recognize compensation related to all stock-based awards, including restricted stock units and stock options, in the consolidated financial statements based on their estimated grant-date fair value. We grant various types of stock-based awards including stock options and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and units are valued using the market price of our common stock on the grant date. Compensation cost is recognized ratably over the applicable vesting period. See Note 8 for additional information regarding our stock-based compensation. 

Recently Issued Accounting Pronouncements

Refer to Note 3 of the Consolidated Financial Statements.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

As of January 31, 2012, the Company transitions from being a “smaller reporting company” to an “accelerated filer” under Rule 12b-2 of the Exchange Act. Accordingly, the disclosures of this Annual Report on Form 10-K for the fiscal year ended January 31, 2012 are those of a Smaller Reporting Company, and Item 7 disclosures are omitted.

43

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Reports of Independent Registered Public Accounting Firms*	45
Consolidated Balance Sheets as of January 31, 2012 and 2011	47
Consolidated Statements of Operations for each of the years ended January 31, 2012 and 2011	48
Consolidated Statements of Cash Flows for each of the years ended January 31, 2012 and 2011	49
Consolidated Statement of Stockholders’ Equity for each of the years ended January 31, 2012 and 2011	50
Notes to Consolidated Financial Statements	51

All supplementary data are either omitted as not applicable or the information required is shown in the consolidated financial statements or related notes thereto.

* As more fully reported in Form 8-K filed on January 12, 2012, Triangle changed its principal independent registered public accounting firm from KPMG LLP, the Canadian member firm affiliated with KPMG International to KPMG LLP, the United States member firm affiliated with KPMG International.  The accompanying audited financial statements are preceded by the KPMG U.S. firm’s audit report with regard to financial statements for fiscal year 2012 and a separate report by the KPMG Canadian firm with regard to financial statements for fiscal year 2011.

44

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 and subsidiaries (the Company) as of January 31, 2012 and the related consolidated statements of operations, cash flows and stockholders’ equity and comprehensive loss for the year ended January 31, 2012. 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 and subsidiaries as of January 31, 2012 and the results of their operations and their cash flows for the year ended January 31, 2012, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Triangle Petroleum Corporation’s internal control over financial reporting as of January 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated April 13, 2012 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Denver, Colorado

April 13, 2012

45

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 and subsidiaries as of January 31, 2011, and the related consolidated statements of operations, stockholders’ equity and comprehensive loss, and cash flows for the year ended January 31, 2011. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material 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 and subsidiaries as of January 31, 2011, and the results of their consolidated operations and their cash flows for the year ended January 31, 2011, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Chartered Accountants

Calgary, Canada

April 13, 2011

46

TRIANGLE PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

	January 31,			January 31,
	2012			2011
ASSETS
CURRENT ASSETS
Cash	$	69,567,674		$	57,773,269
Restricted cash		-			105,264
Prepaid expenses		161,650			26,002
Accounts receivable:
Oil and natural gas sales		5,422,453			155,489
Trade		3,929,465			10,531
Other		465,482			66,808
Total current assets		79,546,724			58,137,363
LONG-TERM ASSETS
Oil and gas properties at cost, using the full cost method of accounting:
Unproved properties and properties under development, not being amortized		111,716,360			15,206,667
Proved properties		33,172,419			7,023,218
		144,888,779			22,229,885
Less accumulated amortization		(3,118,000	)		(96,000	)
Net oil and gas properties		141,770,779			22,133,885
Deposits on equipment under construction		5,647,576			-
Other property and equipment (less accumulated depreciation of $85,122)		1,224,675			-
Prepaid drilling costs and other		2,192,963			1,469,453
Deposits		203,987			290,067
Deferred tax asset - long-term		-			-
Total assets	$	230,586,704		$	82,030,768
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	3,434,079		$	1,939,754
Accrued liabilities:
Exploration and development		11,807,040			875,794
Other		3,391,563			2,004,817
Asset retirement obligations		1,539,872			-
Total current liabilities		20,172,554			4,820,365
Asset retirement obligations		83,418			1,403,697
Total liabilities		20,255,972			6,224,062
COMMITMENTS AND CONTINGENCIES (See Note 11)
STOCKHOLDERS' EQUITY
Common stock, $0.00001 par value, 70,000,000 shares authorized; 43,515,958 and 22,525,672 shares issued and outstanding at January 31, 2012 and 2011, respectively		435			225
Additional paid-in capital		314,199,952			159,788,323
Accumulated deficit		(107,814,197	)		(83,981,842	)
Accumulated other comprehensive income		-			-
Total parent company stockholders’ equity		206,386,190			75,806,706
Noncontrolling interest in subsidiary		3,944,542			-
Total stockholders' equity		210,330,732			75,806,706
Total liabilities and stockholders’ equity	$	230,586,704		$	82,030,768

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

47

TRIANGLE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED JANUARY 31, 2012 AND 2011

	2012			2011
REVENUES
Oil and natural gas sales	$	8,135,972		$	563,670
EXPENSES
Production taxes		896,062			94,654
Other lease operating		1,563,400			76,859
Depletion, depreciation and amortization		3,107,122			135,296
Impairment of oil and natural gas properties		10,416,202			14,917,356
Less: gain on sale of oil and natural gas properties		-			(1,006,294	)
Accretion of asset retirement obligations		166,925			250,319
General and Administrative:
Stock-based compensation		7,567,312			1,066,311
Salaries and benefits		4,384,085			1,211,972
Other general and administrative		4,446,910			4,189,382
Foreign exchange loss (gain)		21,938			(35,615	)
Total operating expenses		32,569,956			20,900,240
LOSS FROM OPERATIONS		(24,433,984	)		(20,336,570	)
OTHER INCOME
Interest income		280,991			59,373
Miscellaneous income		265,180			-
Total other income		546,171			59,373
NET LOSS BEFORE INCOME TAXES		(23,887,813	)		(20,277,197	)
Income tax provision		-
NET LOSS		(23,887,813	)		(20,277,197	)
Less: net loss attributable to noncontrolling interest in subsidiary		55,458			-
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(23,832,355	)	$	(20,277,197	)
NET LOSS PER COMMON SHARE - BASIC AND DILUTED	$	(0.78	)	$	(1.63	)
Weighted average common shares outstanding - basic and diluted		30,597,334			12,463,751

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

48

TRIANGLE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED JANUARY 31, 2012 AND 2011

	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(23,887,813	)	$	(20,277,197	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		3,107,122			135,296
Impairment of oil and natural gas properties		10,416,202			14,917,356
Stock-based compensation		7,567,312			1,066,311
Gain on sale of oil and natural gas properties		-			(1,006,294	)
Accretion of asset retirement obligations		166,925			250,319
Foreign exchange changes		-			(2	)
Changes in related current assets and liabilities:
Prepaid expenses and deposits		(135,648	)		26,566
Accounts receivable:
Oil and natural gas sales		(5,266,963	)		-
Trade		(3,918,934	)		-
Other		(398,673	)		80,956
Accounts payable and accrued liabilities		631,689			1,295,523
Asset retirement expenditures		(303,655	)		(29,361	)
Cash used in operating activities		(12,022,436	)		(3,540,527	)
CASH FLOWS FROM INVESTING ACTIVITIES
Oil and natural gas property expenditures		(107,594,044	)		(16,255,639	)
Purchase of other property and equipment		(1,309,797	)		-
Restricted cash		105,264			(105,264	)
Cash advanced to operators for oil and natural gas property expenditures		(723,510	)		(715,009	)
Deposits on equipment under construction		(5,647,576	)		-
Non-controlling interest in RockPile Holdings LLC		4,000,000			-
Proceeds from return of long-term deposit		86,080			-
Proceeds from sale of oil and natural gas properties		46,800			976,900
Cash used in investing activities		(111,036,783	)		(16,099,012	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common stock		142,312,500			78,426,848
Common stock issuance costs		(7,569,527	)		(6,127,597	)
Issuance of common stock for exercise of options		110,651			234,956
Cash provided by financing activities		134,853,624			72,534,207
NET INCREASE IN CASH		11,794,405			52,894,668
CASH, BEGINNING OF PERIOD		57,773,269			4,878,601
CASH, END OF PERIOD	$	69,567,674		$	57,773,269
NON-CASH INVESTING ACTIVITIES
Additions to oil and natural gas properties through:
Increased accounts payable and accrued liabilities	$	13,180,627		$	2,076,609
Issuance of common stock	$	11,780,344		$	-
Recognition of long-term asset retirement obligations	$	52,668		$	-

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

49

TRIANGLE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE LOSS

FOR THE YEARS ENDED JANUARY 31, 2012 AND 2011

	Shares of Common Stock		Common Stock at Par Value		Additional Paid-in Capital			Warrants			Accumulated Deficit			AOCI*		Non- controlling Interest in Subsidiary			Total Equity
Balance - January 31, 2010		6,992,692	$	70	$	81,950,705		$	4,237,100		$	(63,704,645	)	$	-	$	-		$	22,483,230
Exercise of stock options		79,167		1		234,956			-			-			-		-			234,957
Sale of stock at $3.30/share		2,799,394		28		9,237,972			-			-			-		-			9,238,000
Stock offering costs		-		-		(773,531	)		-			-			-		-			(773,531	)
Sale of stock at $4.30/share		204,419		2		879,000			-			-			-		-			879,002
Stock offering costs		-		-		(23,401	)		-			-			-		-			(23,401	)
Shares issued pursuant to termination agreement		30,000		-		180,000			-			-			-		-			180,000
Expiration of warrants		-		-		4,237,100			(4,237,100	)		-			-		-			-
Sale of stock at $5.50/share		12,420,000		124		68,309,876			-			-			-		-			68,310,000
Stock offering costs		-		-		(5,330,665	)		-			-			-		-			(5,330,665	)
Stock-based compensation		-		-		886,311			-			-			-		-			886,311
Net loss for the year		-		-		-			-			(20,277,197	)		-		-			(20,277,197	)
Year’s comprehensive loss												(20,277,197	)		-					(20,277,197	)
Balance - January 31, 2011		22,525,672	$	225	$	159,788,323		$	-		$	(83,981,842	)	$	-	$	-		$	75,806,706
Stock issued for the purchase of oil and natural gas property		1,437,699		14		11,780,345			-			-			-		-			11,780,359
Sale of stock at $7.50/share		18,975,000		190		142,312,310			-			-			-		-			142,312,500
Stock offering costs		-		-		(7,569,527	)		-			-			-		-			(7,569,527	)
Exercise of stock options		82,501		1		110,650			-			-			-		-			110,651
Stock issued pursuant to termination agreements		24,000		-		184,840			-			-			-		-			184,840
Vesting of restricted stock units		471,086		5		(5	)		-			-			-		-			-
Stock-based compensation		-		-		7,593,016			-			-			-		-			7,593,016
Minority equity contribution in subsidiary		-		-		-			-			-			-		4,000,000			4,000,000
Net loss for the year		-		-		-						(23,832,355	)		-		(55,458	)		(23,887,813	)
Year’s comprehensive loss												(23,832,355	)		-					(23,832,355	)
Balance - January 31, 2012		43,515,958	$	435	$	314,199,952		$	-		$	(107,814,197	)	$	-	$	3,944,542		$	210,330,732

* Accumulated Other Comprehensive Income (Loss)

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

50

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF BUSINESS

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

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

2. BASIS OF PRESENTATION

The accounts of Triangle Petroleum Corporation and its subsidiaries are presented in the accompanying consolidated financial statements. These consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries: (i) Elmworth Energy Corporation, incorporated in the Province of Alberta, Canada, and (ii) Triangle USA Petroleum Corporation (“Triangle USA”), incorporated in the State of Colorado, and its wholly owned subsidiaries. These consolidated financial statements also include the accounts of the Company’s 83.33% owned subsidiary RockPile Holdings LLC (“RockPile”), incorporated in the state of Delaware. All significant intercompany balances and transactions have been eliminated. The Company’s fiscal year-end is January 31. RockPile and another Triangle USA subsidiary have a fiscal year-end of December 31. There were no material intervening events that occurred on the two subsidiaries between December 31, 2011 and January 31, 2012.

These consolidated financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America or GAAP, and are expressed in U.S. dollars. Preparation in accordance with GAAP requires us to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the SEC and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3 describes our significant accounting policies. Our management believes the major estimates and assumptions impacting our consolidated financial statements are the following:

· estimates of proved reserves of oil and natural gas, which affect the calculations of amortization and impairment of capitalized costs of oil and natural gas properties;

· estimates of the fair value of oil and natural gas properties we own, particularly properties that we have not yet explored, or fully explored, by drilling and completing wells;

· estimates as to the future realization of deferred income tax assets; and

· the assumption required by GAAP that proved reserves and generally proved reserve value for measuring capitalized cost impairment be based (for each proved property) on simple averages of the preceding twelve months’ historical oil and natural gas prices on the first day of each month.

The estimated fair values of our unevaluated oil and natural gas properties affects our assessment as to whether portions of unevaluated capitalized costs are impaired, which also affects the calculation of recorded amortization and impairment expense with regards to our capitalized costs of oil and natural gas properties.

Actual results may differ from estimates and assumptions of future events. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting.

Certain amounts in prior years’ consolidated financial statements have been reclassified to conform to the 2011 financial statement presentation.

51

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

Cash and cash equivalents consist of cash in banks in the United States and Canada. Cash equivalents are stated at cost, which approximates market value.

Fair Value

The carrying amounts reported in the consolidated balance sheets for cash, restricted cash, accounts receivable, prepaid expenses, accounts payable and accrued liabilities approximate fair value because of the immediate or short-term maturity of these financial instruments.

Accounts Receivable and Credit Policies

We have certain trade receivables consisting of oil and natural gas sales obligations due under normal trade terms. Our management regularly reviews trade receivables and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible. At January 31, 2012 and 2011, management had determined that no allowance for uncollectible receivables was necessary.

Oil and Natural Gas Properties

We use the full cost method of accounting for our oil and natural gas operations. All costs associated with property acquisition, exploration, and development activities in the United States and Canada are capitalized into a United States full cost pool and a Canadian full cost pool, respectively, and amortized by cost pool over proved reserves. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and natural gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and natural gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves.

Companies that follow the full cost accounting method are required to make quarterly “ceiling test” calculations for each full cost pool. This test ensures that the country-wide cost pool’s total capitalized costs for oil and natural gas properties (net of accumulated DD&A and deferred income taxes) do not exceed for the sum of the present value discounted at 10% of estimated future net cash flows from the Company’s proved oil and natural gas reserves in that country, the pool’s cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. If the cost pool’s net capitalized costs exceed this “ceiling,” the excess is charged to expense. Any recorded ceiling-test impairment of oil and natural gas properties is not reversible at a later date. See Note 4 for disclosures regarding ceiling test impairments recorded in fiscal years 2012 and 2011.

Amortization of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves by country-wide cost pool. The capitalized costs of unevaluated properties, including those of wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred.

Other Property and Equipment

We record at cost any long-lived tangible assets that are not oil and natural gas properties. Depreciation is recorded using the straight-line method over the estimated useful lives of the related assets of three to ten years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived property and equipment, other than oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. We have not found nor recognized any impairment losses on such other property and equipment.

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Revenue Recognition

Revenues from oil and natural gas sales are based on the sales method, with revenue recognized on actual volumes sold to purchasers. There is a ready market for our production, with sales occurring soon after production, but some operators of wells in which we have working interests have either burned or used on-site some produced natural gas due to insufficient local facilities to economically transport the gas to markets or to process the produced gas before it will be accepted into major gas pipeline systems.

Oil and Natural Gas Reserves

The process of estimating quantities of oil and natural gas proved reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing estimates of proved reserves may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures.

At January 31, 2012, 61% of our total proved reserves are categorized as proved undeveloped. All of these proved undeveloped reserves are in the Bakken Shale formation in North Dakota. Our internal reserve engineer reviews our reserve estimates at least quarterly and revises our proved reserve estimates, as significant new information becomes available.

We use the units-of-production method to amortize the cost of our oil and natural gas properties. Changes in our estimate of proved reserve quantities will cause corresponding changes in amortization expense in periods subsequent to these changes, or in some cases, a full cost ceiling limitation charge in the period of the revision.

Income Taxes

Income taxes are provided for the tax effects of transactions reported in the consolidated financial statements and consist of taxes currently payable plus deferred income taxes. We compute deferred income taxes using the liability method whereby deferred income taxes are provided on all temporary differences between the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized.

We assess quarterly the likelihood of realization of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as historical performance and future operating conditions (particularly as related to prevailing oil and natural gas prices).

Contingencies

A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and periodically determine when we should record losses for these items based on information available to us. We have not accrued for any contingencies as of January 31, 2012.

Asset Retirement Obligations

We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and natural gas producing companies incur this liability for their working interest in a well at the time the well is drilled or acquired. The liability reflects a discounted present value of estimated future costs related to the plugging of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool amortization base.

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Stock-based Compensation

We recognize compensation related to all stock-based awards, including restricted stock units and stock options, in the consolidated financial statements based on their estimated grant-date fair value. We grant various types of stock-based awards including stock options and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and units are valued using the market price of our common stock on the grant date. Compensation cost is recognized ratably over the applicable vesting period. See Note 8 for additional information regarding our stock-based compensation.

Earnings per Share

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

Concentration of Credit Risk

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

Off Balance Sheet Arrangements

We have no significant off balance sheet arrangements.

Segment Information

Operating segments are components of an enterprise about which separate financial information is available that is evaluated regularly by the Company in deciding how to allocate resources and in assessing performance. The financial information is required to be reported on the basis that is used internally for evaluating segment performance and deciding how to allocate resources to segments. Through January 31, 2012, the Company operated in one segment, oil and natural gas producing activities. RockPile is a start-up company formed in October 2011, which expects to commence operations in July 2012, and will focus on providing pressure pumping and ancillary services in the Williston Basin.

Recently Issued Accounting Standards

In May 2011, the FASB issued Accounting Standards Update 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This update does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. This update may require certain additional disclosures related to fair value measurements. The Company does not expect the adoption of this update will materially impact its financial statement disclosures.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the consolidated financial statements upon adoption.

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4. PROPERTY AND EQUIPMENT

Property and equipment as of January 31, 2012 and 2011 consisted of the following:

	2012			2011
Oil and natural gas properties, using the full cost method:
Unproved properties and properties under development, not being amortized	$	111,716,360		$	15,206,667
Proved properties		33,172,419			7,023,218
		144,888,779			22,229,885
Less accumulated amortization		(3,118,000	)		(96,000	)
Net carrying value of oil and natural gas properties		141,770,779			22,133,885
Deposits on equipment under construction		5,647,576			-
Cost of other property and equipment		1,309,797			-
Less accumulated depreciation and amortization		(85,122	)		-
Net property and equipment	$	148,643,030		$	22,133,885
Total property and equipment located in the United States	$	148,643,030		$	18,133,885
Total property and equipment located in Canada	$	-		$	4,000,000

During fiscal year 2012, we acquired undeveloped acres from various entities and incurred drilling and completion costs for total consideration of approximately $132.7 million, comprised primarily of cash in the amount of $107.6 million, accrued costs of $13.2 million and 1,437,699 shares of our common stock with a deemed value of $11.8 million.

We capitalized $613,656 and $0 of internal land and geology department costs in fiscal years 2012 and 2011, respectively that are directly associated with property acquisition, exploration (including lease record maintenance) and development. The internal land and geology department costs were capitalized to unevaluated costs.

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

During fiscal year 2012, we recorded a $6 million “ceiling test” impairment expense of the capitalized costs of our U.S. oil and natural gas properties. During fiscal year 2012 and 2011, we recorded impairments of $4.4 million and $14.9 million, respectively, in connection with our properties in the Maritimes Basin of Nova Scotia. We assess all unproved property for possible impairment annually or upon a triggering event. The assessment includes consideration of, among others, intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, governmental restrictions and the assignment of proved reserves. Nova Scotia is currently conducting an extensive hydraulic fracturing review to determine whether and how hydraulic fracturing will be allowed in the future. The review is expected to be completed in calendar year 2012. Nova Scotia also does not currently allow the common industry practice of using salt water disposal wells. While such government restrictions remain in place, it is uneconomic to proceed in further exploration and development of these leases. We do not know if and when the restrictions might be lifted, and we do not know if Nova Scotia would grant an extension to the leases due to Nova Scotia’s existing hydraulic fracturing review. These conditions are the primary factors that contributed to the full impairment of our Nova Scotia properties as of January 31, 2012. Since we have no proved oil and natural gas reserves in Canada, the “ceiling test” of our Canadian oil and natural gas properties results in the expensing of the impairment of our unproved Canadian properties

Deposits on equipment under construction consist of down payments for pressure pumping equipment of RockPile. This equipment has not been put into service and is not currently depreciated. It is estimated that the equipment will go into service in the second quarter of fiscal year 2013.

5. ASSET RETIREMENT OBLIGATIONS

The following table reflects the components of the change in the carrying amount of the asset retirement obligations for the years ended January 31, 2012 and 2011:

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	2012			2011
Balance, beginning of year	$	1,403,697		$	1,180,515
Liabilities incurred		423,111			2,224
Revision of estimates		(52,966	)		-
Sale of assets		(13,822	)		-
Liabilities settled		(303,655	)		(29,361	)
Accretion		166,925			250,319
Balance, end of year		1,623,290			1,403,697
Less current portion of obligations		(1,539,872	)		-
Long-term asset retirement obligations	$	83,418		$	1,403,697

6. INCOME TAXES

Federal income tax expense (benefit) for the years presented differ from the amounts that would be provided by applying the U.S. Federal and state income tax rate. The components of the provision for income taxes are as follows for fiscal years 2012 and 2011:

	2012			2011
Current tax benefit	$	-		$	-
Deferred tax benefit		(7,874,028	)		(5,866,580	)
Valuation Allowance – United States and Canada		7,874,028			5,866,580
Income tax expense	$	-		$	-
Loss before income taxes	$	(23,887,813	)	$	(20,277,197	)
Effective income tax rate		0	%		0	%

Reconciliations of the income tax benefit calculated at the federal statutory rate of 35% to the total income tax (benefit) expense are as follows for fiscal years 2012 and 2011:

	2012			2011
Federal statutory tax benefit	$	8,925,740		$	7,705,335
Permanent differences		(131,527	)		(19,597	)
Difference in foreign tax rates		(600,189	)		(1,936,736	)
Effect of tax rate change		(82,859	)		-
Changes in valuation allowance		(7,874,028	)		(5,866,580	)
Other		(237,137	)		117,578
Provision for income taxes	$	-		$	-

The difference in foreign tax rate of $600,189 is a result of adjusting the US effective tax rate of 37.4% down to the Canadian effective tax rate of 26.5%.

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The components of Triangle’s net deferred income tax assets are as follows for fiscal years 2012 and 2011:

	2012			2011
Current:
Assets:
Uncollectible accounts receivable	$	-		$	17,888
Non-Current:
Assets:
Canadian oil and natural gas properties		6,104,357			4,879,493
United States net losses carried forward		26,975,337			15,287,857
Canadian net losses carried forward		1,610,721			1,382,991
Asset retirement obligations		416,137			363,109
Stock-based compensation		1,957,820			638,657
Investment in RockPile		128,483			-
Property and equipment		23,059			157,219
Other		2,626			-
Total assets		37,218,540			22,727,214
Liabilities:
United States oil and natural gas properties		(8,011,710	)		(1,394,410	)
Gross deferred income tax assets		29,206,830			21,332,804
Valuation allowance		(29,206,830	)		(21,332,804	)
Net deferred income tax asset	$	-		$	-

The Company has a U.S. net tax operating loss (NOL) carryforward of approximately $72.2 million and a Canadian NOL of approximately $6.4 million at January 31, 2012. The U.S. NOL carryforwards begin expiring in 2023 and the Canadian NOL carryforwards begin expiring in 2026.

At January 31, 2012 and 2011, we have no unrecognized tax benefits that would impact our effective tax rate and we have made no provisions for interest or penalties related to uncertain tax positions.

The tax years for fiscal years ending 2009 to 2011 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for examination for fiscal years 2009 to 2011, except for Colorado which is open for the fiscal years 2008 to 2011. We also file returns with various Canadian taxing authorities which remain open for fiscal years 2008 to 2011.

7. CAPITAL STOCK

The Consolidated Statement of Stockholders’ Equity provides a listing of changes in the common stock outstanding from February 1, 2010 to January 31, 2012.

A summary of our common stock activity for the fiscal year ended January 31, 2012 follows:

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

· In March 2011, the Company issued 18,975,000 shares of common stock in a public offering for gross proceeds of $142.3 million. The Company paid approximately $7.6 million in expenses related to this offering.

· On April 1, 2011, the Company issued 1,004,199 shares of common stock to Slawson Exploration Company, LLC and certain other parties for the purchase of approximately 6,716 undeveloped net acres in Williams County, North Dakota in addition to $14.5 million paid in cash.

· The Company issued 24,000 shares of common stock pursuant to employment termination agreements.

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· The Company issued 82,501 shares of common stock pursuant to the exercise of stock options.

· The Company issued 471,086 shares of common stock for restricted stock units that vested during the year.

8. STOCK-BASED COMPENSATION

Effective January 28, 2009, the Company’s board of directors approved a Stock Option Plan (the “Rolling Plan”) whereby the number of authorized but unissued shares of common stock that may be issued upon the exercise of stock options granted under the Rolling Plan at any time shall not exceed 10% of the issued and outstanding shares of common stock on a non-diluted basis at any time, and such aggregate number of shares of common stock shall automatically increase or decrease as the number of issued and outstanding shares of common stock change. Upon approval of the 2011 Omnibus Incentive Plan (the “2011 Plan”) by the Company’s stockholders on July 22, 2011, the Rolling Plan was terminated and no additional awards may be made under such plan. All outstanding awards under the Rolling Plan shall continue in accordance with their applicable terms and conditions.

The 2011 Plan authorizes the Company to issue stock options, stock appreciation rights (“SARs”), restricted stock and restricted stock units, performance awards, stock or property, stock awards and other stock-based awards to any employee, consultant, independent contractor, director or officer of the Company. The maximum number of shares of common stock reserved for issuance under the 2011 Plan is 4,000,000 shares, subject to adjustment for certain transactions.

We have recognized non-cash stock-based compensation cost as follows:

	Year Ended January 31,
	2012			2011
Restricted stock units	$	7,511,959		$	792,893
Stock options		81,057			93,418
Stock issued pursuant to termination agreements		184,840			180,000
		7,777,856			1,066,311
Less amounts capitalized to oil and natural gas properties		(210,544	)		-
Compensation expense	$	7,567,312		$	1,066,311

Historical amounts may not be representative of future amounts as additional awards may be granted.

Restricted Stock Units

The following table provides information about restricted stock unit awards granted during the last two fiscal years.

	Number of Shares			Weighted- Average Award Date Fair Value
Restricted stock units outstanding - January 31, 2010		-
Grants in fiscal year 2011		509,636		$	5.61
Restricted stock units outstanding - January 31, 2011		509,636		$	5.61
Grants in fiscal year 2012		2,645,110		$	7.06
Forfeitures		(134,000	)	$	6.81
Lapse of restrictions		(532,404	)	$	6.20
Restricted stock units outstanding - January 31, 2012		2,488,342		$	7.02

A restricted stock unit represents a right to an unrestricted share of common stock upon satisfaction of defined service, vesting and holding conditions. Restricted stock units have a one to four year vesting schedule prior to conversion into common stock. Compensation costs for the service-based vesting restricted share units are based upon the grant-date market value of the award. Such costs are recognized ratably over the applicable vesting period.

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For the fiscal year 2012, the Company recorded $7,511,959 of stock-based compensation in general and administrative expenses related to restricted stock unit grants. The amount of expense recorded in fiscal year 2012 was impacted by the following matters. The NYSE Amex, LLC (the “NYSE Amex”) requires that all grants of stock options and awards of restricted stock units be issued under a plan approved by stockholders. Therefore, the restricted stock units that were awarded prior to the approval of the 2011 Plan by the stockholders were granted subject to the 2011 Plan, and not considered approved awards until the 2011 Plan was approved by the Company’s stockholders on July 22, 2011. As a result, stock-based compensation for awards granted on or after November 5, 2010 was not recorded until the 2011 Plan was approved on July 22, 2011. At the time the 2011 Plan was approved by the Company’s stockholders, compensation expense was recognized based on the original vesting schedule. The restricted stock units were valued at the market value of a share of common stock on the date the 2011 Plan was approved and ratified for purposes of calculating stock-based compensation.

The total grant date fair value of the restricted stock units that vested during the fiscal year ended January 31, 2012 was $3,300,905. No restricted stock units vested during the fiscal year ended January 31, 2011.

Unamortized compensation cost related to unvested restricted stock units at January 31, 2012 was $13.0 million. We expect to recognize that cost over a weighted average period of 2.4 years.

Subsequent to January 31, 2012, the Company awarded 435,000 restricted stock units to certain officers and directors. The vesting period of such restricted stock units is between one and four years.

Stock Options

All stock options outstanding are those originally issued under the Rolling Plan. The following table provides information about stock option activity during the last two fiscal years.

	Number of Shares			Weighted Average Exercise Price
Options outstanding - January 31, 2010 (183,667 exercisable)		570,000		$	5.20
Less: options canceled		(85,000	)	$	27.80
Less:  options forfeited		(62,500	)	$	17.30
Less:  options exercised		(79,167	)	$	3.00
Options outstanding - January 31, 2011 (125,833 exercisable)		343,333		$	1.60
Less:  options forfeited		(25,000	)	$	3.00
Less:  options exercised		(82,501	)	$	1.34
Options outstanding - January 31, 2012 (142,500 exercisable)		235,832		$	1.50

The intrinsic value of options exercised during fiscal year 2012 was $447,000. The Company received approximately $110,000 for the exercise of 82,501 options in fiscal year 2012.

The following table summarizes the status of stock options outstanding under the Rolling Plan:

				Number of Shares
Exercise price per share		Remaining contractual life (years)		Outstanding		Exercisable
$	3.00		1.99		34,166		34,166
$	1.25		2.83		201,666		108,334
					235,832		142,500

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Weighted average exercise price per share	$	1.50	$	1.67
Weighted average remaining contractual life		2.71		2.63
Aggregate intrinsic value, January 31, 2012	$	1,258,107	$	736,568

Options granted under the Rolling Plan expire five years from the grant date and have service-based vesting schedules of three years.

Compensation costs related to stock options are based on the grant-date fair value of the award, recognized ratably over the applicable vesting period. We estimated the fair value using the Black-Scholes option-pricing model. Expected volatilities were based on the historical volatility of our common stock. We also use historical data to estimate the probability of option exercise, expected years until exercise and potential forfeitures. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates.

Non-cash compensation cost related to our stock options was $81,057 and $93,418 for fiscal years 2012 and 2011, respectively.

As of January 31, 2012, there was $121,000 of unrecognized compensation cost related to non-vested stock options. We expect to recognize such cost on a pro rata basis over a weighted average period of one year.

A summary of the status of the Company’s non-vested options as of January 31, 2012, and changes during the years ended January 31, 2012 and 2011, is presented below:

	Number of Shares			Weighted- Average Grant Date Fair Value
Non-vested options - January 31, 2010		386,333		$	1.10
Options vested		(115,833	)	$	1.20
Less options canceled		(3,000	)		-
Less options forfeited		(50,000	)	$	1.70
Non-vested options - January 31, 2011		217,500		$	1.10
Options vested		(107,501	)	$	1.08
Less options forfeited		(16,667	)	$	2.13
Non-vested options - January 31, 2012		93,332		$	1.02

9. LOSS PER SHARE

	2012			2011
Net loss to common stockholders	$	(23,832,355	)	$	(20,277,197	)
Adjustments for dilution		-			-
Net loss adjusted for effects of dilution	$	(23,832,355	)	$	(20,277,197	)
Basic weighted average common shares		30,597,334			12,463,751
Add dilutive effects of options and restricted stock units		-			-
Diluted weighted average common shares outstanding		30,597,334			12,463,751
Net loss per common share — basic	$	(0.78	)	$	(1.63	)
Net loss per common share — diluted	$	(0.78	)	$	(1.63	)

10. RELATED PARTY TRANSACTIONS

The Company had no reportable related party transactions in fiscal years 2012 and 2011.

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11. COMMITMENTS AND CONTINGENCIES

The Company leases office facilities in Denver, Colorado and Calgary, Alberta, Canada under operating lease agreements that expire in July 2014 and September 2013. Rent expense was $200,199 and $94,351 for the years ended January 31, 2012 and 2011, respectively. The Company also leases office equipment under an operating lease that expires in 2014. The following table shows the annual rentals per year for the life of the leases:

Fiscal year ending January 31,	Annual Rental Amount
2013	$	317,429
2014	$	298,360
2015	$	51,435

As of January 31, 2012 the Company was subject to commitments on a drilling rig contract. The contract expires in September 2013. In the event of early termination of the contract, the Company would be obligated to pay an aggregate amount of approximately $12.4 million as of January 31, 2012 as required under the terms of the contract. Subsequent to year-end, the Company assumed an additional drilling rig contract commencing on April 12, 2012 for a term of 120 days. In the event of early termination under this contract, the Company would be obligated to pay an additional $2.4 million.

12.          SUBSEQUENT EVENTS

We have evaluated subsequent events and are not aware of any significant events that occurred subsequent to January 31, 2012 but prior to the filing with the SEC of this Annual Report on Form 10-K that would have a material impact on our consolidated financial statements.

13. UNAUDITED SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES

Oil and Natural Gas Operations

The following tables contain direct revenue and cost information relating to our oil and gas exploration and production activities for the periods indicated for the United States (the only geographic area in which we had proved reserves in fiscal year 2012 and fiscal year 2011). We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income tax expense related to our oil and natural gas operations is computed using the combined statutory income tax rate for the period.

	Years Ended January 31,
For U.S. Operations	2012			2011
Oil and natural gas revenues from production (all sold to unaffiliated parties)	$	8,135,972		$	563,670
Less operating costs and income taxes:
Production taxes		(896,062	)		(94,654	)
Other lease operating expenses		(922,750	)		(45,231	)
Amortization of oil and gas properties		(3,022,000	)		(96,000	)
Accretion of asset retirement obligations		(6,950	)		(5,148	)
Operating income before income tax expense		3,288,210			322,637
Less income tax expense at statutory rates		(1,227,982	)		(120,489	)
Results of oil and gas operations (excluding general corporate overhead and interest expense)	$	2,060,228		$	202,148
Amortization rate per Boe	$	27.02		$	9.48

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Costs Incurred

The following table sets forth the capitalized costs incurred in our oil and natural gas production, exploration, and development activities in the United States:

	Years Ended January 31,
	2012		2011
Costs incurred during the year:
Acquisition of properties:
Proved	$	-	$	-
Unproved		87,225,544		13,654,462
Exploration		40,727,287		4,506,389
Development		4,705,568		-
Oil and natural gas expenditures		132,655,399		18,160,851
Property sales		-		-
		132,655,399		18,160,851
Asset retirement obligations, net		3,493		69,035
	$	132,658,892	$	18,229,886

Aggregate Capitalized Costs

The table below reflects the aggregate capitalized costs relating to our U.S. oil and natural gas producing activities at January 31, 2012:

Proved properties	$	33,172,419
Unproved properties and properties under development, not being amortized		111,716,360
		144,888,779
Less accumulated amortization		(3,118,000	)
Net oil and natural gas properties	$	141,770,779

Costs Not Being Amortized

The following table summarizes oil and natural gas property costs not being amortized at January 31, 2012, by year that the costs were incurred:

2012	$	97,820,413
2011		13,895,947
	$	111,716,360

The $111.7 million of costs not being amortized includes $10.8 million of costs of unevaluated wells in progress, expected to be completed prior to January 31, 2013. On a quarterly basis, costs not being amortized are evaluated for inclusion in costs to be amortized. Upon evaluation of a well or well location having proved reserves, the associated costs are reclassified from unproved properties to proved properties and become subject to amortization over our proved reserves for the country-wide amortization base. Upon evaluation that costs of unproved properties are impaired or evaluation that a well or well location will not have proved reserves, the amount of cost impairment and well costs are reclassified from unproved properties to proved properties and become subject to amortization.

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Oil and Gas Reserve Information

All of the Company’s estimated proved reserves are located in the Williston Basin in North Dakota and Montana.

The reserve estimates presented below were made in accordance with oil and natural gas reserve estimation and disclosure authoritative accounting guidance issued by the FASB effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and natural gas reserve estimation and disclosure requirements with the requirements in the SEC’s “Modernization of Oil and Gas Reporting” rule, which was also effective for annual reports for fiscal years ending on or after December 31, 2009.

Proved reserves are the estimated quantities of oil and natural gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the two-year period ended January 31, 2012. Ryder Scott Company L.P. (“Ryder Scott”) and MHA Petroleum Consultants, independent petroleum engineering firms, determined our estimated proved oil and natural gas reserves as of January 31, 2012 and 2011, respectively. Through this process, they also determined the projected future cash flows from those proved reserves and the present value, discounted at 10% per annum, of those future cash flows. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

	January 31, 2012						January 31, 2011
	Oil (Mbbl)			Natural Gas (Mmcf)			Oil (Mbbl)			Natural Gas (Mmcf)
Total proved reserves:
Beginning of year		1,236			-			-			-
Revisions of previous estimates		(932	)		-			-			-
Extensions and discoveries		1,154			686			1,240			-
Purchases of reserves		-			-			-			-
Production		(93	)		(12	)		(4	)		-
Sale of properties		-			-			-
End of year		1,365			674			1,236			-
Proved developed reserves		538			202			215			-
Proved undeveloped reserves		827			472			1,021			-

At January 31, 2012, we had proved undeveloped oil and natural gas reserves of 905 Mboe, down 116 Mboe from 1,021 Mboe at January 31, 2011. Changes in our proved undeveloped reserves are summarized in the following table:

63

	Mboe
Proved undeveloped reserves at January 31, 2011		1,021
Net revisions		(819	)
Became developed reserves in fiscal year 2012		(53	)
Acquisitions		-
Extensions and discoveries of proved reserves		756
Oil and natural gas produced and sold in fiscal year 2012		-
Proved undeveloped reserves at January 31, 2012		905

Of the 19 gross (3 net) proved undeveloped locations at January 31, 2011, 13 gross (2.6 net) locations (with 840 net Mboe of proved reserves at January 31, 2012) were viewed by our internal reservoir engineer as unproved as of January 31, 2012 because the available geological and engineering data did not support reasonable certainty of sufficient reserves to provide a positive PV10 Value, net of estimated future development costs. Ryder Scott excluded those 13 gross (2.6 net) locations from proved reserves at January 31, 2012.

Additions to proved undeveloped reserves are for 17 drilling locations, whose status is summarized in the following table:

	PUD Locations		Development wells
			Gross		Net
Proved undeveloped locations for which
Triangle operated wells are anticipated to be drilled by 01/31/2013		4		4		1.61
Non-operated wells were in-progress at January 31, 2012 and are expected to be completed in fiscal year 2013		6		6		0.31
The outside operator already has obtained the drilling permit and expressed plans to start drilling in fiscal year 2013		6		6		0.58
We expect non-operated wells to be drilled by 01/31/2015		1		1		0.11
Total		17		17		2.61

Standardized Measure of Discounted Future Net Cash Flows

Authoritative accounting guidance by the FASB requires the Company to calculate and disclose for January 31, 2012 and 2011 (i) a standardized measure of discounted future net cash flows relating to proved oil and gas reserves (“Standardized Measure”) and (ii) changes in the Standardized Measure for fiscal years 2012 and 2011. Under that accounting guidance, future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated future proved reserve quantities. Estimated future income taxes are computed using the current statutory income tax rates and with consideration of other tax matters such as (i) tax basis of our oil and gas properties and (ii) net operating loss carryforwards relating to our oil and gas producing activities. The resulting future after-tax net cash flows are discounted at 10% per annum to arrive at the Standardized Measure. Future development and operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using year-end cost rates and assuming continuation of existing economic conditions.

The assumptions used to compute the standardized measure are those prescribed by the FASB. These assumptions do not necessarily reflect the Company’s expectations of actual net cash flows to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations. The following prices were used in the calculation of the Standardized Measure:

64

	January 31,
	2012		2011
Oil per Bbl	$	89.71	$	68.76
Natural Gas per Mcf	$	8.19		N/A

Most of our natural gas sales in fiscal year 2012 were for ‘wet’ gas sold before processing to extract natural gas liquids from the wet gas. Most of our natural gas sales in fiscal year 2011 were for ‘dry’ gas after extraction of natural gas liquids. Hence the average natural gas sales price was higher in fiscal year 2012 than in fiscal year 2011.

The following summary sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the Standardized Measure.

	January 31,
(Amounts in thousands)	2012			2011
Future cash inflows	$	127,955		$	84,954
Future Costs:
Production		(48,919	)		(19,054	)
Development		(23,362	)		(20,003	)
Future income tax expense		-			(2,627	)
Future net cash flows		55,674			43,270
10% discount factor		(26,246	)		(30,403	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	29,428		$	12,867

The principle sources of change in the Standardized Measure are shown in the following table.

	January 31,
(Amounts in thousands)	2012			2011
Standardized measure, beginning of period	$	12,867		$	-
Sales, net of production costs		(5,677	)
Net change in prices, net of production costs		973			(68	)
Extensions and discoveries, net of future production and development costs		28,540			18,959
Changes in future development costs		(494	)		(5,735	)
Previously estimated development costs incurred during the period		2,084
Revision of quantity estimates		(9,928	)
Accretion of discount		1,316
Change in income taxes		291			(291	)
Change in production rates and other		(544	)		1
Standardized measure, end of period	$	29,428		$	12,866

We calculate the projected income tax effect using the "year-by-year" method for purposes of the supplemental oil and gas disclosures and use the "short-cut" method for the ceiling test calculation. Companies that follow the full cost accounting method are required to make quarterly "ceiling test" calculations. This test ensures that total capitalized costs for oil and gas properties (net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects.

65

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

None.

ITEM 9A – CONTROLS AND PROCEDURES

MANAGEMENT’S EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is collected and communicated to management to allow timely decisions regarding required disclosures.  The Chief Executive Officer and the Chief Financial Officer have concluded, based on their evaluation as of January 31, 2012 that disclosure controls and procedures were effective in providing reasonable assurance that material information is made known to them by others within the Company.

Management’s Annual Report on Internal Control over Financial Reporting

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

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

· assessing the effectiveness of internal control over financial reporting.

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

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

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

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

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our Chief Executive Officer and our Chief Financial Officer, management assessed the effectiveness of our internal control over financial reporting as of January 31, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework.

Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of our internal control over financial reporting. Based upon the assessment, management believes that, as of January 31, 2012, our internal control over financial reporting is effective based on those criteria.

66

Changes to Internal Controls and Procedures Over Financial Reporting

We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes. The hiring on November 1, 2011 of Joseph Feiten as our principal accounting officer is an internal control change that we believe has materially and favorably affected our internal controls at January 31, 2012 and will do so for internal controls for fiscal year 2013 . Mr. Feiten served for eight years as the principal financial officer and principal accounting officer of two publicly held oil and natural gas exploration and production companies (Tipperary Corporation, followed by American Oil & Gas, Inc.) during the period June 2002 through December 2010. His previous 26 years with PricewaterhouseCoopers (“PwC”) included over 18 years specializing in the oil and natural gas industry. He is one of three co-authors of the 4^th (1996) and 5^th (2000) editions of PwC’s book Petroleum Accounting Principles, Procedures, & Issues.

67

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Triangle Petroleum Corporation:

We have audited Triangle Petroleum Corporation and subsidiaries’ (the Company) internal control over financial reporting as of January 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Triangle Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of January 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Triangle Petroleum Corporation and subsidiaries as of January 31, 2012 and the related consolidated statements of operations, cash flows, and stockholders’ equity and comprehensive loss for the year ended January 31, 2012, and our report dated April 13, 2012 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Denver, Colorado

April 13, 2012

68

ITEM 9B – OTHER INFORMATION

None.

PART III.

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information required under this item is incorporated by reference from the Triangle Petroleum Corporation definitive Proxy Statement for the 2012 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than May 30, 2012.

 ITEM 11.  EXECUTIVE COMPENSATION

Information required under this item is incorporated by reference from the Triangle Petroleum Corporation definitive Proxy Statement for the 2012 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than May 30, 2012.

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

Information required under this item is incorporated by reference from the Triangle Petroleum Corporation definitive Proxy Statement for the 2012 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than May 30, 2012.

 ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE

Information required under this item is incorporated by reference from the Triangle Petroleum Corporation definitive Proxy Statement for the 2012 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than May 30, 2012.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

 Information required under this item is incorporated by reference from the Triangle Petroleum Corporation definitive Proxy Statement for the 2012 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than May 30, 2012.

69

PART IV.

ITEM 15.  EXHIBITS 

Exhibit No.	Description
3.1	Articles of Incorporation, as amended, effective as of November 4, 2010, filed as an exhibit to the Registration Statement on Amendment No. 3 on Form S-1 filed with the Securities and Exchange Commission on November 4, 2010 and incorporated herein by reference.
3.2	Second Amended and Restated Bylaws, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 5, 2010 and incorporated herein by reference.
4.1	Specimen Common Stock Certificate, filed as an exhibit to the Registration Statement on Amendment No. 1 on Form S-1 filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.
10.01	Stock Option Plan, filed as an exhibit to the Registration Statement on Form S-8 filed with the Securities and Exchange Commission on January 31, 2011 and incorporated herein by reference.
10.02	Production Lease, dated as of April 15, 2009, by and between the Company and Her Majesty the Queen in the Right of the Province of Nova Scotia, filed as an exhibit to the Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on April 20, 2009 and incorporated herein by reference.
10.03	Overriding Royalty Agreement, dated as of June 10, 2009, by and between Elmworth Energy Corporation and Contact Exploration Inc., filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 2, 2009 and incorporated herein by reference.
10.04	Amended and Restated Employment Agreement, dated as of December 2, 2010, by and between Triangle Petroleum Corporation and Dr. Peter Hill, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 6, 2010 and incorporated herein by reference.
10.05	Amended and Restated Employment Agreement, dated as of December 2, 2010, by and between Triangle Petroleum Corporation and Jonathan Samuels filed as an exhibit to the Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 6, 2010 and incorporated herein by reference.
10.06	Deferred Share Unit Agreement, dated February 2, 2010 between Triangle Petroleum Corporation and Peter Hill, filed as an exhibit to the Registration Statement on Amendment No. 1 to Form S-1 filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.
10.07	Deferred Share Unit Agreement, dated February 2, 2010 between Triangle Petroleum Corporation and Jonathan Samuels, filed as an exhibit to the Registration Statement on Amendment No. 1 to Form S-1 filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.
10.08	Form of Deferred Share Unit Agreement entered into by each of Gardner Parker, Randal Matkaluk and Steve Holditch, each dated February 2, 2010, filed as an exhibit to the Registration Statement on Amendment No. 2 to Form S-1 filed with the Securities and Exchange Commission on November 2, 2010 and incorporated herein by reference.
14.01	Code of Business Conduct and Ethics, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.

70

21.01*	List of Subsidiaries.
23.01*	Consent of MHA Petroleum Consultants.
23.02*	Consent of Ryder Scott Petroleum Consultants.
23.03*	Consent of KPMG LLP.
23.04*	Consent of KPMG LLP — Calgary.
24.01	Power of Attorney (incorporated by reference to the signature page of this Annual Report on Form 10-K).
31.01*	Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02*	Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Reserve Estimate Report of MHA Petroleum Consultants, filed as an exhibit to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 13, 2011 and incorporated herein by reference.
99.02*	Reserve Estimate Report of Ryder Scott Company L.P.

* Filed herewith.

71

SIGNATURES

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

TRIANGLE PETROLEUM CORPORATION

Date:  April 13, 2012	By:	/s/ PETER HILL
	Peter Hill
	Chief Executive Officer (Principal Executive Officer)
Date:  April 13, 2012	By:	/s/ JONATHAN SAMUELS
	Jonathan Samuels
	President & Chief Financial Officer (Principal Financial Officer)

POWER OF ATTORNEY

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

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

Name	Position	Date
/s/ PETER HILL	Chief Executive Officer (Principal Executive Officer)	April 13, 2012
Peter Hill	and Director
/s/ JONATHAN SAMUELS	President & Chief Financial Officer (Principal Financial Officer)	April 13, 2012
Jonathan Samuels	and Director
/s/ F. GARDNER PARKER	Director	April 13, 2012
F. Gardner Parker
/s/ GUS HALAS	Director	April 13, 2012
Gus Halas
/s/ RANDAL MATKALUK	Director	April 13, 2012
Randal Matkaluk

Exhibit No.	Description
3.1	Articles of Incorporation, as amended, effective as of November 4, 2010, filed as an exhibit to the Registration Statement on Amendment No. 3 on Form S-1 filed with the Securities and Exchange Commission on November 4, 2010 and incorporated herein by reference.
3.2	Second Amended and Restated Bylaws, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 5, 2010 and incorporated herein by reference.
4.1	Specimen Common Stock Certificate, filed as an exhibit to the Registration Statement on Amendment No. 1 on Form S-1 filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.
10.01	Stock Option Plan, filed as an exhibit to the Registration Statement on Form S-8 filed with the Securities and Exchange Commission on January 31, 2011 and incorporated herein by reference.
10.02	Production Lease, dated as of April 15, 2009, by and between the Company and Her Majesty the Queen in the Right of the Province of Nova Scotia, filed as an exhibit to the Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on April 20, 2009 and incorporated herein by reference.
10.03	Overriding Royalty Agreement, dated as of June 10, 2009, by and between Elmworth Energy Corporation and Contact Exploration Inc., filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on September 2, 2009 and incorporated herein by reference.
10.04	Amended and Restated Employment Agreement, dated as of December 2, 2010, by and between Triangle Petroleum Corporation and Dr. Peter Hill, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 6, 2010 and incorporated herein by reference.
10.05	Amended and Restated Employment Agreement, dated as of December 2, 2010, by and between Triangle Petroleum Corporation and Jonathan Samuels filed as an exhibit to the Current Report on Form 8-K, filed with the Securities and Exchange Commission on December 6, 2010 and incorporated herein by reference.
10.06	Deferred Share Unit Agreement, dated February 2, 2010 between Triangle Petroleum Corporation and Peter Hill, filed as an exhibit to the Registration Statement on Amendment No. 1 to Form S-1 filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.
10.07	Deferred Share Unit Agreement, dated February 2, 2010 between Triangle Petroleum Corporation and Jonathan Samuels, filed as an exhibit to the Registration Statement on Amendment No. 1 to Form S-1 filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.
10.08	Form of Deferred Share Unit Agreement entered into by each of Gardner Parker, Randal Matkaluk and Steve Holditch, each dated February 2, 2010, filed as an exhibit to the Registration Statement on Amendment No. 2 to Form S-1 filed with the Securities and Exchange Commission on November 2, 2010 and incorporated herein by reference.
14.01	Code of Business Conduct and Ethics, filed as an exhibit to the Current Report on Form 8-K filed with the Securities and Exchange Commission on October 25, 2010 and incorporated herein by reference.

21.01*	List of Subsidiaries.
23.01*	Consent of MHA Petroleum Consultants.
23.02*	Consent of Ryder Scott Petroleum Consultants.
23.03*	Consent of KPMG LLP.
23.04*	Consent of KPMG LLP — Calgary.
24.01	Power of Attorney (incorporated by reference to the signature page of this Annual Report on Form 10-K).
31.01*	Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02*	Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Reserve Estimate Report of MHA Petroleum Consultants, filed as an exhibit to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 13, 2011 and incorporated herein by reference.
99.02*	Reserve Estimate Report of Ryder Scott Company L.P.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document

* Filed herewith.

** Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

EX-21.01

Exhibit 21.01

Triangle Petroleum Corporation

List of Subsidiaries

EXACT NAME OF SUBSIDIARY AS SPECIFIED IN ITS CHARTER	STATE OR COUNTRY OF INCORPORATION OR ORGANIZATION
Elmworth Energy Corporation	Alberta, Canada
Triangle USA Petroleum Corporation RockPile Holdings, LLC	Colorado Delaware

EX-23.01

EX-23.02

 

FAX (303) 623-4258

621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 80293 TELEPHONE 303) 623-9147

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the references to our firm, in the context in which they appear, and to the information regarding our reserves estimates of Triangle Petroleum Corporation (the “Company”) as of January 31, 2012, included in the Company’s Annual Report on Form 10-K for the year ended January 31, 2012, as well as in the notes to the financial statements included therein (the “Annual Report”).

We also consent to the incorporation by reference in the Company's registration statements (Nos. 333-175740 and 333-171959) on Form S-8 and registration statements (Nos. 333-171958 and 333-173357) on Form S-3 of the references to our firm, in the context in which they appear, and to the information regarding our reserves estimates of the Company as of January 31, 2012, included in the Annual Report.

Very truly yours,

\s\ Ryder Scott Company, L.P.

Ryder Scott Company, L.P.

April 12, 2012
Denver, CO

EX-23.03

EX-23.04

EX-31.01

EXHIBIT 31.01

CERTIFICATION

I, Peter Hill, certify that:

1. I have reviewed this annual report on Form 10-K of Triangle Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonable likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: April 13, 2012

/s/ PETER HILL

Peter Hill

Chief Executive Officer

EX-31.02

 EXHIBIT 31.02

CERTIFICATION

 I, Jonathan Samuels, certify that:

1. I have reviewed this annual report on Form 10-K of Triangle Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonable likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: April 13, 2012

/s/ JONATHAN SAMUELS

Jonathan Samuels

President & Chief Financial Officer

EX-32.01

 Exhibit 32.01

CERTIFICATIONS OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER

PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Peter Hill, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report of Triangle Petroleum Corporation on Form 10-K for the fiscal year ended January 31, 2011 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in this Annual Report on Form 10-K fairly presents in all material respects the financial condition and results of operations of Triangle Petroleum Corporation.

	By:	/S/    PETER HILL
Date: April 13, 2012	Name:	Peter Hill
	Title:	Chief Executive Officer

I, Jonathan Samuels, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report of Triangle Petroleum Corporation on Form 10-K for the fiscal year ended January 31, 2011 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in this Annual Report on Form 10-K fairly presents in all material respects the financial condition and results of operations of Triangle Petroleum Corporation.

	By:	/S/    JONATHAN SAMUELS
Date: April 13, 2012	Name:	Jonathan Samuels
	Title:	President & Chief Financial Officer

EX-99.02

Exhibit 99.02

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Basis Of Presentation

12 Months Ended

Jan. 31, 2012

Basis Of Presentation [Abstract]

Basis Of Presentation

2. BASIS OF PRESENTATION

     The accounts of Triangle Petroleum Corporation and its subsidiaries are presented in the accompanying consolidated financial statements. These consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries: (i) Elmworth Energy Corporation, incorporated in the Province of Alberta, Canada, and (ii) Triangle USA Petroleum Corporation ("Triangle USA"), incorporated in the State of Colorado, and its wholly owned subsidiaries. These consolidated financial statements also include the accounts of the Company's 83.33% owned subsidiary RockPile Holdings LLC ("RockPile"), incorporated in the state of Delaware. All significant intercompany balances and transactions have been eliminated. The Company's fiscal year-end is January 31. RockPile and another Triangle USA subsidiary have a fiscal year-end of December 31. There were no material intervening events that occurred on the two subsidiaries between December 31, 2011 and January 31, 2012.

     These consolidated financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America or GAAP, and are expressed in U.S. dollars. Preparation in accordance with GAAP requires us to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board ("FASB") and by the SEC and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3 describes our significant accounting policies. Our management believes the major estimates and assumptions impacting our consolidated financial statements are the following:

• estimates of proved reserves of oil and natural gas, which affect the calculations of amortization and impairment of capitalized costs of oil and natural gas properties;
• estimates of the fair value of oil and natural gas properties we own, particularly properties that we have not yet explored, or fully explored, by drilling and completing wells;
• estimates as to the future realization of deferred income tax assets; and
• the assumption required by GAAP that proved reserves and generally proved reserve value for measuring capitalized cost impairment be based (for each proved property) on simple averages of the preceding twelve months' historical oil and natural gas prices on the first day of each month.

     The estimated fair values of our unevaluated oil and natural gas properties affects our assessment as to whether portions of unevaluated capitalized costs are impaired, which also affects the calculation of recorded amortization and impairment expense with regards to our capitalized costs of oil and natural gas properties.

     Actual results may differ from estimates and assumptions of future events. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions used for determining proved reserves and for financial reporting.

     Certain amounts in prior years' consolidated financial statements have been reclassified to conform to the 2011 financial statement presentation.

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Description Of Business

12 Months Ended

Jan. 31, 2012

Description Of Business [Abstract]

Description Of Business

1. DESCRIPTION OF BUSINESS

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

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

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Consolidated Balance Sheets (USD $)	Jan. 31, 2012	Jan. 31, 2011
ASSETS
Cash	$ 69,567,674	$ 57,773,269
Restricted cash		105,264
Prepaid expenses	161,650	26,002
Accounts receivable:
Oil and natural gas sales	5,422,453	155,489
Trade	3,929,465	10,531
Other	465,482	66,808
Total current assets	79,546,724	58,137,363
LONG-TERM ASSETS
Unproved properties and properties under development, not being	111,716,360	15,206,667
Proved properties	33,172,419	7,023,218
Oil and gas properties, gross	144,888,779	22,229,885
Less accumulated amortization	(3,118,000)	(96,000)
Net oil and gas properties	141,770,779	22,133,885
Deposits on equipment under construction	5,647,576
Other property and equipment (less accumulated depreciation of $85,122)	1,224,675
Prepaid drilling costs and other	2,192,963	1,469,453
Deposits	203,987	290,067
Deferred tax asset - long-term
Total assets	230,586,704	82,030,768
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable	3,434,079	1,939,754
Accrued liabilities:
Exploration and development	11,807,040	875,794
Other	3,391,563	2,004,817
Asset retirement obligations	1,539,872
Total current liabilities	20,172,554	4,820,365
Asset retirement obligations	83,418	1,403,697
Total liabilities	20,255,972	6,224,062
COMMITMENTS AND CONTINGENCIES (See Note 11)
STOCKHOLDERS' EQUITY
Common stock, $0.00001 par value, 70,000,000 shares authorized;43,515,958 and 22,525,672 shares issued and outstanding at January 31,2012 and 2011, respectively	435	225
Additional paid-in capital	314,199,952	159,788,323
Accumulated deficit	(107,814,197)	(83,981,842)
Accumulated other comprehensive income
Total parent company stockholders' equity	206,386,190	75,806,706
Noncontrolling interest in subsidiary	3,944,542
Total stockholders' equity	210,330,732	75,806,706
Total liabilities and stockholders' equity	$ 230,586,704	$ 82,030,768

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Consolidated Statements Of Stockholders' Equity And Comprehensive Loss (USD $)	Oil and Gas Properties [Member] Common Stock [Member]	Oil and Gas Properties [Member] Additional Paid-In Capital [Member]	Oil and Gas Properties [Member] AOCI [Member]		Oil and Gas Properties [Member]	Common Stock [Member] Common Stock $3.30 [Member]	Common Stock [Member] Common Stock $4.30 [Member]	Common Stock [Member] Common Stock $5.50 [Member]	Common Stock [Member] Common Stock $7.50 [Member]	Common Stock [Member]	Additional Paid-In Capital [Member] Common Stock $3.30 [Member]	Additional Paid-In Capital [Member] Common Stock $4.30 [Member]	Additional Paid-In Capital [Member] Common Stock $5.50 [Member]	Additional Paid-In Capital [Member] Common Stock $7.50 [Member]	Additional Paid-In Capital [Member]	Warrants [Member]	Accumulated Deficit [Member]	Non - Controlling Interest In Subsidiary [Member]	AOCI [Member] Common Stock $3.30 [Member]		AOCI [Member] Common Stock $4.30 [Member]		AOCI [Member] Common Stock $5.50 [Member]		AOCI [Member] Common Stock $7.50 [Member]		AOCI [Member]		Common Stock $3.30 [Member]	Common Stock $4.30 [Member]	Common Stock $5.50 [Member]	Common Stock $7.50 [Member]	Total
Balance at Jan. 31, 2010										$ 70					$ 81,950,705	$ 4,237,100	$ (63,704,645)											[1]					$ 22,483,230
Balance, shares at Jan. 31, 2010										6,992,692
Stock issued, value						28	2	124			9,237,972	879,000	68,309,876							[1]		[1]		[1]					9,238,000	879,002	68,310,000
Stock issued, shares						2,799,394	204,419	12,420,000
Stock offering costs											(773,531)	(23,401)	(5,330,665)							[1]		[1]		[1]					(773,531)	(23,401)	(5,330,665)
Exercise of stock options										1					234,956													[1]					234,957
Exercise of stock options, shares										79,167
Common stock issued pursuant to termination agreements															180,000													[1]					180,000
Common stock issued pursuant to termination agreements, shares										30,000
Expiration of warrants															4,237,100	(4,237,100)												[1]
Stock-based compensation															886,311													[1]					886,311
Net loss for the year																	(20,277,197)											[1]					(20,277,197)
Year's comprehensive loss																	(20,277,197)											[1]					(20,277,197)
Balance at Jan. 31, 2011										225					159,788,323		(83,981,842)											[1]					75,806,706
Balance, shares at Jan. 31, 2011										22,525,672																							22,525,672
Stock issued, value	14	11,780,345		[1]	11,780,359				190					142,312,310												[1]						142,312,500
Stock issued, shares	1,437,699								18,975,000
Stock offering costs														(7,569,527)												[1]						(7,569,527)
Exercise of stock options										1					110,650													[1]					110,651
Exercise of stock options, shares										82,501
Common stock issued pursuant to termination agreements															184,840													[1]					184,840
Common stock issued pursuant to termination agreements, shares										24,000
Vesting of restricted stock units										5					(5)													[1]
Vesting of restricted stock, shares										471,086
Stock-based compensation															7,593,016													[1]					7,593,016
Minority equity contribution in subsidiary																		4,000,000										[1]					4,000,000
Net loss for the year																	(23,832,355)	(55,458)										[1]					(23,887,813)
Year's comprehensive loss																	(23,832,355)											[1]					(23,832,355)
Balance at Jan. 31, 2012										$ 435					$ 314,199,952		$ (107,814,197)	$ 3,944,542										[1]					$ 210,330,732
Balance, shares at Jan. 31, 2012										43,515,958																							43,515,958

[1] Accumulated Other Comprehensive Income (Loss)

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Consolidated Statements Of Stockholders' Equity And Comprehensive Loss (Parenthetical) (USD $)	Jan. 31, 2011 Common Stock $3.30 [Member]	Jan. 31, 2011 Common Stock $4.30 [Member]	Jan. 31, 2011 Common Stock $5.50 [Member]	Jan. 31, 2012 Common Stock $7.50 [Member]
Common shares, share price	$ 3.30	$ 4.30	$ 5.50	$ 7.50

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Consolidated Balance Sheets (Parenthetical) (USD $)	Jan. 31, 2012	Jan. 31, 2011
Consolidated Balance Sheets [Abstract]
Accumulated depreciation	$ 85,122
Common stock, shares authorized	70,000,000	70,000,000
Common stock, par value	$ 0.00001	$ 0.00001
Common stock, shares issued	43,515,958	22,525,672
Common stock, shares outstanding	43,515,958	22,525,672

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Related Party Transactions

12 Months Ended

Jan. 31, 2012

Related Party Transactions [Abstract]

Related Party Transactions

10. RELATED PARTY TRANSACTIONS

The Company had no reportable related party transactions in fiscal years 2012 and 2011.

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Document And Entity Information (USD $)	12 Months Ended
	Jan. 31, 2012	Mar. 31, 2012	Jul. 31, 2011
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Jan. 31, 2012
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2012
Entity Registrant Name	Triangle Petroleum Corp
Entity Central Index Key	0001281922
Current Fiscal Year End Date	--01-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		44,154,253
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 320,531,418

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Commitments And Contingencies

12 Months Ended

Jan. 31, 2012

Commitments And Contingencies [Abstract]

Commitments And Contingencies

11. COMMITMENTS AND CONTINGENCIES

     The Company leases office facilities in Denver, Colorado and Calgary, Alberta, Canada under operating lease agreements that expire in July 2014 and September 2013. Rent expense was $200,199 and $94,351 for the years ended January 31, 2012 and 2011, respectively. The Company also leases office equipment under an operating lease that expires in 2014. The following table shows the annual rentals per year for the life of the leases:

Fiscal year ending		Annual Rental
January 31,		Amount
2013	$	317,429
2014	$	298,360
2015	$	51,435

As of January 31, 2012 the Company was subject to commitments on a drilling rig contract. The contract expires in September 2013. In the event of early termination of the contract, the Company would be obligated to pay an aggregate amount of approximately $12.4 million as of January 31, 2012 as required under the terms of the contract. Subsequent to year-end, the Company assumed an additional drilling rig contract commencing on April 12, 2012 for a term of 120 days. In the event of early termination under this contract, the Company would be obligated to pay an additional $2.4 million.

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Consolidated Statements Of Operations (USD $)	12 Months Ended
	Jan. 31, 2012	Jan. 31, 2011
REVENUES
Oil and natural gas sales	$ 8,135,972	$ 563,670
EXPENSES
Production taxes	896,062	94,654
Other lease operating	1,563,400	76,859
Depletion, depreciation and amortization	3,107,122	135,296
Impairment of oil and natural gas properties	10,416,202	14,917,356
Less: gain on sale of oil and natural gas properties		(1,006,294)
Accretion of asset retirement obligations	166,925	250,319
General and Administrative:
Stock-based compensation	7,567,312	1,066,311
Salaries and benefits	4,384,085	1,211,972
Other general and administrative	4,446,910	4,189,382
Foreign exchange loss (gain)	21,938	(35,615)
Total operating expenses	32,569,956	20,900,240
LOSS FROM OPERATIONS	(24,433,984)	(20,336,570)
OTHER INCOME
Interest income	280,991	59,373
Miscellaneous income	265,180
Total other income	546,171	59,373
NET LOSS BEFORE INCOME TAXES	(23,887,813)	(20,277,197)
Income tax provision
NET LOSS	(23,887,813)	(20,277,197)
Less: net loss attributable to noncontrolling interest in subsidiary	55,458
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (23,832,355)	$ (20,277,197)
NET LOSS PER COMMON SHARE - BASIC AND DILUTED	$ (0.78)	$ (1.63)
Weighted average common shares outstanding - basic and diluted	30,597,334	12,463,751

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Asset Retirement Obligations

12 Months Ended

Jan. 31, 2012

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

5. ASSET RETIREMENT OBLIGATIONS

     The following table reflects the components of the change in the carrying amount of the asset retirement obligations for the years ended January 31, 2012 and 2011:

		2012			2011
Balance, beginning of year	$	1,403,697		$	1,180,515
Liabilities incurred		423,111			2,224
Revision of estimates		(52,966	)		-
Sale of assets		(13,822	)		-
Liabilities settled		(303,655	)		(29,361	)
Accretion		166,925			250,319
Balance, end of year		1,623,290			1,403,697
Less current portion of obligations		(1,539,872	)		-
Long-term asset retirement obligations	$	83,418		$	1,403,697

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Property And Equipment

12 Months Ended

Jan. 31, 2012

Property And Equipment [Abstract]

Property And Equipment

4. PROPERTY AND EQUIPMENT

Property and equipment as of January 31, 2012 and 2011 consisted of the following:

		2012			2011
Oil and natural gas properties, using the full cost method:
Unproved properties and properties under development, not being amortized	$	111,716,360		$	15,206,667
Proved properties		33,172,419			7,023,218
		144,888,779			22,229,885
Less accumulated amortization		(3,118,000	)		(96,000	)
Net carrying value of oil and natural gas properties		141,770,779			22,133,885
Deposits on equipment under construction		5,647,576			-
Cost of other property and equipment		1,309,797			-
Less accumulated depreciation and amortization		(85,122	)		-
Net property and equipment	$	148,643,030		$	22,133,885
Total property and equipment located in the United States	$	148,643,030		$	18,133,885
Total property and equipment located in Canada	$	-		$	4,000,000

     During fiscal year 2012, we acquired undeveloped acres from various entities and incurred drilling and completion costs for total consideration of approximately $132.7 million, comprised primarily of cash in the amount of $107.6 million, accrued costs of $13.2 million and 1,437,699 shares of our common stock with a deemed value of $11.8 million.

     We capitalized $613,656 and $0 of internal land and geology department costs in fiscal years 2012 and 2011, respectively that are directly associated with property acquisition, exploration (including lease record maintenance) and development. The internal land and geology department costs were capitalized to unevaluated costs.

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

During fiscal year 2012, we recorded a $6 million "ceiling test" impairment expense of the capitalized costs of our U.S. oil and natural gas properties.  During fiscal year 2012 and 2011, we recorded impairments of $4.4 million and $14.9 million, respectively, in connection with our properties in the Maritimes Basin of Nova Scotia.  We assess all unproved property for possible impairment annually or upon a triggering event. The assessment includes consideration of, among others, intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, governmental restrictions and the assignment of proved reserves. Nova Scotia is currently conducting an extensive hydraulic fracturing review to determine whether and how hydraulic fracturing will be allowed in the future. The review is expected to be completed in calendar year 2012. Nova Scotia also does not currently allow the common industry practice of using salt water disposal wells.  While such government restrictions remain in place, it is uneconomic to proceed in further exploration and development of these leases.  We do not know if and when the restrictions might be lifted, and we do not know if Nova Scotia would grant an extension to the leases due to Nova Scotia's existing hydraulic fracturing review.  These conditions are the primary factors that contributed to the full impairment of our Nova Scotia properties as of January 31, 2012.   Since we have no proved oil and natural gas reserves in Canada, the "ceiling test" of our Canadian oil and natural gas properties results in the expensing of the impairment of our unproved Canadian properties

Deposits on equipment under construction consist of down payments for pressure pumping equipment of RockPile. This equipment has not been put into service and is not currently depreciated. It is estimated that the equipment will go into service in the second quarter of fiscal year 2013.

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Subsequent Events

12 Months Ended

Jan. 31, 2012

Subsequent Events [Abstract]

Subsequent Events

12. SUBSEQUENT EVENTS

     We have evaluated subsequent events and are not aware of any significant events that occurred subsequent to January 31, 2012 but prior to the filing with the SEC of this Annual Report on Form 10-K that would have a material impact on our consolidated financial statements.

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Stock-Based Compensation

12 Months Ended

Jan. 31, 2012

Stock-Based Compensation [Abstract]

Stock-Based Compensation

8. STOCK-BASED COMPENSATION

     Effective January 28, 2009, the Company's board of directors approved a Stock Option Plan (the "Rolling Plan") whereby the number of authorized but unissued shares of common stock that may be issued upon the exercise of stock options granted under the Rolling Plan at any time shall not exceed 10% of the issued and outstanding shares of common stock on a non-diluted basis at any time, and such aggregate number of shares of common stock shall automatically increase or decrease as the number of issued and outstanding shares of common stock change. Upon approval of the 2011 Omnibus Incentive Plan (the "2011 Plan") by the Company's stockholders on July 22, 2011, the Rolling Plan was terminated and no additional awards may be made under such plan. All outstanding awards under the Rolling Plan shall continue in accordance with their applicable terms and conditions.

     The 2011 Plan authorizes the Company to issue stock options, stock appreciation rights ("SARs"), restricted stock and restricted stock units, performance awards, stock or property, stock awards and other stock-based awards to any employee, consultant, independent contractor, director or officer of the Company. The maximum number of shares of common stock reserved for issuance under the 2011 Plan is 4,000,000 shares, subject to adjustment for certain transactions.

We have recognized non-cash stock-based compensation cost as follows:

		Year Ended January 31,
		2012			2011
Restricted stock units	$	7,511,959		$	792,893
Stock options		81,057			93,418
Stock issued pursuant to termination agreements		184,840			180,000
		7,777,856			1,066,311
Less amounts capitalized to oil and natural gas
properties		(210,544	)		-
Compensation expense	$	7,567,312		$	1,066,311

Historical amounts may not be representative of future amounts as additional awards may be granted.

Restricted Stock Units

     The following table provides information about restricted stock unit awards granted during the last two fiscal years.

				Weighted-
				Average
				Award
	Number of			Date Fair
	Shares			Value
Restricted stock units outstanding - January 31, 2010	-
Grants in fiscal year 2011	509,636		$	5.61
Restricted stock units outstanding - January 31, 2011	509,636		$	5.61
Grants in fiscal year 2012	2,645,110		$	7.06
Forfeitures	(134,000	)	$	6.81
Lapse of restrictions	(532,404	)	$	6.20
Restricted stock units outstanding - January 31, 2012	2,488,342		$	7.02

     A restricted stock unit represents a right to an unrestricted share of common stock upon satisfaction of defined service, vesting and holding conditions. Restricted stock units have a one to four year vesting schedule prior to conversion into common stock. Compensation costs for the service-based vesting restricted share units are based upon the grant-date market value of the award. Such costs are recognized ratably over the applicable vesting period.

     For the fiscal year 2012, the Company recorded $7,511,959 of stock-based compensation in general and administrative expenses related to restricted stock unit grants. The amount of expense recorded in fiscal year 2012 was impacted by the following matters. The NYSE Amex, LLC (the "NYSE Amex") requires that all grants of stock options and awards of restricted stock units be issued under a plan approved by stockholders. Therefore, the restricted stock units that were awarded prior to the approval of the 2011 Plan by the stockholders were granted subject to the 2011 Plan, and not considered approved awards until the 2011 Plan was approved by the Company's stockholders on July 22, 2011. As a result, stock-based compensation for awards granted on or after November 5, 2010 was not recorded until the 2011 Plan was approved on July 22, 2011. At the time the 2011 Plan was approved by the Company's stockholders, compensation expense was recognized based on the original vesting schedule. The restricted stock units were valued at the market value of a share of common stock on the date the 2011 Plan was approved and ratified for purposes of calculating stock-based compensation.

The total grant date fair value of the restricted stock units that vested during the fiscal year ended January 31, 2012 was $3,300,905. No restricted stock units vested during the fiscal year ended January 31, 2011.

Unamortized compensation cost related to unvested restricted stock units at January 31, 2012 was $13.0 million. We expect to recognize that cost over a weighted average period of 2.4 years.

Subsequent to January 31, 2012, the Company awarded 435,000 restricted stock units to certain officers and directors. The vesting period of such restricted stock units is between one and four years.

Stock Options

     All stock options outstanding are those originally issued under the Rolling Plan. The following table provides information about stock option activity during the last two fiscal years.

					Weighted
					Average
		Number of			Exercise
		Shares			Price
Options outstanding - January 31, 2010 (183,667 exercisable)		570,000		$	5.20
Less: options canceled		(85,000	)	$	27.80
Less:	options forfeited	(62,500	)	$	17.30
Less:	options exercised	(79,167	)	$	3.00
Options outstanding - January 31, 2011 (125,833 exercisable)		343,333		$	1.60
Less:	options forfeited	(25,000	)	$	3.00
Less:	options exercised	(82,501	)	$	1.34
Options outstanding - January 31, 2012 (142,500 exercisable)		235,832		$	1.50

     The intrinsic value of options exercised during fiscal year 2012 was $447,000. The Company received approximately $110,000 for the exercise of 82,501 options in fiscal year 2012.

The following table summarizes the status of stock options outstanding under the Rolling Plan:

				Number of Shares
	Exercise	Remaining
	price per	contractual
	share	life (years)		Outstanding		Exercisable
$	3.00	1.99		34,166		34,166
$	1.25	2.83		201,666		108,334
				235,832		142,500
	Weighted average exercise price per share		$	1.50	$	1.67
	Weighted average remaining contractual life			2.71		2.63
	Aggregate intrinsic value, January 31, 2012		$	1,258,107	$	736,568

     Options granted under the Rolling Plan expire five years from the grant date and have service-based vesting schedules of three years.

     Compensation costs related to stock options are based on the grant-date fair value of the award, recognized ratably over the applicable vesting period. We estimated the fair value using the Black-Scholes option-pricing model. Expected volatilities were based on the historical volatility of our common stock. We also use historical data to estimate the probability of option exercise, expected years until exercise and potential forfeitures. We use U.S. Treasury bond rates in effect at the grant date for our risk-free interest rates.

     Non-cash compensation cost related to our stock options was $81,057 and $93,418 for fiscal years 2012 and 2011, respectively.

     As of January 31, 2012, there was $121,000 of unrecognized compensation cost related to non-vested stock options. We expect to recognize such cost on a pro rata basis over a weighted average period of one year.

A summary of the status of the Company's non-vested options as of January 31, 2012, and changes during the years ended January 31, 2012 and 2011, is presented below:

				Weighted-
				Average
	Number of			Grant Date
	Shares			Fair Value
Non-vested options - January 31, 2010	386,333		$	1.10
Options vested	(115,833	)	$	1.20
Less options canceled	(3,000	)		-
Less options forfeited	(50,000	)	$	1.70
Non-vested options - January 31, 2011	217,500		$	1.10
Options vested	(107,501	)	$	1.08
Less options forfeited	(16,667	)	$	2.13
Non-vested options - January 31, 2012	93,332		$	1.02

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Income Taxes

12 Months Ended

Jan. 31, 2012

Income Taxes [Abstract]

Income Taxes

6. INCOME TAXES

     Federal income tax expense (benefit) for the years presented differ from the amounts that would be provided by applying the U.S. Federal and state income tax rate. The components of the provision for income taxes are as follows for fiscal years 2012 and 2011:

		2012			2011
Current tax benefit	$	-		$	-
Deferred tax benefit		(7,874,028	)		(5,866,580	)
Valuation Allowance –
United States and Canada		7,874,028			5,866,580
Income tax expense	$	-		$	-
Loss before income taxes	$	(23,887,813	)	$	(20,277,197	)
Effective income tax rate		0	%		0	%

     Reconciliations of the income tax benefit calculated at the federal statutory rate of 35% to the total income tax (benefit) expense are as follows for fiscal years 2012 and 2011:

		2012			2011
Federal statutory tax benefit	$	8,925,740		$	7,705,335
Permanent differences		(131,527	)		(19,597	)
Difference in foreign tax rates		(600,189	)		(1,936,736	)
Effect of tax rate change		(82,859	)		-
Changes in valuation allowance		(7,874,028	)		(5,866,580	)
Other		(237,137	)		117,578
Provision for income taxes	$	-		$	-

     The difference in foreign tax rate of $600,189 is a result of adjusting the US effective tax rate of 37.4% down to the Canadian effective tax rate of 26.5%.

The components of Triangle's net deferred income tax assets are as follows for fiscal years 2012 and 2011:

		2012			2011
Current:
Assets:
Uncollectible accounts receivable	$	-		$	17,888
Non-Current:
Assets:
Canadian oil and natural gas properties		6,104,357			4,879,493
United States net losses carried forward		26,975,337			15,287,857
Canadian net losses carried forward		1,610,721			1,382,991
Asset retirement obligations		416,137			363,109
Stock-based compensation		1,957,820			638,657
Investment in RockPile		128,483			-
Property and equipment		23,059			157,219
Other		2,626			-
Total assets		37,218,540			22,727,214
Liabilities:
United States oil and natural gas properties		(8,011,710	)		(1,394,410	)
Gross deferred income tax assets		29,206,830			21,332,804
Valuation allowance		(29,206,830	)		(21,332,804	)
Net deferred income tax asset	$	-		$	-

     The Company has a U.S. net tax operating loss (NOL) carryforward of approximately $72.2 million and a Canadian NOL of approximately $6.4 million at January 31, 2012. The U.S. NOL carryforwards begin expiring in 2023 and the Canadian NOL carryforwards begin expiring in 2026.

     At January 31, 2012 and 2011, we have no unrecognized tax benefits that would impact our effective tax rate and we have made no provisions for interest or penalties related to uncertain tax positions.

The tax years for fiscal years ending 2009 to 2011 remain open to examination by the Internal Revenue Service of the United States. We file tax returns with various state taxing authorities which remain open for examination for fiscal years 2009 to 2011, except for Colorado which is open for the fiscal years 2008 to 2011. We also file returns with various Canadian taxing authorities which remain open for fiscal years 2008 to 2011.

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Capital Stock

12 Months Ended

Jan. 31, 2012

Capital Stock [Abstract]

Capital Stock

7. CAPITAL STOCK

     The Consolidated Statement of Stockholders' Equity provides a listing of changes in the common stock outstanding from February 1, 2010 to January 31, 2012.

A summary of our common stock activity for the fiscal year ended January 31, 2012 follows:

• On February 15, 2011, the Company issued 433,500 shares of common stock to Williston Exploration LLC in the second closing of the Williston acquisition.
• In March 2011, the Company issued 18,975,000 shares of common stock in a public offering for gross proceeds of $142.3 million. The Company paid approximately $7.6 million in expenses related to this offering.
• On April 1, 2011, the Company issued 1,004,199 shares of common stock to Slawson Exploration Company, LLC and certain other parties for the purchase of approximately 6,716 undeveloped net acres in Williams County, North Dakota in addition to $14.5 million paid in cash.
• The Company issued 24,000 shares of common stock pursuant to employment termination agreements.
• The Company issued 82,501 shares of common stock pursuant to the exercise of stock options.

• The Company issued 471,086 shares of common stock for restricted stock units that vested during the year.

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Loss Per Share

12 Months Ended

Jan. 31, 2012

Loss Per Share [Abstract]

Loss Per Share

9. LOSS PER SHARE

		2012			2011
Net loss to common stockholders	$	(23,832,355	)	$	(20,277,197	)
Adjustments for dilution		-			-
Net loss adjusted for effects of dilution	$	(23,832,355	)	$	(20,277,197	)
Basic weighted average common shares		30,597,334			12,463,751
Add dilutive effects of options and restricted stock units		-			-
Diluted weighted average common shares outstanding		30,597,334			12,463,751
Net loss per common share — basic	$	(0.78	)	$	(1.63	)
Net loss per common share — diluted	$	(0.78	)	$	(1.63	)

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Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
	Jan. 31, 2012	Jan. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$ (23,887,813)	$ (20,277,197)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization	3,107,122	135,296
Impairment of oil and natural gas properties	10,416,202	14,917,356
Stock-based compensation	7,567,312	1,066,311
Gain on sale of oil and natural gas properties		(1,006,294)
Accretion of asset retirement obligations	166,925	250,319
Foreign exchange changes		(2)
Changes in related current assets and liabilities:
Prepaid expenses and deposits	(135,648)	26,566
Accounts receivable:
Oil and natural gas sales	(5,266,963)
Trade	(3,918,934)
Other	(398,673)	80,956
Accounts payable and accrued liabilities	631,689	1,295,523
Asset retirement expenditures	(303,655)	(29,361)
Cash used in operating activities	(12,022,436)	(3,540,527)
CASH FLOWS FROM INVESTING ACTIVITIES
Oil and natural gas property expenditures	(107,594,044)	(16,255,639)
Purchase of other property and equipment	(1,309,797)
Restricted cash	105,264	(105,264)
Cash advanced to operators for oil and natural gas property expenditures	(723,510)	(715,009)
Deposits on equipment under construction	(5,647,576)
Non-controlling interest in RockPile Holdings LLC	4,000,000
Proceeds from return of long-term deposit	86,080
Proceeds from sale of oil and natural gas properties	46,800	976,900
Cash used in investing activities	(111,036,783)	(16,099,012)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common stock	142,312,500	78,426,848
Common stock issuance costs	(7,569,527)	(6,127,597)
Issuance of common stock for exercise of options	110,651	234,956
Cash provided by financing activities	134,853,624	72,534,207
NET INCREASE IN CASH	11,794,405	52,894,668
CASH, BEGINNING OF PERIOD	57,773,269	4,878,601
CASH, END OF PERIOD	69,567,674	57,773,269
NON-CASH INVESTING ACTIVITIES
Increased accounts payable and accrued liabilities	13,180,627	2,076,609
Issuance of common stock	11,780,344
Recognition of long-term asset retirement obligations	$ 52,668

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Summary Of Significant Accounting Policies

12 Months Ended

Jan. 31, 2012

Summary Of Significant Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

     Cash and cash equivalents consist of cash in banks in the United States and Canada. Cash equivalents are stated at cost, which approximates market value.

Fair Value

     The carrying amounts reported in the consolidated balance sheets for cash, restricted cash, accounts receivable, prepaid expenses, accounts payable and accrued liabilities approximate fair value because of the immediate or short-term maturity of these financial instruments.

Accounts Receivable and Credit Policies

     We have certain trade receivables consisting of oil and natural gas sales obligations due under normal trade terms. Our management regularly reviews trade receivables and reduces the carrying amount by a valuation allowance that reflects management's best estimate of the amount that may not be collectible. At January 31, 2012 and 2011, management had determined that no allowance for uncollectible receivables was necessary.

Oil and Natural Gas Properties

     We use the full cost method of accounting for our oil and natural gas operations. All costs associated with property acquisition, exploration, and development activities in the United States and Canada are capitalized into a United States full cost pool and a Canadian full cost pool, respectively, and amortized by cost pool over proved reserves. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and natural gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. Under the full cost method of accounting, no gain or loss is recognized upon the disposition of oil and natural gas properties unless such disposition would significantly alter the relationship between capitalized costs and proved reserves.

     Companies that follow the full cost accounting method are required to make quarterly "ceiling test" calculations for each full cost pool. This test ensures that the country-wide cost pool's total capitalized costs for oil and natural gas properties (net of accumulated DD&A and deferred income taxes) do not exceed for the sum of the present value discounted at 10% of estimated future net cash flows from the Company's proved oil and natural gas reserves in that country, the pool's cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects. If the cost pool's net capitalized costs exceed this "ceiling," the excess is charged to expense. Any recorded ceiling-test impairment of oil and natural gas properties is not reversible at a later date. See Note 4 for disclosures regarding ceiling test impairments recorded in fiscal years 2012 and 2011.

     Amortization of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves by country-wide cost pool. The capitalized costs of unevaluated properties, including those of wells in progress, are excluded from the costs being amortized. We do not have major development projects that are excluded from costs being amortized. On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Expenditures for maintenance and repairs are charged to production expense in the period incurred.

Other Property and Equipment

     We record at cost any long-lived tangible assets that are not oil and natural gas properties. Depreciation is recorded using the straight-line method over the estimated useful lives of the related assets of three to ten years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived property and equipment, other than oil and natural gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. We have not found nor recognized any impairment losses on such other property and equipment

Revenue Recognition

     Revenues from oil and natural gas sales are based on the sales method, with revenue recognized on actual volumes sold to purchasers. There is a ready market for our production, with sales occurring soon after production.

  Oil and Natural Gas Reserves

     The process of estimating quantities of oil and natural gas proved reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing estimates of proved reserves may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures.

     At January 31, 2012, 61% of our total proved reserves are categorized as proved undeveloped. All of these proved undeveloped reserves are in the Bakken Shale formation in North Dakota. Our internal reserve engineer reviews our reserve estimates at least quarterly and revises our proved reserve estimates, as significant new information becomes available.

     We use the units-of-production method to amortize the cost of our oil and natural gas properties. Changes in our estimate of proved reserve quantities will cause corresponding changes in amortization expense in periods subsequent to these changes, or in some cases, a full cost ceiling limitation charge in the period of the revision.

Income Taxes

     Income taxes are provided for the tax effects of transactions reported in the consolidated financial statements and consist of taxes currently payable plus deferred income taxes. We compute deferred income taxes using the liability method whereby deferred income taxes are provided on all temporary differences between the financial basis and the tax basis of assets and liabilities. Valuation allowances are established to reduce deferred tax assets to an amount that more likely than not will be realized.

     We assess quarterly the likelihood of realization of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as historical performance and future operating conditions (particularly as related to prevailing oil and natural gas prices).

Contingencies

     A provision for contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes subjective judgment. In many cases, this judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. We closely monitor known and potential legal, environmental, and other contingencies and periodically determine when we should record losses for these items based on information available to us. We have not accrued for any contingencies as of January 31, 2012.

Asset Retirement Obligations

     We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Oil and natural gas producing companies incur this liability for their working interest in a well at the time the well is drilled or acquired. The liability reflects a discounted present value of estimated future costs related to the plugging of wells, the removal of facilities and equipment, and site restorations. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool amortization base.

Stock-based Compensation

     We recognize compensation related to all stock-based awards, including restricted stock units and stock options, in the consolidated financial statements based on their estimated grant-date fair value. We grant various types of stock-based awards including stock options and restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock and units are valued using the market price of our common stock on the grant date. Compensation cost is recognized ratably over the applicable vesting period. See Note 8 for additional information regarding our stock-based compensation.

Earnings per Share

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

Concentration of Credit Risk

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

Off Balance Sheet Arrangements

We have no significant off balance sheet arrangements.

Segment Information

     Operating segments are components of an enterprise about which separate financial information is available that is evaluated regularly by the Company in deciding how to allocate resources and in assessing performance. The financial information is required to be reported on the basis that is used internally for evaluating segment performance and deciding how to allocate resources to segments. Through January 31, 2012, the Company operated in one segment, oil and natural gas producing activities. RockPile is a start-up company formed in October 2011, which expects to commence operations in July 2012, and will focus on providing pressure pumping and ancillary services in the Williston Basin.

Recently Issued Accounting Standards

     In May 2011, the FASB issued Accounting Standards Update 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This update does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. This update may require certain additional disclosures related to fair value measurements. The Company does not expect the adoption of this update will materially impact its financial statement disclosures.

     Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the consolidated financial statements upon adoption.

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Supplemental Oil And Natural Gas Disclosures

12 Months Ended

Jan. 31, 2012

Supplemental Oil And Natural Gas Disclosures [Abstract]

Supplemental Oil And Natural Gas Disclosures

13. UNAUDITED SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES

Oil and Natural Gas Operations

     The following tables contain direct revenue and cost information relating to our oil and gas exploration and production activities for the periods indicated for the United States (the only geographic area in which we had proved reserves in fiscal year 2012 and fiscal year 2011). We have no long-term supply or purchase agreements with governments or authorities in which we act as producer. Income tax expense related to our oil and natural gas operations is computed using the combined statutory income tax rate for the period.

		Years Ended January 31,
For U.S. Operations		2012			2011
Oil and natural gas revenues from production (all sold
to unaffiliated parties)	$	8,135,972		$	563,670
Less operating costs and income taxes:
Production taxes		(896,062	)		(94,654	)
Other lease operating expenses		(922,750	)		(45,231	)
Amortization of oil and gas properties		(3,022,000	)		(96,000	)
Accretion of asset retirement obligations		(6,950	)		(5,148	)
Operating income before income tax expense		3,288,210			322,637
Less income tax expense at statutory rates		(1,227,982	)		(120,489	)
Results of oil and gas operations (excluding general
corporate overhead and interest expense)	$	2,060,228		$	202,148
Amortization rate per Boe	$	27.02		$	9.48

Costs Incurred

     The following table sets forth the capitalized costs incurred in our oil and natural gas production, exploration, and development activities in the United States:

		Years Ended January 31,
		2012		2011
Costs incurred during the year:
Acquisition of properties:
Proved	$	-	$	-
Unproved		87,225,544		13,654,462
Exploration		40,727,287		4,506,389
Development		4,705,568		-
Oil and natural gas expenditures		132,655,399		18,160,851
Property sales		-		-
		132,655,399		18,160,851
Asset retirement obligations, net		3,493		69,035
	$	132,658,892	$	18,229,886

Aggregate Capitalized Costs

     The table below reflects the aggregate capitalized costs relating to our U.S. oil and natural gas producing activities at January 31, 2012:

Proved properties	$	33,172,419
Unproved properties and properties under development,
not being amortized		111,716,360
		144,888,779
Less accumulated amortization		(3,118,000	)
Net oil and natural gas properties	$	141,770,779

Costs Not Being Amortized

     The following table summarizes oil and natural gas property costs not being amortized at January 31, 2012, by year that the costs were incurred:

2012	$	97,820,413
2011		13,895,947
	$	111,716,360

The $111.7 million of costs not being amortized includes $10.8 million of costs of unevaluated wells in progress, expected to be completed prior to January 31, 2013. On a quarterly basis, costs not being amortized are evaluated for inclusion in costs to be amortized. Upon evaluation of a well or well location having proved reserves, the associated costs are reclassified from unproved properties to proved properties and become subject to amortization over our proved reserves for the country-wide amortization base. Upon evaluation that costs of unproved properties are impaired or evaluation that a well or well location will not have proved reserves, the amount of cost impairment and well costs are reclassified from unproved properties to proved properties and become subject to amortization.

Oil and Gas Reserve Information

All of the Company's estimated proved reserves are located in the Williston Basin in North Dakota and Montana.

     The reserve estimates presented below were made in accordance with oil and natural gas reserve estimation and disclosure authoritative accounting guidance issued by the FASB effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and natural gas reserve estimation and disclosure requirements with the requirements in the SEC's "Modernization of Oil and Gas Reporting" rule, which was also effective for annual reports for fiscal years ending on or after December 31, 2009.

     Proved reserves are the estimated quantities of oil and natural gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

     The table below presents a summary of changes in the Company's estimated proved reserves for each of the years in the two-year period ended January 31, 2012. Ryder Scott Company L.P. ("Ryder Scott") and MHA Petroleum Consultants, independent petroleum engineering firms, determined our estimated proved oil and natural gas reserves as of January 31, 2012 and 2011, respectively. Through this process, they also determined the projected future cash flows from those proved reserves and the present value, discounted at 10% per annum, of those future cash flows. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

	January 31, 2012				January 31, 2011
	Oil		Natural Gas		Oil		Natural Gas
	(Mbbl)		(Mmcf)		(Mbbl)		(Mmcf)
Total proved reserves:
Beginning of year	1,236		-		-		-
Revisions of previous estimates	(932	)	-		-		-
Extensions and discoveries	1,154		686		1,240		-
Purchases of reserves	-		-		-		-
Production	(93	)	(12	)	(4	)	-
Sale of properties	-		-		-
End of year	1,365		674		1,236		-
Proved developed reserves	538		202		215		-
Proved undeveloped reserves	827		472		1,021		-

     At January 31, 2012, we had proved undeveloped oil and natural gas reserves of 905 Mboe, down 116 Mboe from 1,021 Mboe at January 31, 2011. Changes in our proved undeveloped reserves are summarized in the following table:

	Mboe
Proved undeveloped reserves at January 31, 2011	1,021
Net revisions	(819	)
Became developed reserves in fiscal year 2012	(53	)
Acquisitions	-
Extensions and discoveries of proved reserves	756
Oil and natural gas produced and sold in fiscal year 2012	-
Proved undeveloped reserves at January 31, 2012	905

Of the 19 gross (3 net) proved undeveloped locations at January 31, 2011, 13 gross (2.6 net) locations (with 840 net Mboe of proved reserves at January 31, 2012) were viewed by our internal reservoir engineer as unproved as of January 31, 2012 because the available geological and engineering data did not support reasonable certainty of sufficient reserves to provide a positive PV10 Value, net of estimated future development costs. Ryder Scott excluded those 13 gross (2.6 net) locations from proved reserves at January 31, 2012.

Additions to proved undeveloped reserves are for 17 drilling locations, whose status is summarized in the following table:

	PUD
	Locations	Development wells
Proved undeveloped locations for which		Gross	Net
Triangle operated wells are anticipated to be drilled by 01/31/2013	4	4	1.61
Non-operated wells were in-progress at January 31, 2012 and are
______expected to be completed in fiscal year 2013	6	6	0.31
The outside operator already has obtained the drilling permit and
______expressed plans to start drilling in fiscal year 2013	6	6	0.58
We expect non-operated wells to be drilled by 01/31/2015	1	1	0.11
Total	17	17	2.61

Standardized Measure of Discounted Future Net Cash Flows

Authoritative accounting guidance by the FASB requires the Company to calculate and disclose for January 31, 2012 and 2011 (i) a standardized measure of discounted future net cash flows relating to proved oil and gas reserves ("Standardized Measure") and (ii) changes in the Standardized Measure for fiscal years 2012 and 2011. Under that accounting guidance, future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated future proved reserve quantities. Estimated future income taxes are computed using the current statutory income tax rates and with consideration of other tax matters such as (i) tax basis of our oil and gas properties and (ii) net operating loss carryforwards relating to our oil and gas producing activities. The resulting future after-tax net cash flows are discounted at 10% per annum to arrive at the Standardized Measure. Future development and operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using year-end cost rates and assuming continuation of existing economic conditions.

The assumptions used to compute the standardized measure are those prescribed by the FASB. These assumptions do not necessarily reflect the Company's expectations of actual net cash flows to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations. The following prices were used in the calculation of the Standardized Measure:

		January 31,
		2012		2011
Oil per Bbl	$	89.71	$	68.76
Natural Gas per Mcf	$	8.19		N/A

   Most of our natural gas sales in fiscal year 2012 were for 'wet' gas sold before processing to extract natural gas liquids from the wet gas.  Most of our natural gas sales in fiscal year 2011 were for 'dry' gas after extraction of natural gas liquids.  Hence the average natural gas sales price was higher in fiscal year 2012 than in fiscal year 2011.  

   The following summary sets forth the Company's future net cash flows relating to proved oil and natural gas reserves based on the Standardized Measure.

		January 31,
(Amounts in thousands)		2012		2011
Future cash inflows	$	127,955		$	84,954
Future Costs:
Production		(48,919	)		(19,054	)
Development		(23,362	)		(20,003	)
Future income tax expense		-			(2,627	)
Future net cash flows		55,674			43,270
10% discount factor		(26,246	)		(30,403	)
Standardized measure of discounted future net cash
flows relating to proved reserves	$	29,428		$	12,867

The principle sources of change in the Standardized Measure are shown in the following table.

		January 31,
(Amounts in thousands)		2012			2011
Standardized measure, beginning of period	$	12,867		$	-
Sales, net of production costs		(5,677	)
Net change in prices, net of production costs		973			(68	)
Extensions and discoveries, net of future
production and development costs		28,540			18,959
Changes in future development costs		(494	)		(5,735	)
Previously estimated development costs
incurred during the period		2,084
Revision of quantity estimates		(9,928	)
Accretion of discount		1,316
Change in income taxes		291			(291	)
Change in production rates and other		(544	)		1
Standardized measure, end of period	$	29,428		$	12,866

     We calculate the projected income tax effect using the "year-by-year" method for purposes of the supplemental oil and gas disclosures and use the "short-cut" method for the ceiling test calculation. Companies that follow the full cost accounting method are required to make quarterly "ceiling test" calculations. This test ensures that total capitalized costs for oil and gas properties (net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related tax effects.