UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(mark one)

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

For the fiscal year ended January 31, 2013

o	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)

Delaware

98-0430762

(State or Other Jurisdiction of Incorporation or

Organization)

(I.R.S. Employer Identification No.)

1200 17th St., Suite 2600, 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:
Common Stock, $0.00001 par value		NYSE MKT LLC

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 o No x

Indicate by checkmark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No x

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

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

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

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 o		Accelerated filer x

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

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

The aggregate market value of the voting common equity held by non-affiliates as of July 31, 2012, based on the closing sales price of the common stock was $247,693,375. For purposes of this computation, all officers, directors, and 5 percent beneficial owners of the registrant are deemed to be affiliates. Such determination should not be deemed an admission that such directors, officers, or 5 percent beneficial owners are, in fact, affiliates of the registrant.

As of April 15, 2013, there were 56,268,825 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 2013 Annual Meeting of Stockholders.

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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. The terms fiscal year 2013, fiscal year 2012 and fiscal year 2011 herein refers to the fiscal years ended January 31, 2013, 2012 and 2011, respectively.

ITEM 1. BUSINESS

OVERVIEW

Triangle Petroleum Corporation is an independent energy company focused on the exploration, development and production of unconventional shale oil and natural gas resources in the United States. Our oil and natural gas reserves and operations are primarily concentrated in the Bakken Shale and Three Forks formations of the Williston Basin in North Dakota and Montana. As of January 31, 2013, we held leasehold interests in approximately 86,000 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, 2013 totaled 14,637,000 Boe. We conduct our U.S. exploration and production operations through our wholly-owned subsidiary Triangle USA Petroleum Corporation (“TUSA”).

Our daily production for fiscal year 2013 averaged approximately 1,334 Boepd, with an average daily production in the fourth quarter of fiscal year 2013 of 2,099 Boepd, of which 1,439 Boepd is net to our interests in wells we operate (“operated wells”) and 660 Boepd is from wells operated by third-parties (“non-operated wells”). All production in fiscal year 2013 is from wells in North Dakota, primarily from the Bakken Shale formation and, to a lesser extent, the Three Forks formation.

As of March 31, 2013, we have completed a total of 19 (11.1 net) operated wells. During fiscal year 2014, we anticipate drilling approximately 33 (15.7 net) operated wells and completing approximately 29 (13.2 net) operated wells in North Dakota or eastern Montana. Of the 29 planned wells for fiscal year 2014, we have completed three gross wells and have an additional two gross wells in progress as of March 31, 2013. Twenty-seven of the wells are planned to be in the Bakken Shale and two are planned for the Three Forks formation. We also have economic interests in 191 (8.41 net) non-operated wells.

In our core area of North Dakota and eastern Montana, Triangle is directing resources toward its operated program to develop its approximately 36,000 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 50,000 net acre position in the Station Prospect is predominantly operated acreage with an average remaining lease term of two and one half 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 endeavor to use completion, collection and production techniques that optimize reservoir production while also reducing costs. With the completion capacity of RockPile Energy Services, LLC (“RockPile”), our wholly-owned subsidiary, we are positioned to lower our well completion costs and have greater control over drilling and completion schedules. Integrated solutions for water, oil and natural gas transportation and processing are to be provided by our 30% owned affiliate, Caliber Midstream Partners LP (“Caliber”). We expect to reduce the cost and environmental impacts of trucking, reduce or eliminate the emissions generated by the flaring of produced natural gas, and improve the efficiency and reduce the costs of winter and spring operations.

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Summary of Fiscal Year 2013 Highlights

During fiscal year 2013, we accomplished the following:

· Grew sales volumes 415% to 488.2 Mboe;

· Generated revenues of $60.7 million;

· Generated cash flow from operating activities of $2.8 million;

· Increased proved reserves 900% to 14,637 Mboe;

· Increased operated drill spacing units (“DSUs”) from 75 to 92 (from 21 to 33 DSUs in our core area);

· Commenced RockPile operations and completed 495 stages on 17 wells;

· Bought out the minority holders of RockPile making it our wholly-owned subsidiary;

· Entered into our Caliber midstream joint venture with a reputable equity partner;

· Secured a convertible promissory note investment from a reputable equity partner with a principal amount of $120 million;

· Secured a credit facility for TUSA with maximum credit available of $300 million and a borrowing base of $75 million at January 31, 2013, which has since been syndicated with an increased maximum credit availability of $500 million and a borrowing base of $110 million as of the date of this annual report; and

· Initiated a hedging program, establishing a position of approximately 1,600 Bopd hedged as of January 31, 2013 for calendar year 2013, with a weighted average collar of $86.94 to $102.15 per bbl.

Our Strategy

Our goal is to increase stockholder value by converting leasehold positions 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 2013 that the state had surpassed 735,000 barrels of oil production per day, making it the second-largest oil-producing state in the nation. We believe that the Williston Basin is still in the early stages of what may be a 20+ year development program. We believe that increased density drilling and discovery of additional geologic zones may increase the horizon of full development further. 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 sufficient additional acreage in the Williston Basin, prospective for the Bakken Shale and Three Forks formations, is and will be available for acquisition, to allow us to reach our current 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 pursue various strategies 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 plan to continue to do so.

· 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 also lowers mobilization costs. Applying zipper-fracture techniques via

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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.

· Pursue targeted, high-potential growth opportunities at RockPile. In RockPile’s first six months of operations, the company worked on 17 wells, 12 of which were operated by Triangle. We believe that RockPile’s performance on these wells compares favorably with competing providers of pressure pumping services in the Williston Basin. RockPile intends to leverage its track record of performance on Triangle wells to market the company’s services and add additional third-party customers. Additionally, RockPile’s management team possesses extensive experience in a wide variety of oilfield services beyond pressure pumping. RockPile intends to opportunistically expand its service offerings to capitalize on favorable market dynamics.

· Reduce trucking, improve production economics and increase fluid logistic efficiency on most of our operated units with the start of operations of Caliber. Caliber is a joint venture with First Reserve Energy Infrastructure Fund formed to provide complete fluid logistics services to operators in the Williston Basin. The first development phase is planned to be fully operational by the fall of 2013, and will be connected to many of Triangle’s McKenzie County wells.

Our Competitive Strengths

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

· Determined and capable management coupled with experienced operations team with history of proven success. Jon Samuels, our President and Chief Executive Officer, joined the Company in December 2009, and served as our Chief Financial Officer for over two years, following an earlier career as a member of an energy-focused investment management firm. Justin Bliffen serves as the newly appointed Chief Financial Officer, after having served for two years as the Vice President and Executive Vice President of Finance, following an earlier career as an energy derivatives trader. Joe Feiten, our Principal Accounting Officer, has over 30 years of oil and natural gas accounting experience, having recently served as Chief Financial Officer and Principal Accounting Officer of two other public oil and natural gas companies. Triangle has assembled a seasoned operations team with significant Bakken experience. Our Subsurface Manager has over 30 years of experience, including 20 years of exploring and mapping the Williston Basin. Our Vice President of Operations has over 25 years of experience, with recent years focused on horizontally drilling and completing wells in the Williston and other basins. Our Senior Reservoir Engineer and our Vice President of Land each have over 30 years of experience with U.S. oil and natural gas exploration and production, including recent years of Bakken experience. The Chief Executive Officer of RockPile Energy Services has over 30 years of experience in completions services in the Williston Basin. By combining aggressive and capital market-savvy management with decades of operational experience, Triangle believes it is uniquely well-equipped to prudently navigate the many financial and technical challenges faced by a growing an oil and natural gas company.

· We benefit from development activity in the Bakken Shale and Three Forks formations acreage. Development activity in the Williston Basin continues its steady development pace with a drilling rig count of 185 at March 15, 2013. 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 further 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 continue to advance drilling and completion technologies that have significantly reduced production risk, decreased per unit drilling and completion costs, and enhanced returns.

· Our size allows us to pursue a broader range of acquisition opportunities. Our size provides us with the opportunity to acquire smaller acreage blocks in the Williston Basin that may be less attractive to larger operators. 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

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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 in the Williston Basin.

· RockPile possesses extensive experience providing completion services in the Williston Basin. RockPile is led by a senior management team with over 200 years of oilfield services experience, including over 100 years of experience in the Williston Basin, gained at leading global oilfield service companies. Additionally, RockPile has assembled a talented team of operational professionals with significant experience in the challenging environment of the Williston Basin through a focus on recruiting and retaining employees that are native to the region. RockPile’s depth of technical, operational, and supply chain expertise is a critical component of RockPile’s service offering. To ensure RockPile’s standards of technical expertise are maintained at all levels of the organization, RockPile invests significant resources into employee development programs that combine leadership, technical, and field training components along with regular performance evaluations.

· RockPile is a promising source of strategic advantage, cost savings, and service revenues. The Williston Basin is a resource-constrained region in terms of oilfield services, infrastructure and human capital, resulting in challenging operating conditions, often amplified for relatively smaller operators such as Triangle. Pressure pumping services are often limited in availability and quality. Such services also represent a key element in completing horizontal wells. Having control over this critical component of the value chain permits us to optimize the availability and timing of critical well completions. In controlling our largest cost center, RockPile’s profits on TUSA operated wells reduce Triangle’s consolidated cost of well completions, while RockPile’s services to third-parties boost revenues and earnings.

· Caliber’s full-service fluid logistics platform offers advantages to Triangle economics. Caliber is focused on developing innovative, cost-effective, and efficient solutions to handle a producer’s oil, natural gas, produced water, and fresh water. TUSA will serve as Caliber’s first and anchor customer, allowing for firm gas gathering and processing capacity as well as competitive rates on all fluid movement. Caliber believes it can offer one-stop shopping that is unlike many of its competitors in the Williston Basin and, as such, is well positioned to add additional third-party fluid volumes to its system, allowing producers to potentially reduce costs and inefficiencies associated predominantly with trucking. Caliber is led by a customer-focused and experienced management team with a proven blend of technical, commercial, financial, land, and regulatory experience.

· We have a healthy balance sheet. As of January 31, 2013, we had approximately $33.1 million in cash, other current assets of approximately $48.1 million and an available revolver of $50.0 million against current liabilities of $77.9 million.

Fiscal Year 2014 Outlook

Our fiscal year 2014 exploration and development capital investment is expected to be approximately $245 million. This investment will be allocated to the development of wells in the Bakken Shale and Three Forks formations in North Dakota. With this investment, we plan to run three full-time rigs, drill approximately 33 gross operated wells and complete approximately 29 gross operated wells. Our oil and natural gas sales volumes are projected to increase to between 1,325 and 1,475 Mboe during fiscal year 2014 as a result of our increased capex budget for drilling.

RockPile expects to add a second pressure pumping spread and a cased-hole wireline service in the second quarter of fiscal year 2014. RockPile is projecting substantial growth in gross revenue from fiscal year 2014 operations. This growth is expected to be funded by cash provided by operating activities, a RockPile credit facility and previously announced and budgeted equity investment by Triangle in February 2013.

TUSA will begin using the services of Caliber, which is expected to provide the following benefits in fiscal year 2014:

· Integrated solution to water, oil and natural gas transportation and processing needs from one provider;

· Reduce the cost and environmental impact of trucking;

· Reduce or eliminate the emissions generated by the flaring of produced natural gas; and

· Improve the efficiency of, and reduce the cost of, winter and spring operations.

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We will regularly review our capital expenditures throughout the year and will adjust our investments based on changes in commodity prices, service costs and drilling success. We have the flexibility to adjust our capital expenditures based upon market conditions.

For fiscal year 2014, we have approximately 1,600 Bopd of our oil production price-hedged as of January 31, 2013. We do not currently have any of our natural gas production hedged. For a more complete discussion of our hedging activities, a listing of open contracts as of January 31, 2013, and the estimated fair value of those contracts as of that date, see Note 13 - Commodity Derivative Instruments, to our Consolidated Financial Statements. The open contracts are not treated as hedges for accounting purposes.

Segments

There are two reportable operating segments within Triangle. Our exploration and production operating segment and our pressure pumping services operating segment are managed separately because of the nature of their products and services. The exploration and production operating segment is responsible for finding and producing oil and natural gas. The pressure pumping services operating segment is responsible for pressure pumping for both Triangle-operated wells and wells operated by third-parties. See Note 4 - Segment Reporting, in the Consolidated Financial Statements.

Operations and Oil and Natural Gas Properties

Williston Basin

We own operated and non-operated leasehold positions in the Williston Basin. As of March 31, 2013, we have completed a total of 19 (11.1 net) operated wells and have economic interests in 191 (8.41 net) non-operated wells in the Williston Basin. During fiscal year 2014, we anticipate drilling and completing an additional 29 (13.2 net) operated wells in North Dakota or eastern Montana for completion in the Bakken Shale or Three Forks formations.

Triangle is currently running a three-rig drilling program, and we anticipate continuing a three-rig program throughout fiscal year 2014. The focus of our drilling program is on our core North Dakota acreage in McKenzie and Williams Counties.

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, 2013, we have participated in the drilling of 191 gross non-operated wells, including 126 producing wells and 65 wells in various stages of permitting, drilling or completion.

In our core area of North Dakota and eastern Montana, we are directing resources toward our operated program to develop our approximately 36,000 net acres primarily in McKenzie and Williams Counties, North Dakota. In Roosevelt and Sheridan Counties, Montana, our Station Prospect is a largely contiguous position within the thermally mature area of the Williston Basin. Our approximate 50,000 net acre position in the Station Prospect is predominantly operated acreage and provides us with a development area that we believe is scalable for the future.

Discussed below are the key aspects of our drilling program in our Williston Basin core area:

· Long Laterals. Based upon our exploration efforts, we believe that the internal rate of return of the longer ~10,000 foot laterals is higher than we achieved with our shorter laterals of 5,000 feet or less. Although utilizing long laterals is more expensive, we estimate that the additional costs of drilling the longer lateral and adding more fracture stimulation stages is offset by the associated incremental increase in oil production.

· Multi-Well Pads. We typically drill on pads with 2+ wells per pad. As we move into the development stage of drilling, we expect the average number of wells drilled from each pad to increase. We plan to capitalize on the many advantages of pad drilling, such as reduced costs of mobilization and demobilization of our drilling rigs, as well as the reduced number of drilling pads, thereby minimizing environmental impacts through less surface disturbance. Furthermore, we have seen efficiencies in our completion work as we eliminate mobilization and demobilization time for our pressure pumping company and have the ability to

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Pricing and Production Cost Information

The following table summarizes the volumes and realized prices for oil and natural gas produced and sold from the Bakken Shale and Three Forks formations properties in which we held an interest during the periods indicated. Realized prices presented below exclude the effects of hedges and derivative activities. Also presented is a summary of related production costs per Boe.

	For the fiscal years ended January 31,
	2013		2012		2011
Net Sales Volume
Oil (Bbls)	451,784		92,694		6,174
Natural gas (Mcf)	188,044		11,758		23,689
Natural gas liquids (gallons)	212,266		9,076		—
Total equivalent barrels (6 Mcf = 1 Boe)	488,179		94,870		10,122
Average Sales Price Per Unit
Oil price (per Bbl)	$	85.29	$	86.40	$	74.20
Natural gas price (per Mcf)	$	4.78	$	9.06	$	4.46
Natural gas liquids price (per gallon)	$	0.86	$	2.26	$	n/a
Weighted average price (per Boe)	$	81.15	$	85.76	$	55.69
Production tax (per Boe)	$	9.20	$	9.45	$	9.35
Lease operating expenses (per Boe)	$	7.11	$	9.50	$	3.03
Gathering, transportation and processing (per Boe)	$	0.31	$	0.23	$	1.44

Sales from our operated wells began in May 2012. Our net sales volumes from operated wells totaled 240,173 Bbls of oil for fiscal year 2013. Caliber is in the process of installing natural gas pipelines and a natural gas processing facility, which is expected to allow our operated wells to begin processing and selling natural gas by the third quarter of fiscal year 2014.

Marketing and Major Customers

Oil and Natural Gas Customers. In the U.S., sales of produced crude oil, natural gas and natural gas liquids are not regulated and are made at negotiated prices. Of our $39.6 million in revenues from oil and gas sales in fiscal year 2013, $38.5 million is revenue from the sales of crude oil, and of that approximately $20.0 million is our share of revenue from sales of crude oil from the 16 wells for which we were the well operator in fiscal year 2013.

For wells that we operate, oil production is sold at the wellhead, or a location nearby, under short term agreements with several purchasers. While the pricing terms of these agreements vary by purchaser, they all reflect a price determined by the current NYMEX West Texas Intermediate contract, less a discount that is either calculated, fixed, or a combination of calculated and fixed.

We sell our oil and natural gas to a broad portfolio of customers. In fiscal year 2013, we made sales directly to two purchasers and through three well operators where for each of those five parties, sales exceeded 10% of our total oil and natural gas revenue for fiscal year 2013. These two purchasers and three operators accounted for approximately 23%, 20%, 16%, 13% and 12%, respectively, of our total oil and natural gas sales for fiscal year 2013. Although a substantial portion of our production is purchased by, or through, these parties, we do not believe the loss of any one customer would have a material adverse effect on our business as other customers should be accessible to us. We regularly monitor the credit worthiness of customers and may require parental guarantees, letters of credit or prepayments when deemed necessary.

For our economic interests in wells operated by third-parties, substantially all of our sales of crude oil and natural gas in fiscal years 2013, 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. These third-party operators include a variety of exploration and production companies ranging 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.

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For our economic interests in wells operated by third-parties, 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 2013, 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.

Pressure Pumping Customers. The ability of RockPile to acquire and retain business depends substantially upon the number of oil and natural gas wells being drilled, the depth and drilling conditions of such wells and the number of well completions. These factors can be affected by changes in commodities prices, the overall economic environment, and industry trends and technological advancements. RockPile’s principal customers consist of independent oil and natural gas producing companies needing completion of horizontal wells in western North Dakota and eastern Montana. Since commencing operations in July 2012 and through January 31, 2013, RockPile provided pressure pumping services for twelve wells operated by TUSA and five wells operated by three third parties.

Delivery Commitments

As of January 31, 2013, TUSA had two midstream services agreements with Caliber North Dakota LLC, one for crude oil gathering, stabilization, treating and redelivery and one for (i) natural gas compression, gathering, dehydration, processing and redelivery; (ii) produced water transportation and disposal services; and (iii) fresh water transportation for TUSA’s oil and natural gas drilling and production operations. Under the agreements, TUSA committed to deliver minimum monthly revenues derived from the fees paid by TUSA to Caliber for volumes of oil, natural gas, produced water, and fresh water for a primary term of 15 years beginning on the in-service date of the Caliber facilities (the date on which the Caliber central facility has been substantially completed and has commenced commercial operation, estimated to occur between July 31, 2013 and September 1, 2013). The total revenue commitment over the 15 year term is $337,128,710, received interchangeably across all four classes of service.

Competitors

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

RockPile’s competition includes large integrated oilfield services companies, a significant number of regional competitors, and a limited number of smaller service companies. Caliber competes with both large-scale and small-scale pipeline operators, as well as trucking companies and miscellaneous oilfield services entities.

Seasonality

Due to United States refineries having to import most of their crude oil, there is little seasonality in the demand for crude oil produced in North Dakota. Oil prices in North Dakota are impacted more by global oil demand and by crude oil transportation capacity and capability from the well to U.S. refineries. Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or cool summers sometime lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during lower demand periods. This can also lessen seasonal demand fluctuations.

Certain of our drilling, completion, and other operations are subject to seasonal limitations. Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. Local heavy snows or local heavy rains can at times disrupt or slow field services, which is one reason why Triangle is in the process of having future crude oil, natural gas and produced water transported out by Caliber’s pipeline, rather than by truck, for its operated wells. See Risk Factors for additional discussion.

RockPile’s operations are conducted in areas subject to extreme weather conditions during certain parts of the year, primarily in the winter and the spring. During these periods, pressure pumping operations can be delayed because of cold, snow, and other winter weather conditions. Additionally, state and local governments in RockPile’s area of operations enact “frost laws” to protect their roadways during the spring as the ground thaws and makes the roads unstable. Passage over certain county roads is restricted by weight. For state roads, additional fees are required to get over-the-road permits. Frost laws result in logistical challenges that could potentially result in temporary service interruptions for RockPile.

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We do not currently believe that seasonal fluctuations will have a material impact on our performance.

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 our 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

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 and in some cases private parties have the power to enforce compliance with environmental 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 (“CERCLA”) 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 and cleaning up soil and groundwater contamination and threatened and actual releases of hazardous substances, and also 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 (“RCRA”) and comparable state statutes govern the management, storage, treatment and disposal of solid and hazardous waste and authorize substantial fines and penalties for noncompliance. Because petroleum and natural gas waste streams are generally exempt from CERCLA, RCRA can be used to impose penalties and other injunctive relief by both federal and state governments and private citizens upon oil and natural gas operators. Although RCRA exempts certain of our oil field wastes from treatment as hazardous wastes (for example, the waters produced from hydraulic fracturing operations), such wastes are regulated under RCRA as solid waste and by other laws. In addition, oil field wastes could be reclassified as hazardous wastes in the future, thereby making them subject to more stringent handling and disposal requirements, and this could have a material impact on us. For example, the Sierra Club has petitioned the United States Environmental Protection (“EPA”) to reclassify oil field wastes as non-exempt hazardous wastes, but EPA has yet to act on this petition.

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Water Regulation and Supplies

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, the injection of wastewater into underground wells, and also generally limit the construction of facilities in wetlands and other waters of the United States without a permit. Current uncertainty regarding the scope of the jurisdiction of federal and state governments over waters of the United States has resulted in significant regulatory uncertainty for the oil and natural gas industry, and this may increase compliance and/or enforcement risks for us. In addition, concerns regarding the underground disposal of produced water into Class II Underground Injection Wells (“UIC”), including concerns regarding seismic consequences, may result in stricter regulation and increased costs associated with oil and natural gas wastewater disposal.

The BP crude oil spill in the Gulf of Mexico and generally heightened industry scrutiny has resulted and may result in new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations relating to water protection and specifically to oil spill prevention and enforcement. The EPA has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities, and conducted public meetings around the country on this issue, which have been well publicized and well attended. This renewed focus could lead to additional federal, state and local laws and regulations affecting our drilling, fracturing and other operations, particularly with respect to water protection.

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 spills, oil pollution prevention and related matters that may impose additional regulatory burdens and compliance costs 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 United States. 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 EPA announced that it will consider federal pre-treatment standards for these wastewaters. Proposed standards are expected in 2014. We cannot predict the EPA’s future actions in this regard, but increased and more stringent future regulation of produced waters or other waste streams could have a material impact on our operations.

Our operations could also be adversely impacted if we are unable to locate sufficient amounts of water, or dispose of or recycle water, used in our exploration and production operations. Currently, the quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints and supply concerns (particularly in some parts of the country). Moreover, the imposition of new environmental initiatives and conditions could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with exploration, development or production of oil and natural gas.

Air Emissions and Climate Change

The federal Clean Air Act (the “CAA”) and implementing state air quality laws and regulations impose permit requirements, operational restrictions, and emission control requirements on certain sources of emissions used in our operations. In August 2012, the EPA published final New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAPs”) that amend existing NSPS and NESHAPs applicable to the oil and natural gas industry and create new air quality-related standards for oil and natural gas production, transmission and distribution facilities. Importantly, these new standards include requirements for hydraulically fractured natural gas wells. The standards would apply to newly drilled and fractured natural gas wells, as well as existing natural gas wells that are refractured. Although the requirements of the new regulations applicable to hydraulically fractured natural gas wells do not become effective until 2015, other requirements of these new and revised standards may require us to modify our current facilities and operations and may increase future costs of our operations. In a report issued in late 2011, the Shale Gas Production Subcommittee of the Department of Energy (the “DOE Shale Gas Subcommittee”) encouraged states to take similar action, and included several other

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recommendations for studying and reducing air emissions from shale gas production activities. On March 28, 2013, EPA proposed to modify certain requirements of the NSPS applicable to storage tanks.

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. In June 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the CAA’s Prevention of Significant Deterioration and Title V permitting programs. This rule, known as the “Tailoring Rule,” tailors the permitting thresholds under these programs to apply, at least initially, only to larger stationary sources of GHG emissions. EPA intends to revisit these GHG permitting thresholds by 2016. Additionally, on June 26, 2012, the United States Court of Appeals for the District of Columbia Circuit issued an opinion and order in Coalition for Responsible Regulation v. Environmental Protection Agency, No. 09-1322, upholding EPA’s GHG-related rules, including the “Tailoring Rule,” against challenges from various state and industry group petitioners. In addition, 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. In a 2011 report, the DOE Shale Gas Subcommittee recommended that the EPA expand reporting requirements for GHG emissions from shale gas emission sources. 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.

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. 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 SDWA, the EPA is prohibited from regulating the injection of fracking fluids through its UIC 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 water-cycle impacts of fracking, including potential effects on drinking water, as a result of Congressional and public concern. The EPA has released limited information about this study, with a full report on EPA’s findings expected in 2014.

Related to EPA’s hydraulic fracturing study, the EPA has issued a series of reports indicating that contamination may have resulted from certain fracking operations in Pavillion, Wyoming. The operator of the wells has challenged the EPA’s findings, contending that other activities, including natural methane migration, may have caused contamination in the groundwater. As a result, EPA has again delayed resolution of the issue to accept further public comment. Nonetheless, the Pavillion matter has drawn increased attention to the oil and natural gas industry, and more specifically, potential groundwater impacts from hydraulic fracturing. While it is impossible to predict the outcome of EPA’s study or the Pavillion case, these initiatives could result in additional and more stringent federal regulation of oil and natural gas operations. Other federal agencies, including the Department of Energy and the Department of Interior, and the United States Congress are also investigating the potential impacts of fracking. In addition, bills have been introduced in the United States Congress to amend the SWDA to authorize EPA to regulate the injection of fracking fluids regardless of diesel content. The success of such legislation is uncertain, but if successful it could require our and similar operations to meet increased federal permitting and/or financial assurance requirements, adhere to more stringent construction and testing specifications, increased monitoring, reporting, and recordkeeping obligations, and meet stricter closure 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. The BLM is currently revising its proposed regulation. Finally, the EPA is in the initial stages of a Toxic Substances Control Act (“TSCA”) rulemaking, which will collect expansive information on the chemicals used in hydraulic fracturing fluid,

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including health-related data, from chemical manufacturers and processors. The TSCA rulemaking follows the general trend of increased disclosure and transparency associated with the chemicals used in hydraulic fracturing among the various states (e.g., North Dakota), including widespread participation by industry in a publicly searchable registry website developed and maintained by the Ground Water Protection Council (“FracFocus”). All of these initiatives present significant, but uncertain, risk of additional regulation of the oil and natural gas industry.

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 certain states, local governments have passed moratoriums or have otherwise sought to limit oil and natural gas exploration and production within their jurisdictions. Local governments in Pennsylvania, New York, and Colorado have been particularly active in this respect. These efforts often have been aided by national interest groups. Local regulations of this type, combined with increased “setback” requirements, may increase the costs and limit the extent of our operations.

In addition, as briefly noted above, concerns have been raised about the potential for earthquakes associated with disposal of produced waters into Class II UIC wells. The EPA’s current regulatory requirements for such wells do not require the consideration of seismic impacts when issuing permits. Some environmental groups 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 UIC disposal 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 in Note 5 — Property and Equipment in the accompanying consolidated financial statements, Nova Scotia, where we own oil and natural gas properties, is currently evaluating how fracking should be regulated and does not allow the use of salt water disposal wells.

Formation

We were incorporated in the State of Nevada on December 11, 2003, under the name Peloton Resources Inc. On May 10, 2005, we changed our name to “Triangle Petroleum Corporation.” On November 30, 2012, we changed our state of incorporation from Nevada to Delaware.

Employees and Office Facilities

As of March 31, 2013, we had 165 full time employees (including 107 employed by RockPile).

We maintain our principal office at 1200 17th Street, Suite 2600, 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 12,134 square feet in our 1200 17th Street 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 an unrelated party. The Calgary, Alberta lease runs until September 2013 and is subleased to an unrelated entity. The 1200 17th Street lease began in June 2012 and runs through September 2017. Monthly rental payments under the leases are $4,816 for the 1625 Broadway office, $26,290 for the 1200 17th Street office and CDN $6,460 for the Calgary, Alberta office.

RockPile’s and Caliber’s headquarters are currently located at 1600 Wynkoop Street, Suite 900, Denver, CO 80202. We lease approximately 9,144 square feet of office space pursuant to a lease expiring on June 30, 2014. Monthly rental payments under the lease are $19,812. Additional properties owned or leased by RockPile and Caliber include:

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· Field Operations Headquarters. RockPile is in the process of constructing an approximately 31,000 square foot shop and office facility in Dickinson, ND. The shop will serve as RockPile’s base of operations in the Williston Basin.

· Employee Housing Facilities. RockPile is in the process of completing construction of a 20 unit multi-family development in Dickinson, ND, which will be made available to RockPile employees. A portion of the development is currently occupied and RockPile expects the facility to be completed by the second quarter of fiscal year 2014.

· Proppant and Rail Facility. RockPile operates a proppant distribution facility in Dickinson, ND. The facility is adjacent to the Field Operations Headquarters (described above) and consists of 10 million pounds of proppant storage capacity, a rail spur off of BNSF Railway’s line running through Dickinson, storage for approximately 45 rail cars, weight scales, and transloading equipment. The proppant storage facility rests on a parcel of land secured by a 10 year lease expiring March 1, 2022 with extension options thereafter. The lease also provides for RockPile’s use of the aforementioned rail spur. The proppant storage facility, weight scales, and transloading equipment are owned by RockPile.

· Transloading and Rail Car Storage Facility. RockPile has secured access to 1,700 linear feet of rail car storage and transloading services in Dore, ND pursuant to a Transload Service Agreement expiring on approximately June 1, 2015, subject to certain renewal options. The Transload Service Agreement provides for lease payments due from RockPile as well as minimum transload fees which RockPile is obligated to meet.

· Caliber Central Facility. Caliber is in the process of constructing its central facility, covering approximately 40 acres and located in Township 150 North, Range 101 West, Section 36 SESW. With a planned in-service date of August 1, 2013, the Caliber central facility will house the following:

· a gas processing facility, which will process natural gas using mechanical refrigeration; and

· a crude oil processing facility, which will process oil using centralized stabilization and vapor recovery.

· Freshwater Pump Station. The Caliber Freshwater Pump Station is located on a 1-acre site Caliber purchased in Township 150 North, Range 101 West, Section 12 SWSW. The Freshwater Pump Station is a pump and meter station that will centralize freshwater for delivery through Caliber pipeline.

· Produced Water Facility. Caliber holds a lease for 5.22 acres at the Lewis Saltwater Disposal well, located in Township 150 North, Range 101 West, Section 25 SWSW. These 5 acres house associated saltwater disposal facilities.

Available Information

We maintain a website at http://www.trianglepetroleum.com. The information contained on or accessible through our website is not part of this Annual Report on Form 10-K. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to reports filed or furnished pursuant to Sections 13(a) and 15(d) of the Exchange Act, are available on our website, free of charge, as soon as reasonably practicable after we electronically file such reports with, or furnish those reports to, the SEC.

We maintain a Code of Business Conduct and Ethics for Directors, Officers and Employees (“Code of Conduct”). A copy of our Code of Conduct may be found on our website in the Corporate Governance section. Our Code of Conduct contains information regarding whistleblower procedures. In the event our board of directors approves an amendment to or waiver from any provision of our Code of Conduct, we will disclose the required information pertaining to such amendment or waiver on our website at http://www.trianglepetroleum.com.

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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.

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 an Accelerated Filer under the Exchange Act. We are subject to certain disclosure filing requirements, including filing Form 10-K annually and Form 10-Qs 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”).

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, plans, prospects, 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,” “likely,” “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:

· our future capital expenditures and performance;

· anticipated drilling and development;

· 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;

· lack of diversification;

· substantial capital requirements and access to additional capital;

· our plans for RockPile;

· our plans for Caliber;

· 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;

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· 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.

Delay rental. A payment made to the lessor under a non-producing oil and natural gas lease at the end of each year to continue the lease in force for another year during its primary term.

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.

Development well. A well drilled to a known producing formation in a previously discovered field, usually offsetting a producing well on the same or an adjacent oil and natural gas lease.

Drill Spacing Unit. An area allotted to a well by regulations or field rules issued by a governmental authority having jurisdiction for the drilling and production of a 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.

EUR. Estimated ultimate recovery. EUR is an approximation of the quantity of oil or natural gas that is potentially recoverable or has already been recovered from a reserve or well.

Exploratory well. A well drilled either (a) in search of a new and as yet undiscovered pool of oil or natural gas or (b) with the hope of significantly extending the limits of a pool already developed.

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

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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.

Forced Pooling. The act of being forced by state law into participation in an oil and/or natural gas producing unit. Pooling is a technique used by oil and natural gas development companies to organize an oil or natural gas field.

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

Fracturing. Mechanically inducing a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock in order to enhance the permeability of rocks greatly by connecting pores together. See Hydraulic fracturing.

Gas or Natural gas. The lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain liquids.

GHGs. Green House Gases. Gases, such as carbon dioxide and methane, that when released into the atmosphere contribute to, or are believed to contribute to, global warming. The EPA has issued a notice of finding and determination that emissions of GHGs present an endangerment to human health and the environment, which allows EPA to regulate GHG emissions under existing provisions of the federal Clean Air Act.

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

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

Hydraulic fracturing. A procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases permeability and porosity.

Horizontal drilling. A well bore that is drilled laterally.

Landowner royalty. That interest retained by the holder of a mineral interest upon the execution of an oil and natural gas lease, which in the U.S. usually falls in the range of 12.5% to 20% of all gross revenues from oil and natural gas production unencumbered with any expenses of operation, development, or maintenance, except for state and local production taxes on the royalty.

Leases. Full or partial interests in oil or natural gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.

Mbbls. Thousand stock tank barrels used in this report in reference to crude oil or other liquid hydrocarbons.

Mboe. Thousand 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.

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Mgal. Thousand gallons of liquid hydrocarbons.

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

Net revenue interest. Working interest less all royalties, overriding royalties, non-participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.

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.

NYMEX. New York Mercantile Exchange.

Overriding royalty. An interest in the gross revenues or production over and above the landowner’s royalty carved out of the working interest and also unencumbered with any expenses of operation, development or maintenance, except for state and local production taxes on the overriding royalty.

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.

Operator. The individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.

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.

Pressure Pumping. The overall business of pumping a fluid down a well for the purpose of improving production from the well. This is a generic term used to mean that a pump truck or trucks are called to a well site to pump into the well.

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.

Proppant. Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

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.

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.

Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where relatively major capital expenditures are required to start producing the proved undeveloped reserves.

PV-10 value. The present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of

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the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the Company’s proved reserves on a comparative basis to other companies’ reserves and from period to period.

Recompletion. The completion for production from an existing wellbore in a formation other than that in which the well has previously been completed.

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.

Reserve life. Represents the estimated net proved reserves at a specified date divided by actual production for the preceding 12-month period.

Royalty. The share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well, except for state and local production taxes.

Royalty interest. An interest in an oil and natural gas property entitling the owner to shares of oil and natural gas production, free of costs of exploration, development and production operations except for state and local production taxes.

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.

Undeveloped acreage. Lease acres 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 regardless of whether or not such acreage contains proved reserves.

Undeveloped leasehold acreage. The leased 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, regardless of whether such acreage contains estimated net proved reserves.

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.

Zipper fracturing. The process of hydraulic fracturing two horizontal wells simultaneously. The wells are drilled in the same direction with their laterals spaced a given distance apart. The fracturing (“frac”) operations are then alternated between each of the wells, (e.g. frac stage 1 in well #1 and then alternating to stage 1 in well # 2, stage 2 in well #1, stage 2 in well #2, and so on, until all stages are complete in each well). The result is a zipper-like appearance of the fracs between the two wells.

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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 Statements 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. Except where the context otherwise indicates, references below to “we,” “our,” “ours,” and “us” includes our subsidiaries, including our interest in Caliber.

The risks described below relating to oil and natural gas exploration, exploitation and development activities affect TUSA directly but also affect RockPile and Caliber because the materialization of those risks, whether experienced by TUSA or other customers or potential customers of RockPile or Caliber, may adversely affect demand for the products and services provided by RockPile and Caliber.

Risks Relating to Our Business

Oil and natural gas prices are volatile and change for reasons that are beyond our control. Decreases in the price we receive for our production adversely affect our business, financial condition, results of operations and liquidity.

Declines in the prices we receive for our production adversely affect many aspects of our business, including our financial condition, revenues, results of operations, liquidity, rate of growth and the carrying value of our properties, all of which depend primarily or in part upon those prices. Declines in the prices we receive for our production also adversely affect our ability to finance capital expenditures, make acquisitions, raise capital and satisfy our financial obligations. In addition, declines in prices reduce the amount of oil and natural gas that we can produce economically and, as a result, adversely affect our quantities of proved reserves. Among other things, a reduction in our reserves can limit the capital available to us, as the maximum amount of available borrowing under our revolving credit facility is, and the availability of other sources of capital likely will be, based to a significant degree on the estimated quantities of those reserves. Declines in prices would also reduce the demand for services provided by RockPile and Caliber, adversely affecting their revenue and profitability.

Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Prices have historically been volatile and are likely to continue to be volatile in the future. The prices of oil and natural gas are affected by a variety of factors that are beyond our control, including changes in global supply and demand for oil and natural gas, domestic and foreign governmental regulations and taxes, the level of global oil and natural gas exploration activity and inventories, the price, availability and consumer acceptance of alternative fuel sources, the availability of refining capacity, technological advances affecting energy consumption, weather conditions, speculative activity, financial and commercial market uncertainty and worldwide economic conditions

In addition to factors affecting the price of oil and natural gas generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. Pricing can be influenced by, among other things, local or regional supply and demand factors (such as refinery or pipeline capacity issues, trade restrictions and governmental regulations) and the terms of our sales contracts. The prices that we receive for our production are often at a discount to the relevant benchmark prices on NYMEX. A negative difference between the benchmark price and the price received is called a differential. The differential may vary significantly due to market conditions, the quality and location of production and other factors. Due to increasing production from the Williston Basin in recent years and limits to the available takeaway capacity and related infrastructure, the differential applicable to oil produced there has been significant. We cannot accurately predict future differentials, and increases in differentials could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, the difficulty involved in predicting the differential also makes it more difficult for us to effectively hedge our production.

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 $13.8 million and $24.3 million for the fiscal

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years ended January 31, 2013 and 2012, 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.

Oil and natural gas exploration, exploitation and development activities may not be successful and could result in a complete loss of a significant investment.

Exploration, exploitation and development activities are subject to many risks. For example, new wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. 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. Similarly, decline rates from a productive well may exceed our estimates and may cause the well to become uneconomic. We engage in exploratory drilling, which increases these risks. Drilling for oil and natural gas often involves unprofitable efforts not only from dry holes, but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. Cost-related risks are exacerbated in the Williston Basin because the drilling and completion of a well there generally costs significantly more than a typical onshore conventional well. Further, our exploration, exploitation and development activities may be curtailed, delayed or canceled as a result of numerous factors, including:

· title problems;

· problems in delivery of our oil and natural gas to market;

· pressure or irregularities in geological formations;

· equipment failures or accidents;

· adverse weather conditions;

· reductions in oil and natural gas prices;

· compliance with environmental and other governmental requirements, including with respect to permitting issues; and

· costs of, or shortages or delays in the availability of, drilling rigs, equipment, qualified personnel and services.

We expect that all of the wells we drill in fiscal year 2014 will be drilled horizontally and will be hydraulically fractured. When drilling horizontal wells, the risks we face include, but are not limited to, failing to place our well bore in the desired target producing zone, not staying in the desired drilling zone while drilling horizontally through the formation, failing to run casing the entire length of the well bore and not being able to run tools and other equipment consistently through the horizontal well bore. Risks we face while completing such wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, failing to run tools the entire length of the well bore during completion operations, and not successfully cleaning out the well bore after completion of the final fracture stimulation stage. Because of the cost typically associated with this type of well, unsuccessful exploration or development activity affecting even a small number of these wells could have a significant impact on our results of operations.

Our planned operations will require additional capital that may not be available.

Our business is capital intensive and requires substantial expenditures to maintain currently producing wells, to make the acquisitions and/or conduct the exploration, exploitation and development activities necessary to replace our reserves, and to pay expenses and to satisfy our other obligations. Cash flow from operations has not to date been a material source of liquidity for us, which makes us dependent on external financing . In addition, our existing asset base is small compared to many of our public company competitors, which may make financing more difficult. We anticipate that we will continue to 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. We cannot assure you that our cash flows from operations and other available sources of financing will be adequate for us to implement our capital plans and to satisfy our debt-related and other obligations. Debt or equity financing may not be available in a timely manner, on terms acceptable to us or at all. 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 and

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prospects.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or the relevant underlying assumptions will materially affect the quantity and present value of our reserves.

The reserve data included in this report represent estimates only. Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various estimates, including estimates based upon assumptions relating to economic factors, such as future commodity prices, production costs, severance and excise taxes and availability of capital, estimates of required capital expenditures and workover and remedial costs, and the assumed effect of governmental regulation. The assumptions underlying our estimates of our proved reserves could prove to be inaccurate, and any significant inaccuracy could materially affect, among other things, future estimates of our reserves, the economically recoverable quantities of oil and natural gas attributable to our properties, the classifications of reserves based on risk of recovery and estimates of our future net cash flows.

At January 31, 2013, approximately 59% of our estimated net remaining proved reserves (Mboe) were proved undeveloped (“PUD”). Estimation of PUD reserves is almost always based on analogy to existing wells as contrasted with the performance data used to estimate producing reserves. Recovery of PUD reserves requires significant capital expenditures and successful drilling operations.

Additionally, SEC rules require that, subject to limited exceptions, PUD reserves may only be recorded if they relate to wells scheduled to be drilled within five years after the date of booking. This rule has limited and may continue to limit our potential to record additional PUD reserves as we pursue our drilling program. Moreover, we may be required to write-down our PUDs if we do not drill those wells within the required five-year time frame. Our PUD reserve estimates as of January 31, 2013 reflected our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including currently estimated expenditures of approximately $196 million during the five years ending on January 31, 2018. You should be aware that the estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves.

You should not assume that the present values referred to in this report represent the current market value of our estimated oil and natural gas reserves. The timing and success of the production and the expenses related to the development of oil and natural gas properties, each of which is subject to numerous risks and uncertainties, will affect the timing and amount of actual future net cash flows from our proved reserves and their present value. In addition, our PV-10 estimates are based on assumed future prices and costs. Actual future prices and costs may be materially higher or lower than the assumed prices and costs. Further, the effect of derivative instruments is not reflected in these assumed prices. Also, the use of a 10% discount factor to calculate PV-10 may not necessarily represent the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

We are subject to complex laws and regulations, including environmental laws and regulations, that can adversely affect the cost, manner and feasibility of doing business and limit our growth.

Our operations and facilities are subject to extensive federal, state, local and foreign laws and regulations relating to exploration for, and the exploitation, development, production and transportation of, oil and natural gas, as well as environmental, safety and other matters. Existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations, may harm our business, results of operations and financial condition. Laws and regulations applicable to us include those relating to:

· land use restrictions;

· drilling bonds and other financial responsibility requirements;

· spacing of wells;

· emissions into the air;

· unitization and pooling of properties;

· habitat and endangered species protection, reclamation and remediation;

· the containment and disposal of hazardous substances, oil field waste and other waste materials;

· the use of underground storage tanks;

· transportation and drilling permits;

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· the use of underground injection wells, which affects the disposal of water from our wells;

· safety precautions;

· hydraulic fracturing (including limitations on the use of this technology);

· the prevention of oil spills;

· the closure of production facilities;

· operational reporting; and

· taxation and royalties.

Under these laws and regulations, we could be liable for:

· personal injuries;

· property and natural resource damages;

· releases or discharges of hazardous materials;

· well reclamation costs;

· oil spill clean-up costs;

· other remediation and clean-up costs;

· plugging and abandonment costs;

· governmental sanctions, such as fines and penalties; and

· other environmental damages.

These regulations have been changed frequently in the past and, in general, these changes have imposed more stringent requirements that increase operating costs and/or require capital expenditures to remain in compliance. For example, North Dakota, a state in which we conduct operations, recently amended its 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 of drilling activities. Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities, including suspension or termination of operations. Some environmental laws and regulations impose strict liability. Strict liability means that in some situations we could be exposed to liability for clean-up costs and other damages as a result of conduct that was lawful at the time it occurred or for the conduct of prior operators of properties we have acquired or other third-parties, including, in some circumstances, operators of properties in which we have an interest and parties that provide transportation services for us. Similarly, some environmental laws and regulations impose joint and several liability, meaning that we could be held responsible for more than our share of a particular reclamation or other obligation, and potentially the entire obligation, where other parties were involved in the activity giving rise to the liability. In addition, we may be required to make large and unanticipated capital expenditures to comply with applicable laws and regulations, for example by installing and maintaining pollution control devices. In addition, our plugging and abandonment obligations will be substantial and may be more than our estimates. Our operations could also be adversely affected by environmental and other laws and regulations that require us to obtain permits before commencing drilling or other activities. Even when permits are granted, they may be subject to conditions which impose delays on a project, increase its costs or reduce its benefits to us.

In addition, any changes in applicable laws, regulations and/or administrative policies or 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 that could fundamentally alter our ability to carry on our business or otherwise adversely affect our results of operation and financial condition.

Caliber’s operations may be subject to additional regulatory risks. For example, its pipelines may in the future be subject to siting, public necessity, rate and service regulations by the Federal Energy Regulatory Commission (“FERC”) or various state regulatory bodies, depending upon jurisdiction. FERC generally regulates the transportation of natural gas, NGLs and crude oil in interstate commerce. FERC’s actions in any of these areas or modifications of its current regulations could adversely impact Caliber’s ability to compete for business, the costs it incurs in its operations, the construction of new facilities or its ability to recover the full cost of operating its pipelines. Other laws and actions by federal and state regulatory authorities could have similar effects on Caliber’s operations.

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Acquisitions may prove to be unprofitable 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, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In addition, 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 connection with our assessment of a potential acquisition, we perform a review of the acquired properties that we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems, and generally 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, we may assume unknown liabilities that could have a material adverse effect on our business, financial condition and results of operations.

We have a limited operating history.

We have a limited operating history conducting oil and natural gas exploration and production activities. The history of RockPile and Caliber are more limited, as both of those entities began conducting operations in fiscal year 2013. Each of these businesses 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 our development 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 these 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 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 higher 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 longer 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 favorable 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.

The lack of availability or high cost of drilling rigs, fracture stimulation crews, equipment, supplies, insurance, personnel and oilfield 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 commodity prices, 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.

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Increased activity in the Williston Basin has resulted in increases in the cost of these products and services. Such cost increases adversely affect the results of our exploration and production business.

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 oilfield services, to drill and develop certain of 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 we encounter unanticipated problems in connection with such transactions, 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.

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

It is often not possible to determine title to an oil and natural gas interest without incurring substantial expense. The title review processes we have conducted with respect to certain interests we have acquired may not have been sufficient to detect all potential defects, and we have not conducted such a process with respect to all our properties. If a title defect does exist, it is possible that we may lose all or a portion of our interest in 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, accounting, 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 occurrence 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 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 within specified periods of time, 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 implementing our exploration and development plan, but the funds needed to do so may not be available and our exploration and development activities may be unsuccessful. Our future oil and natural gas reserves and production, and therefore our future cash flow and income, are highly dependent on our success in 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 impairments.

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 (or by an experienced petroleum engineer on our staff and audited by an independent petroleum engineering firm) 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 recognized such impairment expense in the fiscal year ended January 31, 2012. 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.

Other companies operated properties representing approximately 31% of our production in the fourth quarter of fiscal year 2013. We have limited ability to exercise influence over, or 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 expertise and financial resources, inclusion of other participants in drilling wells and use of technology. In addition, we could be adversely affected by our lack of control over the timing and amount of capital expenditures related to non-operated properties.

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. RockPile and Caliber also focus on the Williston Basin areas of those states. Larger companies have the ability to manage their risk by diversification. However, we currently lack diversification in terms of the 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, and this increases our risk profile.

We face strong competition from other companies.

We encounter competition from other companies involved in the oil and natural gas industry 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 we do. 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

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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 on 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. 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. Similarly, the market for RockPile’s services and products is characterized by continual technological developments to provide better and more reliable performance and services. If they are not able to design, develop, and produce commercially competitive products and to implement commercially competitive services in a timely manner in response to changes in technology, their business could be materially and adversely affected.

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 that may ultimately flow 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 from the Bakken Shale has a high Btu content that requires natural 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 natural gas gathering and processing capacity. Such shortage has limited our ability to sell our natural gas production. As a result, the majority of our natural gas from the Williston Basin wells to date has been flared.

The lack of available capacity in any of the gathering, processing and pipeline systems we use 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.

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

A U.S. or global economic downturn could have a material adverse effect on our business and operations.

Any or all of the following may occur if a crisis arises in the global financial and securities markets and an economic downturn results:

· The economic slowdown could lead to lower demand for oil and natural gas by individuals and industries, which in turn has resulted and could continue to result in lower oil and natural gas prices.

· The lenders under our revolving credit facility may become more restrictive in their lending practices or unable or unwilling to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth.

· We may be unable to obtain additional debt or equity financing, which would require us to limit our capital expenditures and other spending. Financing costs may significantly increase as lenders may be reluctant to lend without receiving higher fees and spreads.

· The losses incurred by financial institutions as well as the insolvency of some financial institutions heightens the risk that a counterparty to our hedge arrangements could default on its obligations. These losses and the possibility of a counterparty declaring bankruptcy or being placed in conservatorship or receivership may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when we are also receiving a lower

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price for our natural gas and oil sales. As a result, our financial condition could be materially adversely affected.

· TUSA’s credit facility requires the lenders to re-determine our borrowing base periodically. The re-determinations are based on our proved reserves based on price assumptions that our lenders require us to use to calculate reserves pursuant to the credit facility. The lenders could reduce their price assumptions used to determine reserves for calculating our borrowing base due to lower commodities and futures prices, which could result in the reduction of our borrowing base and funds available to borrow.

· Bankruptcies of purchasers of our oil and natural gas could lead to the delay or failure of us to receive the revenues from those sales.

· A generally reduced availability of capital would likely lead to a decreased demand for the services provided by RockPile and Caliber.

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. 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 during certain periods, thereby reducing activity levels. Similarly, any drought or other condition resulting in a shortage or the unavailability of adequate supplies of water would impair our ability to conduct hydraulic fracturing operations. 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. 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 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.

Hydraulic fracturing has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development.

Hydraulic fracturing is the primary production method used in the Bakken Shale and Three Forks formations. Hydraulic fracturing is a process that creates a fracture extending from the well bore in a rock formation that enables oil or natural gas to move more easily through the rock pores to a production well. Fractures typically are created through the injection of water and chemicals into the rock formation. Several federal entities, including the EPA, have recently asserted potential regulatory authority over hydraulic fracturing, and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with the results of the study anticipated to be available for review in 2014. Moreover, the EPA also is studying the potential impact of wastewater derived from hydraulic fracturing activities and by 2014 plans to propose standards that such wastewater must meet before being transported to a treatment plant. In addition, Congress has considered, and may in the future consider, legislation that would amend the Safe Drinking Water Act to encompass hydraulic fracturing activities. The proposed legislation would have required hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, including disclosure of chemicals used in the fracturing process, and meet plugging and abandonment requirements. Some states already have adopted, and other states are considering adopting, requirements that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances. For example, North Dakota requires disclosure of information concerning the chemicals used in hydraulic fracturing fluids and imposes certain well construction and testing requirements. In 2011, Montana enacted regulations requiring operators to disclose information about hydraulic fracturing fluids on a well-by-well basis. In addition, operators must generally obtain approval from the state before hydraulic fracturing occurs and submit a report after the work is performed. Montana also requires specific construction and testing requirements for wells that will be hydraulically fractured. In some

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areas, municipalities and other local governmental bodies have also purported to regulate, and in some cases prohibit, hydraulic fracturing activities. In addition, Nova Scotia currently has in place a moratorium on hydraulic fracturing.

Depending on the legislation or regulations that ultimately may be adopted, exploration and production activities that employ 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 that are not commercially viable without the use of hydraulic fracturing. This could have an adverse effect on our business, financial condition and results of operations. See Item 1. Business Overview — Environmental Laws and Regulations for further discussion of applicable environmental laws.

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

The U.S. President’s Fiscal Year 2014 Budget Proposal includes provisions that, if enacted into law, would eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include (i) the repeal of the percentage depletion allowance for oil and natural gas wells, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any similar changes in U.S. federal income tax laws could increase the cost of exploration and development of natural gas and oil resources. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

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 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.

The EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to human health and the environment, which allows EPA to begin regulating GHG emissions under existing provisions of the federal Clean Air Act. EPA has begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress has considered and may in the future consider “cap and trade” legislation that would establish an economy-wide cap on GHG emissions in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for our production. Canada, where we also hold oil and natural 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 we produce. See Item 1. Business Overview — Environmental Laws and Regulations — Air Emissions and Climate Change for further discussion.

Many 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 services or infrastructure provided to us by other parties. 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.

Our business could be negatively impacted by cybersecurity risks and other disruptions.

As an oil and natural gas producer, we face various security threats, including possible attempts by third parties to gain unauthorized access to sensitive information, or to render data or systems unusable, through unauthorized computer access; threats to the safety of our employees; and threats to the security of our infrastructure or third party facilities and infrastructure, such as processing plants and pipelines. There can be no assurance that the procedures

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and controls we use to monitor these threats and mitigate our exposure to them will be sufficient in preventing them from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition, results of operations, and cash flows.

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 to 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 risk. We might incur substantial losses from, and be subject to substantial liability claims for, uninsured or underinsured risks related to our operations.

Our operations are subject to all the risks normally incident to the operation and development of oil and natural gas properties, the drilling of oil and natural gas wells, hydraulic fracturing and the provision of related services including:

· environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other substances 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;

· well blowouts;

· pipeline failures and ruptures;

· casing collapse;

· mechanical and operational problems that affect production; and

· natural disasters.

We do not maintain insurance against all such risks. We generally 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.

Constraints in the supply of, prices for, and availability of transportation of raw materials can have a material adverse effect on RockPile’s business.

High levels of demand for, or a shortage of, raw materials used in hydraulic fracturing operations, such as proppants, can trigger constraints in RockPile’s supply chain of those raw materials, particularly where it has a relationship with a single supplier for a particular resource. Many of the raw materials essential to its business require the use of rail, storage, and trucking services to transport the materials to its jobsites. These services, particularly during times of high demand, may cause delays in the arrival of or otherwise constrain its supply of raw materials. These constraints could have a material adverse effect on RockPile’s business. In addition, price increases imposed by its vendors for such raw materials and the inability to pass these increases through to its customers could have a material adverse effect on its business. Our other operations may be similarly adversely affected by shortages of these raw materials.

Growing Caliber’s business by constructing new pipelines and other infrastructure subjects it to construction risks and will require it to obtain rights of way at a reasonable cost. Such projects may not be profitable if costs are higher, or demand is less, than expected.

One of the ways we intend to grow Caliber’s business is through the construction of pipelines, treatment/processing facilities and other midstream infrastructure. The construction of this infrastructure will require significant amounts of capital, which may exceed our expectations, and will involve numerous regulatory, environmental, political and legal uncertainties, and stringent, lengthy and occasionally unreasonable or impractical federal, state and local permitting, consent, or authorization requirements. As a result, new infrastructure may not be constructed as scheduled or as originally designed, which may require redesign and additional equipment, relocations of facilities or rerouting of pipelines, which in turn could subject Caliber to additional capital costs,

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additional expenses or penalties and may adversely affect Caliber’s operations. In addition, the coordination and monitoring of these projects requires skilled and experienced labor. Agreements with Caliber’s producer customers may contain substantial financial penalties and/or give the producers the right to repurchase certain assets and terminate their contracts if construction deadlines are not achieved. Moreover, Caliber’s revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if Caliber builds a new pipeline, the construction may occur over an extended period of time, and Caliber may not receive any material increases in revenues until after completion of the project, if at all.

In addition, the construction of pipelines and other infrastructure may require Caliber to obtain rights-of-way or other property rights prior to construction. Caliber may be unable to obtain such rights-of-way or other property rights at a reasonable cost. If the cost of obtaining new or renewing rights-of-way or other property rights increases, it would adversely affect Caliber’s operations.

Furthermore, Caliber may have limited or no commitments from customers relating to infrastructure projects prior to their construction. If Caliber constructs facilities to capture anticipated future growth in production or satisfy anticipated market demand that does not materialize, the facilities may not operate as planned or may not be used at all. Caliber may rely on estimates of proved reserves in deciding to construct new pipelines and facilities, and these estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new infrastructure projects may be unprofitable.

The holder of our Convertible Note has significant influence on our major corporate decisions, including control over some matters that require stockholder approval, and could take actions that could be adverse to stockholders.

In connection with the issuance and sale in July 2012 of our Convertible Note with an initial principal amount of $120.0 million, we entered into an Investment Agreement with NGP Triangle Holdings, LLC (“NGP”) and its parent company. Pursuant to the Investment Agreement, NGP is entitled to designate one director to our board of directors until the occurrence of a “Termination Event” (as defined in the Investment Agreement). The Investment Agreement further provides that, for so long as at least 50% of the original principal amount is outstanding and held by NGP, we will not take certain actions without the prior written consent of NGP. In addition, pursuant to the Convertible Note, for so long as at least 50% of the original principal amount is outstanding and held by NGP, we have agreed to (i) obtain the prior written consent of NGP before submitting certain resolutions or matters to a vote of the stockholders, or (ii) require the approval of stockholders as would be required to approve such resolution or matter if the then-outstanding Convertible Note held by NGP had been converted into shares of common stock immediately prior to the record date for such meeting of stockholders and NGP had voted all of such shares of common stock against such resolution or matter. The Convertible Note is convertible into shares of common stock at an initial conversion price of $8.00 per share, which, based on the initial principal amount, would allow the Convertible Note to be converted into 15,000,000 shares of common stock plus any shares issuable upon the conversion of accrued interest.

In March 2013, the Company sold to two affiliates of NGP 9,300,000 shares of common stock of the Company in a private placement. In connection with the private placement, we entered into an amendment to the Investment Agreement to modify the definition of “Termination Event,” thereby strengthening NGP’s board seat designation right. If NGP were to fully convert the Convertible Note on the date of this report, then NGP and its affiliates would hold approximately 34% of our outstanding shares of common stock.

As a result of the foregoing, NGP has significant influence over us, our management, our policies and, under both the Investment Agreement, as amended, and following conversion of the Convertible Note as a significant stockholder, certain matters requiring stockholder approval. The interests of NGP, including in its capacity as a creditor, may differ from the interests of the Company’s stockholders, and the ability of NGP to influence certain of our major corporate decisions may harm the market price of our common stock by delaying, deferring or preventing transactions that are in the best interest of all stockholders or discouraging third-party investors.

The cost of servicing our debt could adversely affect our business. In addition, our debt agreements have substantial restrictions and financial covenants that could adversely affect our business.

We have outstanding indebtedness under TUSA’s and RockPile’s credit facilities. A significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to

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fund other liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend upon our future operating performance and financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. We cannot assure you that our business will generate sufficient cash flows from operations, or that future borrowings will be available to us under our revolving credit facilities or otherwise, in an amount sufficient to fund our liquidity needs.

A substantial decrease in our operating cash flows or an increase in our expenses could make it difficult for us to meet our debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling assets, refinancing all or a portion of our existing debt, or obtaining additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service or other obligations then due.

The terms of certain of our debt agreements require us to comply with specified financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the agreements could result in a default under those agreements, which could cause all of our existing indebtedness to be immediately due and payable.

In addition to making it more difficult for us to satisfy our debt and other obligations, our indebtedness could limit our ability to respond to changes in the markets in which we operate and otherwise limit our activities. For example, our indebtedness, and the terms of agreements governing that indebtedness, could increase our vulnerability to economic downturns and impair our ability to withstand sustained declines in commodity prices and limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

Our revolving credit facilities limit the amounts we can borrow to a borrowing base amount determined by the lenders. Outstanding borrowings in excess of the borrowing base may be required to be repaid immediately, and we may not have the financial resources in the future to make those repayments. Our inability to borrow additional funds under our revolving credit facilities, or a requirement to repay borrowings in excess of a reduced borrowing base, could adversely affect our operations and our financial results.

Our limited partner interest in the Caliber joint venture may be diluted.

In October 2012, a wholly owned subsidiary of ours entered into a joint venture to provide crude oil, natural gas and water transportation services to us and third-parties primarily in the Williston Basin. In connection with its investment in the joint venture entity, our subsidiary received a 30% percent limited partner interest, as well as certain trigger units convertible into limited partner interests that would cause us to increase our ownership to a 50% limited partner interest. Further, our subsidiary received certain warrants that would allow us to purchase additional limited partner interests at specified prices. The trigger units vest upon the joint venture’s achievement of certain business performance metrics, namely connecting at least 162 TUSA wells to the joint venture’s gathering system or attaining aggregate revenues attributable to third party volumes equaling or exceeding 50% percent of projected distributable cash flows as set forth in the joint venture’s annual plan for six consecutive quarters or eight non-consecutive quarters.

There are numerous factors that may adversely affect the achievement of the aforementioned business performance metrics, including, but not limited to, depressed commodity prices, TUSA’s failure to establish commercial discoveries on properties that it intended to connect to the gathering system, competition from other oil and natural gas gathering, transportation and processing companies, regulatory barriers, increased drilling and production costs, and other factors causing TUSA and third-party providers to shut-in production or seek alternative sources for their transportation needs. If the business performance metrics are never achieved, our trigger units will not vest, and we will be unable to increase our limited partner interest above 30% absent a direct capital outlay.

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Further, if the joint venture partner makes an additional capital contribution and we choose not to invest additional capital in the joint venture, we would be diluted below our current 30% limited partner interest.

Our derivative activities could result in financial losses or reduced income, or could limit our potential gains from increases in prices.

We use derivatives for a portion of our crude oil production to reduce exposure to adverse fluctuations in prices of crude oil and to achieve a more predictable cash flow. These arrangements expose us to the risk of financial loss in some circumstances, including when sales are different than expected, the counterparty to the derivative contract defaults on its contractual obligations, or when there is a change in the expected differential between the underlying price in the derivative agreement and actual prices that we receive. These risks may be exacerbated by the fact that our derivative contracts are currently with one counterparty.

In addition, derivative arrangements may limit the benefit from increases in the price for crude oil, and they may also require the use of our resources to meet cash margin requirements. Since we do not designate our derivatives as hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of derivatives are recorded in our statements of operations, and our net income is subject to greater volatility than it would be if our derivative instruments qualified for hedge accounting. For instance, if the price of crude oil rises significantly, it could result in significant non-cash charges each quarter, which could have a material negative effect on our net income.

Additionally, the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, among other things, imposes restrictions on the use and trading of certain derivatives, including energy derivatives. The nature and scope of those restrictions is in the process of being determined in significant part through implementing regulations adopted by the SEC, the Commodities Futures Trading Commission and other regulators. If, as a result of the Dodd-Frank Act or its implementing regulations, capital or margin requirements or other limitations relating to our commodity derivative activities are imposed, this could have an adverse effect on our ability to implement our hedging strategy. In particular, a requirement to post cash collateral in connection with our derivative positions would likely make it impracticable to implement our current hedging strategy. In addition, requirements and limitations imposed on our derivative counterparties could increase the costs of pursuing our hedging strategy.

We have restated our financial statements in the past and may be required to do so in the future.

We have restated or corrected certain financial information in the past, including by issuing restated financial information for the quarters ended April 30, 2007, July 31, 2007 and October 31, 2007, for the year ended January 31, 2012, and, most recently, for the quarter ended October 31, 2012. The preparation of financial statements in accordance with GAAP involves making estimates, judgments, interpretations and assumptions that affect reported amounts of assets, liabilities, revenues, expenses and income. These estimates, judgments, interpretations and assumptions are often inherently imprecise or uncertain, and any necessary revisions to prior estimates, judgments, interpretations or assumptions could lead to further restatements. Our vertical integration strategy creates certain accounting issues relating to the relationship of our various businesses that are relatively complex, increasing the risk that we may have to restate or correct financial disclosures in the future. Any such restatement or correction may be highly time consuming, may require substantial attention from management and significant accounting costs, may result in adverse regulatory actions by the SEC or NYSE MKT and/or stockholder litigation, may cause us to fail to meet our reporting obligations and/or may cause investors to lose confidence in our reported financial information, leading to a decline in our stock price.

We have identified material weaknesses in our internal controls that, if not properly corrected, could result in material misstatements in our financial statements.

As disclosed in Item 9A, we have identified a material weakness in our system of internal control over financial reporting as of January 31, 2013 relating to the accounting for pressure pumping income. A material weakness is a deficiency, or combination of deficiencies, in internal controls over financial reporting that results in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. As a result of this material weakness, our management concluded that our internal control over financial reporting and our disclosure controls and procedures were not effective as of January 31, 2013. We are in the process of implementing system and procedural changes to prevent these issues from recurring in fiscal year 2014. If we are not able to remedy the control deficiencies in a timely manner, or if other deficiencies arise in the future, we may be unable to provide holders of our securities with required financial

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information in a timely and reliable manner and we could be required to restate or correct our financial statements in the future.

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 securities that have, in many cases, been unrelated to the operating performance, underlying asset values or prospects of the companies issuing those securities. 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.

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 acquisitions of additional leasehold interests. Any issuances of large

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quantities of our common stock could reduce the price of our common stock. In addition, 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 Section 203 of the Delaware General Business Corporations Act, which generally prohibits certain business combination transactions between a corporation and an “interested stockholder” within three years of the time such stockholder became an interested stockholder, absent, in most cases, board or stockholder approval. An “interested stockholder” is any person who, together with affiliates and associates, is the owner of 15% or more of the outstanding voting stock of the corporation, and the term “business combination” encompasses 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 a benefit on other than a pro rata basis with other stockholders. Although a corporation can opt out of Section 203 in its certificate of incorporation, we have not done so. Section 203 may have an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including by discouraging takeover attempts that might result in a premium being paid over the then-current market price of our common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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 are not material 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, 2013, we held interests in approximately 86,000 net acres of operated and non-operated leasehold positions in the Williston Basin of North Dakota and Montana. Approximately 36,000 net acres are located in our core area of North Dakota and eastern Montana, of which approximately 20,000 net acres are considered operated acreage. Approximately 50,000 net acres are located in our Station Prospect area of Montana, of which approximately 35,000 net acres are considered operated acreage. The majority of our Williston Basin leaseholds are held primarily under fee leases. These leases typically carry a primary term of 3 to 5 years with landowner royalties of approximately 16% to 20%. In most cases, we obtain “paid-up” fee leases, which do not require annual delay rentals.

As of March 31, 2013, we have completed a total of 19 (11.1 net) operated wells. During fiscal year 2014, we anticipate drilling and completing an additional 29 (13.2 net) wells in North Dakota or eastern Montana, including 27 wells for completion in the Bakken Shale formation and two for completion in the Three Forks formation. Of the 29 planned wells for fiscal year 2014, we have completed three gross wells with an additional two gross wells in progress as of March 31, 2013.

In our core area of North Dakota and eastern Montana, Triangle is directing resources toward its operated program to develop its approximately 36,000 net acres, primarily in McKenzie and Williams County, North Dakota. In Sheridan and Roosevelt Counties, Montana, our Station Prospect is a largely contiguous position within the thermally mature area of the Williston Basin. Our approximate 50,000 net acre position in the Station Prospect is

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predominantly operated acreage with an average remaining lease term of approximately two and one half years and provides us with a development area that we believe is scalable for the future.

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, 2013, we have participated, or are participating, in the drilling of 191 gross (8.41 net) non-operated wells, consisting of (i) 126 (5.08 net) non-operated producing wells, (ii) 57 non-operated gross (2.82 net) wells in various stages of drilling and completion and (iii) 8 non-operated gross (0.51 net) wells permitted to drill.

Oil and Natural Gas Reserves

Net Reserves of Crude Oil and Natural Gas at Fiscal Year-End 2013 and 2012

Approximately 99.5% of the Company’s proved reserves at January 31, 2013 are associated with oil and natural gas properties in North Dakota. The remainder is associated with an interest in a new Montana well near the North Dakota border. Our proved reserves are located in the Bakken Shale formation or Three Forks formation for property interests of our wholly-owned subsidiary Triangle USA Petroleum Corporation. Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”), an independent petroleum engineering firm, audited our estimates of proved oil and natural gas reserves as of January 31, 2013 and our determination of 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, 2013. 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 PV-10 Value at January 31, 2012. Those estimates and their respective PV-10 Values are summarized in the following table and are further discussed in the Cawley Gillespie and Ryder Scott reports filed as exhibits to this annual report.

	As of January 31,
	2013		2012
Proved developed:
Oil (MBbls)	4,985		538
Natural gas (Mmcf)	5,906		202
Proved undeveloped:
Oil (MBbls)	7,555		827
Natural gas (Mmcf)	6,679		472

Total proved oil reserves (MBbls)	12,540		1,365
Total proved natural gas reserves (Mmcf)	12,585		674
Total proved oil and natural gas reserves (MBoe)	14,637		1,477

PV-10 Values (in thousands) of oil and natural gas proved reserves:
PV-10 Value of proved developed reserves	$	165,484	$	19,393
PV-10 Value of proved undeveloped reserves	$	59,377	$	10,035
PV-10 Value of total proved reserves	$	224,861	$	29,428

The increase in our total proved reserves in fiscal year 2013 in the amount of 13,160 Mboe resulted primarily from our drilling and completion activity on the Bakken and Three Forks formations properties. As a result of our drilling program that evaluated both the Middle Bakken and Three Forks formations, we increased the number of proved undeveloped (“PUD”) locations from 17 (2.61 net) at fiscal year-end 2012 to 59 (19.76 net) at fiscal year-end 2013. These PUD locations offset our existing producing wells or are located in drill spacing units that offset producing wells.

In estimating the proved reserves, Triangle used the SEC definition of proved reserves. Projected future cash flows were based on economic and operating conditions as of the respective January 31st 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 31st estimation date.

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Volumes of reserves that will be actually recovered and cash flows that will be 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, of engineering and geological interpretation and judgment, and of 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.

The following table reconciles (a) the standardized measure of discounted future net cash flows (GAAP) related to total proved oil and natural gas reserves to (b) PV-10 Value (Non-GAAP) of total proved oil and natural gas reserves. The difference is due to the PV-10 Value excluding the impact of income taxes.

	As of January 31,
(in thousands)	2013			2012
Standardized Measure, for total proved reserves	$	211,352		$	29,428
Add back: Discounting at 10% per annum	297,653			26,246
Future cash flow, after income taxes	509,005			55,674
Add: future undiscounted income taxes	87,313			—
Undiscounted future net cash flows before taxes	596,318			55,674
Less: Discounting at 10% per annum	(371,457		)	(26,246		)
PV-10 Value of total proved oil and natural gas reserves	$	224,861		$	29,428

The Standardized Measure is presented more fully and discussed further in Note 22 - Unaudited Supplemental Oil and Natural Gas Disclosures to the consolidated financial statements referenced in Part II, Item 8 of this report.

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 2013.

Proved Undeveloped Reserves

At January 31, 2013, we had proved undeveloped oil and natural gas reserves of 8,667.0 Mboe, which represents 59% of our total proved reserves as compared to 905.2 Mboe or 61% of our total proved reserves at January 31, 2012. Changes in our proved undeveloped reserves are summarized in the following table:

	Mboe		Gross wells		Net wells
At January 31, 2012	904.5		17		2.6
Became developed reserves in fiscal year 2013	(362.9	)	(9	)	(1.2	)
Traded for net acres in other drill spacing units	(256.3	)	(5	)	(0.7	)
Negative revision	(35.6	)	(1	)	(0.1	)
Positive revisions	101.4		0		0.0
Acquisition of additional interests in PUD locations	171.7		0		0.3
Additional proved undeveloped locations	8,144.2		57		18.9
At January 31, 2013	8,667.0		59		19.8

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Additions to proved undeveloped reserves are for 57 drilling locations, whose status is summarized in the following table:

		Development
	PUD	Wells
	Locations	Gross	Net
Proved undeveloped locations:
For which Triangle operated wells are to be drilled and completed by June 30, 2017	34	34	16.83
For which non-operated wells were in-progress at January 31, 2013 and are expected to be completed in fiscal year 2014	17	17	1.22
That are non-operated wells with drilling permits	3	3	0.32
That are non-operated wells to be drilled by 01/31/2015	3	3	0.48
Total	57	57	18.85

Reserve Estimation Methods

The process of estimating proved reserves involves exercising professional judgment to select estimation method(s) within three categories: (1) performance-based methods, (2) volumetric-based methods; and (3) analogy. The selection of estimation method(s) considers (i) the geoscience and engineering data available at the time, (ii) the established or anticipated performance characteristics of the reservoir being evaluated and (iii) the development stage and production history of the well, property or field.

For proved reserves estimated at January 31, 2012 and 2013, Ryder Scott and Triangle’s Senior Reservoir Engineer, respectively, used the same general estimation methods:

· Proved producing reserves attributable to producing wells were estimated by performance methods or by analogy. Performance methods included decline curve analysis, which utilized extrapolation of historical production through the estimation date where such historical data were considered to be definitive. Where such historical data was insufficient for extrapolation, the analogy method was used.

· Proved undeveloped reserves were estimated by the analogy method.

The January 31, 2103 proved undeveloped reserves estimated by Triangle’s Senior Reservoir Reserve Engineer were audited by Cawley Gillespie. The Ryder Scott report (Exhibit 99.1) and the Cawley Gillespie report (Exhibit 99.2), which provide further explanation and discussion of reserve estimation methods, are incorporated herein by reference.

Internal Controls over Reserve Estimation

Cawley Gillespie’s year-end report was 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 reasonably ensure accuracy and completeness of the data prior to submission to Cawley Gillespie. Upon analysis and evaluation of data provided, Cawley Gillespie issues a preliminary report of our reserves which is reviewed by our Senior Reservoir Engineer and Principal Accounting Officer for completeness of the data presented and reasonableness of the results obtained. Once all questions have been addressed, Cawley Gillespie issues the final report, reflecting their conclusions on Triangle’s estimates.

As to technical qualifications for the reserves audit, Cawley Gillespie’s year-end reserves audit report (filed as Exhibit 99.2 to this annual report) states, “Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists. The firm has provided petroleum consulting services to the oil and gas industry for over 50 years. This audit was supervised by W. Todd Brooker, Senior Vice President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). Mr. Brooker received his Bachelor of Science degree in Petroleum Engineering from the University of Texas at Austin in 1989, and joined CG&A as a reservoir engineer in 1992.

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The following depicts our Station Prospect area of operations within the Williston Basin:

In Sheridan and Roosevelt Counties, Montana, our Station Prospect is a largely contiguous position within the thermally mature area of the Williston Basin. Our approximate 50,000 net acre position in the Station Prospect is predominantly operated acreage that provides Triangle with a development area that we believe is scalable for the future.

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, 2013.

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Project
Williston Basin, North Dakota	70,657	20,185	55,579	10,744	126,236	30,929
Williston Basin, Montana	—	—	85,022	55,071	85,022	55,071
Total Williston Basin	70,657	20,185	140,601	65,815	211,258	86,000
Maritimes Basin, Canada	—	—	474,625	412,924	474,625	412,924
Acreage Totals	70,657	20,185	615,226	478,739	685,883	498,924

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 will do so.

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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):

	Future		Net Acres Expiring
Fiscal	Extension		If No	With All
Year	Cost		Extensions	Extensions
2014	$	459,812	4,145	1,140
2015	$	1,884,050	21,254	13,352
2016	$	214,105	19,320	22,932
2017			18,011	24,108
2018			274	1,504
Thereafter			197	197
Total	$	2,557,967	63,201	63,233
Already extended			32	—
			63,233	63,233
Held by production			21,920	21,920
Total Undeveloped Net			85,153	85,153

The table shows for fiscal year 2014 that, with all currently allowed extensions, 1,140 net acres would expire if no drilling or other actions are taken to further extend the lease life. We anticipate that some drilling or other actions will occur whereby less than 500 acres will expire in fiscal year 2014. 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 2013, 2012 and 2011. The table’s number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated. Well completion refers to installation of permanent equipment for production of oil or natural gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned after little or no production.

	Fiscal Year 2013		Fiscal Year 2012		Fiscal Year 2011
	Gross	Net	Gross	Net	Gross	Net
U.S.A. (all in North Dakota)
Productive exploratory wells drilled:
Operated by Triangle	6	3.17	—	—	—	—
Operated by others	41	0.55	50	2.10	4	0.94
Total	47	3.72	50	2.10	4	0.94

Dry exploratory wells drilled	1	0.01	—	—	—	—

Productive development wells drilled:
Operated by Triangle	10	6.85	—	—	—	—
Operated by others	14	0.73	11	0.56	—	—
Total	24	7.58	11	0.56	0	0
Dry development wells drilled	—	—	—	—	—	—

Canada
Exploratory and development wells	—	—	—	—	—	—

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As of January 31, 2013, we had 144 gross productive wells and 16 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 targeting natural gas reserves.

The total wells drilled from the table above does not equal the 144 gross productive wells in the previous paragraph because the productive well count includes wells which were acquired after being completed and wells that were completed prior to fiscal year 2011.

Costs Incurred and Capitalized Costs

The table below presents costs incurred in oil and natural gas acquisition, exploration and development activities in fiscal years 2013, 2012 and 2011:

	2013		2012		2011
Property acquisition	$	21,192,897	$	87,225,544	$	13,654,462
Exploration	55,953,303		40,727,797		4,575,424
Development	91,666,473		4,705,568		—

Total	$	168,812,673	$	132,658,909	$	18,229,886

All capitalized costs excluded from amortization as of January 31, 2013 and 2012 were located in the United States. We anticipate the excluded costs at January 31, 2013 will be included in the amortization computation over the next five years. We are unable to predict the future impact on amortization rates.

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 MKT 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:

	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

	Fiscal Year 2013
	High		Low
February 1, 2012 to April 30, 2012	$	7.99	$	5.54
May 1, 2012 to July 31, 2012	$	6.38	$	4.72
August 1, 2012 to October 31, 2012	$	7.76	$	5.65
November 1, 2012 to January 31, 2013	$	6.62	$	5.12

Holders

Our 56,268,825 shares of common stock outstanding at April 15, 2013 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 have not paid any cash dividends in the past and 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.

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected consolidated financial data as of and for the years ended January 31, 2009 through January 31, 2013. The data as of and for the fiscal years ended January 31 for the respective years was derived from our historical consolidated financial statements and the accompanying notes included elsewhere in this annual report on Form 10-K and in our prior annual reports on Form 10-K, as applicable.

The selected financial data set forth below should be read in conjunction with the consolidated financial statements and accompanying notes thereto provided in Item 8 of this Report.

	For the Fiscal Years Ended January 31,
(in thousands, except per share amounts)	2013			2012			2011			2010			2009
Operating results:
Oil and natural gas sales	$	39,614		$	8,136		$	564		$	131		$	387
Pressure pumping services	20,748			—			—			—			—
Other	340			—			—			—			—
Total Revenue	$	60,702		$	8,136		$	564		$	131		$	387

Total operating expenses	$	68,871		$	33,111		$	20,900		$	2,278		$	15,276

Net loss attributable to common stockholders	$	(13,760	)	$	(24,278	)	$	(20,277	)	$	(2,140	)	$	(13,770	)

Loss per share to common stockholders:
Basic and diluted	$	(0.31	)	$	(0.60	)	$	(1.63	)	$	(0.03	)	$	(0.23	)

Total assets	$	428,321		$	229,845		$	82,031		$	24,358		$	26,770
Long-term obligations	$	148,788		$	83		$	1,404		$	1,181		$	728

Cash flow data:
Net cash provided by (used in) operating activities	$	2,763		$	(12,766	)	$	(3,541	)	$	(2,100	)	$	(3,898	)
Net cash used in investing activities	$	(179,712	)	$	(111,046	)	$	(16,100	)	$	(2,192	)	$	(1,190	)
Net cash provided by financing activities	$	141,250		$	134,854		$	72,534		$	—		$	12,003

Proved reserves:
Oil (MBbls)	12,540			1,365			1,236			—			1,178
Natural gas (MMcf)	12,584			674			—			—			98
Total equivalent (Boe)	14,637			1,477			1,236			—			1,194

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

The following discussion is intended to assist in understanding our results of operations and our current financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this annual report contain additional information that should be referred to when reviewing this material.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties that could cause actual results to differ from those expressed. We encourage you to revisit the Forward-Looking Statements section in Part I of this annual report.

Overview

We are an independent energy company focused on the exploration, acquisition, and production of unconventional shale oil and natural gas resources in the United States. Our oil and natural gas reserves and operations are primarily concentrated in the Bakken Shale and Three Forks formations of the Williston Basin in North Dakota and Montana. As of January 31, 2013, we held leasehold interests in approximately 86,000 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.

In our 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 50,000 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 operated development program, we have pursued select vertical integration opportunities in an effort to realize cost savings and strategic advantages. The Williston Basin is a resource constrained region in terms of oilfield services, infrastructure and human capital, resulting in challenging operating conditions for relatively smaller operators, such as Triangle. Pressuring pumping services and fluid logistics are critical to achieving operational efficiencies in the basin and represent material cost centers for exploration and production companies. As a result, we have targeted these verticals for integration via RockPile and Caliber. Having control over these areas of the value chain permits us to direct the availability and timing of well completion services and to transport oilfield fluids through pipeline.

RockPile, a wholly-owned subsidiary initially capitalized in September and October 2011, is a provider of hydraulic pressure pumping and complementary well completion services to oil and natural gas exploration and production companies in the Williston Basin of North Dakota and Montana. The Williston Basin is widely regarded as one of the most demanding basins in North America due to the harsh environment, lack of established infrastructure, and limited availability of qualified personnel in the region. RockPile’s management team has extensive experience providing oilfield services in the Williston Basin.

Pressure pumping involves the use of a technologically sophisticated set of mobile equipment mounted on tractor trailer chassis. RockPile purchased its first set of equipment, collectively known as a “spread”, in the first half of 2012. RockPile’s first spread commenced 12-hour operations in July 2012 and 24-hour operations in September 2012. From commencement of operations in July 2012 through January 31, 2013, RockPile completed 363 stages on 12 wells for Triangle and 132 stages on 5 wells for third-parties for a total of 495 stages on 17 wells. RockPile ordered a second spread during the first quarter of fiscal year 2014, which is currently on schedule to be placed into production in the second quarter of fiscal year 2014.

Caliber is a joint venture with First Reserve Energy Infrastructure Fund (“FREIF”) created in October 2012, which was capitalized through initial funding commitments of $100 million in equity capital contributions ($70 million from FREIF, $30 million from Triangle). Caliber is managed and governed by its general partner, Caliber Midstream GP, LLC, of which FREIF and Triangle each own a 50% non-economic interest and share governance equally. Caliber is an energy infrastructure company that provides crude oil and natural gas gathering, transportation, treating and processing; produced water transportation and disposal in Caliber-owned and/or operated injection wells; and freshwater sourcing and transportation by pipeline linked to various points of supply to

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Oil and natural gas sales and production costs for each year are summarized in the table that follows. The fiscal year 2012 information shows oil sales volumes that correspond to the $8,008,912 in oil revenues for fiscal year 2012.

	2013			2012
U.S. oil and natural gas operations
Oil sold (barrels)	451,784			92,694
Average oil price per barrel	$	85.29		$	86.40
Oil revenue	$	38,532,886		$	8,008,912
Natural gas sold (mcf)	188,044			11,758
Average natural gas price per mcf	$	4.78		$	9.06
Natural gas revenue	$	899,290		$	106,557
Natural gas liquids sold (gallons)	212,266			9,076
Average natural gas liquids price per gallon	$	0.86		$	2.26
Natural gas liquids revenue	$	182,035		$	20,503
Total oil, natural gas and natural gas liquids revenues	$	39,614,211		$	8,135,972
Less production taxes	(4,492,836		)	(896,062		)
Less lease operating expense (excluding production taxes)	(3,469,413		)	(901,240		)
Less gathering, transportation and processing expense	(150,530		)	(21,510		)
Less impairment of oil and natural gas properties	—			(6,000,000		)
Less oil and natural gas amortization expense	(13,548,000		)	(3,022,000		)
Less accretion of asset retirement obligations	(21,119		)	(6,950		)
Income (loss) from U.S. oil and natural gas production	$	17,932,313		$	(2,711,790	)
Gross profit from pressure pumping services	3,016,573			—
Other revenues	340,081			—
Income (loss) from U.S. operations	$	21,288,967		$	(2,711,790	)

Canadian oil and natural gas operations
Lease operating expense	(96,947		)	(640,650		)
Less impairment of oil and natural gas properties	—			(4,416,202		)
Accretion of asset retirement obligations	(162,382		)	(159,975		)
Loss from Canadian oil and natural gas operations	(259,329		)	(5,216,827		)
Income (loss) from operations	21,029,638			(7,928,617		)
U.S. and Canadian other income (expense)
Loss on derivative activities	(3,570,151		)	—
Other income (expense)	74,396			551,824
Interest expense	(2,818,118		)	—
Foreign exchange loss	(656		)	(21,938		)
Less depreciation of furniture and equipment	(407,746		)	(91,872		)
Less general and administrative expenses	(28,791,092		)	(16,932,340		)
Net loss	$	(14,483,729	)	$	(24,422,943	)
Total U.S. barrels of oil equivalent (“boe”) sold	488,179			94,870
U.S. oil and natural gas revenue per boe sold	$	81.15		$	85.76
U.S. production tax per boe sold	$	9.20		$	9.45
U.S. other lease operating expense per boe sold	$	7.11		$	9.50
U.S. gathering, transportation and processing expense per boe sold	$	0.31		$	0.23
U.S. amortization expense per boe sold	$	27.75		$	31.85

Oil and Natural Gas Sales Revenue

Production revenues increased to $39.6 million for the fiscal year ended January 31, 2013 from $8.1 million for the fiscal year ended January 31, 2012 due to a 415% increase in production volumes, offset by a 5% reduction in oil and natural gas prices on a per Boe basis. The increase in production volumes added approximately $31.9

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million in revenues, and the decrease in price per Boe reduced revenues by approximately $0.4 million.

Total production volumes increased to 488.2 Mboe (1,334 Boepd) for the fiscal year ended January 31, 2013 from 94.9 Mboe (260 Boepd) for the fiscal year ended January 31, 2012, primarily due to the addition of approximately 240.2 Mboe from our operated drilling program as well as a 153.1 Mboe (161% ) increase in production from our non-operated portfolio. Additional information concerning production is in the following table:

	Fiscal Year Ended January 31, 2013				Fiscal Year Ended January 31, 2012
	Oil	Natural Gas	Liquids	Total	Oil	Natural Gas	Liquids	Total
	(MBbls)	(MMcf)	(Mgal)	(Mboe)	(MBbls)	(MMcf)	(Mgal)	(Mboe)
Operated	240	—	—	240	—	—	—	—
Non-Operated	212	188	212	248	93	12	9	95
Total	452	188	212	488	93	12	9	95

Pressure Pumping Services

RockPile commenced operations in July 2012. We formed RockPile with strategic objectives to have both greater control over our largest cost center as well as to provide locally-sourced, high-quality completion services to Triangle and other operators in the Williston Basin. RockPile’s focus from formation through January 31, 2013 has mostly been on procuring new pressure pumping equipment, building physical and supply chain infrastructure in North Dakota, recruiting and training employees, and establishing third-party customers in the Williston Basin. Results of operations are affected by a number of variables including drilling and stimulation activity in the Williston Basin, pricing environment, service performance, equipment utilization, and the ability to secure and retain third-party customers. RockPile’s profitability is primarily driven by the ability to obtain third-party work, equipment utilization, and the pricing environment for our services.

For the year ended January 31, 2013, RockPile performed hydraulic fracturing services for Triangle and three distinct third-party customers. This work resulted in 17 total well completions: 12 for Triangle and five for third-parties. All Triangle wells were completed using plug-and-perf applications. Four third-party wells were completed using a sliding sleeve application and one well was completed using a plug-and-perf application. RockPile revenue is comprised of service revenue, which is what we charge for equipment and labor, and materials revenue, which is what we charge for chemicals and proppant. Pressure pumping direct costs include the cost of chemicals and proppant, labor (wages and benefits), trucking charges, material transloading fees, railroad related costs, insurance, repairs and maintenance charges and safety costs. Direct costs as a percentage of revenue will vary based upon equipment utilization.

The $3,016,573 of gross profit from pressure pumping services in fiscal year ended 2013 is after (i) elimination of $10 million in intercompany gross profit and (ii) full cost accounting non-recognition of $1.8 million of income relating to pressure pumping services for third parties through October 31, 2012. For the fourth quarter of fiscal year 2013, there was no additional non-recognition of service income under full cost accounting because the eliminated intercompany gross profit on pressure pumping for each TUSA-operated well exceeded that well’s total service income, due to TUSA’s high working interests (averaging 84.2%) in operated wells completed in that quarter. See Note 4 — Segment Reporting in the accompanying Consolidated Financial Statements and see Full Cost Accounting’s Non-recognition of Service Income with Third Parties in Certain Circumstances that begins on page 60.

Hedging Activities

In fiscal year 2013, the Company entered into commodity derivative instruments, primarily utilizing single-day puts and costless collars to reduce the effect of price changes on a portion of our future oil production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the gain (loss) on derivative activities line on the consolidated statement of operations. We value our derivative instruments by obtaining independent market quotes, as well as using industry-standard models that consider various assumptions, including quoted forward prices for commodities, risk free interest rates, and estimated volatility factors, as well as other relevant economic measures.

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The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or us, as appropriate. We utilize our valuations to assess the reasonableness of counterparties’ valuations. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. The change in fair value of our derivative instruments resulted in a $3.6 million unrealized loss on derivative activities for fiscal year 2013. For additional discussion, please refer to Note 13 - Commodity Derivative Instruments under Item 8 of this annual report.

Production Taxes

Total production taxes increased to $4.5 million for the fiscal year ended January 31, 2013 from $0.9 for the fiscal year ended January 31, 2012. Production taxes are primarily based on the wellhead values of production and the increase in production taxes is directly related to a 387% increase in production revenues. Production taxes as a percentage of oil and natural gas sales were 11.3% for the fiscal year ended January 31, 2013 and 11.0% for the fiscal year ended January 31, 2012. These rates are consistent with the published production tax rates in North Dakota, the primary source of our production.

Lease Operating Expense

Lease operating expense for U.S. operations (“LOE”) decreased to $7.11 per Boe for the fiscal year ended January 31, 2013 from $9.50 per Boe for the fiscal year ended January 31, 2012. The decrease is primarily the result of lower LOE on non-operated wells which decreased from $9.50 per Boe to $5.17 per Boe. For most of our non-operated wells the largest LOE component is water disposal. An increase in availability of trucking and third-party disposal facilities in the Williston Basin has reduced this cost on a per unit basis. Offsetting the reduction in non-operated LOE costs were operated LOE costs of $9.15 per Boe. Included in the operated LOE rate are non-recurring costs for equipment rentals as well as two workovers.

Gathering, Transportation and Processing

Gathering, transportation and processing (“GTP”) expenses increased to $0.31 per Boe for the fiscal year ended January 31, 2013 from $0.23 per Boe for the fiscal year ended January 31, 2012. Currently, all GTP costs are associated with non-operated wells and are primarily for the gathering and transportation of oil and natural gas. GTP costs were $0.61 and $0.23 per non-operated Boe for the fiscal years ended 2013 and 2012, respectively. This increase is primarily the result of an increase in natural gas being gathered and transported instead of being flared. Going forward we expect GTP costs to increase as natural gas gathering, transportation and processing infrastructure becomes available for operated wells during the second half of fiscal year 2014.

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

Oil and natural gas amortization expense increased to $13.5 million for the fiscal year ended January 31, 2013 from $3.0 million for the fiscal year ended January 31, 2012. The increase is primarily related to a 415% increase in production for fiscal year 2013 compared to fiscal year 2012. The increase in production accounted for an additional $12.5 million in DD&A expense, which was offset by a reduction of $2.0 million due to a decreased DD&A rate. The decrease in the amortization rate is due to proved reserves increasing at a higher rate than the amortization base increased. During fiscal year 2013 proved reserves increased approximately 891% while the amortization base increased approximately 632%.

Depreciation expense increased to $1.6 million for the fiscal year ended January 31, 2013 from $.09 million for the fiscal year ended January 31, 2012. This increase is primarily attributable to the depreciation of RockPile operating equipment as the equipment was placed into service in July 2012.

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General and Administrative Expenses

The following table summarizes increases in general and administrative expenses for the fiscal years 2013 compared with 2012. The increases are primarily due to increases in the number of employees as we continued to expand our acquisition, exploration, development and production activities in North Dakota and Montana during fiscal year 2013.

	2013		2012		Increase (Decrease)
General and administrative, excluding RockPile:
Stock-based compensation	$	5,848,648	$	7,567,312	$	(1,718,664	)
Salaries, benefits and consulting fees	7,067,799		4,908,670		2,159,129
Office rent and other office costs	1,563,965		1,448,981		114,984
Professional fees	2,084,448		1,517,735		566,713
Public company costs	458,939		607,500		(148,561		)
	17,023,799		16,050,198		973,601
RockPile general and administrative expense	11,767,293		882,142		10,885,151
Total general and administrative expense	$	28,791,092	$	16,932,340	$	11,858,752

RockPile’s general and administrative costs of $11.8 million increased from $0.8 million in fiscal year 2012. This increase is primarily attributable to increased compensation and benefit costs for personnel in RockPile’s headquarters and field offices as RockPile built its team and commenced operations in July 2012.

Interest Expense

The $2.8 million in interest expense consists of approximately $0.2 million in interest and amortized fees related to the TUSA credit facility and approximately $3.0 million in accrued interest and amortized fees related to our 5% convertible note with NGP. The total $3.2 million in interest expense is reduced by approximately $0.4 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. See Note 12 - Long-Term Debt for additional information regarding our credit facility and convertible note.

Income Taxes

Our fiscal year 2013 provision for deferred income taxes is zero due to recognition of 100% valuation allowances against our net deferred tax assets of $35.0 million and $29.2 million at January 31, 2013 and 2012, 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.

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 $24.3 million ($0.60 per common share, basic and diluted) as compared to a net loss attributable to common stockholders of $20.3 million ($1.63 per common share, basic and diluted) for the fiscal year ended January 31, 2011.

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	2012			2011
U.S. oil and natural gas operations
Oil sold (barrels)	92,694			6,174
Average oil price per barrel	$	86.40		$	74.20
Oil revenue	$	8,008,912		$	458,111
Natural gas sold (mcf)	11,758			23,689
Average natural gas price per mcf	$	9.06		$	4.46
Natural gas revenue	$	106,557		$	105,559
Natural gas liquids sold (gallons)	9,076			—
Average natural gas liquids price per gallon	$	2.26		$	—
Natural gas liquids revenue	$	20,503		$	—
Total oil and natural gas revenues	$	8,135,972		$	563,670
Less production taxes	(896,062		)	(94,654		)
Less lease operating expense (excluding production taxes)	(901,240		)	(30,696		)
Less gathering, transportation and processing expense	(21,510		)	(14,535		)
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		)
Income (loss) from U.S. oil and natural gas production	(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		)
Loss from operations	(7,928,617		)	(13,865,224		)
U.S. and Canadian other income (expense)
Other income (expense)	551,824			59,373
Foreign exchange gain (loss)	(21,938		)	35,615
Less depreciation of furniture and equipment	(91,872		)	(39,296		)
Less general and administrative expenses	(16,932,340		)	(6,467,665		)
Net loss	$	(24,422,943	)	$	(20,277,197	)
Total U.S. barrels of oil equivalent (“boe”) sold	94,870			10,122
U.S. oil and natural gas revenue per boe sold	$	85.76		$	55.69
U.S. production tax per boe sold	$	9.45		$	9.35
U.S. other lease operating expense per boe sold	$	9.50		$	3.03
U.S. gathering, transportation and processing expense per boe sold	$	0.23		$	1.44
U.S. amortization expense per boe sold	$	31.85		$	9.48

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General and Administrative Expenses

The following table summarizes increases in general and administrative expenses for the fiscal year 2012 compared with 2011. The increases are primarily due to significant increases in the number of employees (10 employees on January 31, 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 (Decrease)
Stock-based compensation	$	7,567,312	$	1,066,311	$	6,501,001
Salaries, benefits and consulting fees	4,908,670		2,916,982		1,991,688
Office rent and other office costs	1,448,981		1,355,007		93,974
Professional fees	1,517,735		817,369		700,366
Public company costs	607,500		311,996		295,504
	16,050,198		6,467,665		9,582,533
RockPile general and administrative expense	882,142		—		882,142
Total general and administrative expense	$	16,932,340	$	6,467,665	$	10,464,675

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.

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 liquidity is highly dependent on the commodity price we receive for the oil and natural gas we produce. Commodity prices are market driven, and have been volatile, therefore, we cannot predict future commodity prices. Prices received for production heavily influence our revenue, cash flow, profitability, access to capital and future rate of growth.

Our primary cash requirements in our exploration and production segment are for exploration, development and acquisition of oil and natural gas properties. Based on current prices, we anticipate capital requirements for fiscal year 2014 to be approximately $245 million. These funds will be allocated primarily towards our operated drilling program.

Sources of Capital

Cash flow from operations. We expect our cash flow from operations to continue to increase commensurate with our anticipated increase in sales volumes and wells drilled. We have been able to significantly increase our volumes over the past year, which is directly related to our successful drilling and completion of operated wells. If we are able to continue to drill and complete our wells as anticipated and they produce at rates similar to those generated by our existing wells, subject to the changes in the market price of crude oil, we would expect our production rates and operating cash flows to continue to increase as we continue to develop our properties. We also expect cash flow from operations at RockPile and Caliber to increase as they expand their operations.

TUSA Credit Facility. As of January 31, 2013, the maximum credit available under the TUSA credit facility was $300.0 million with a borrowing base and aggregate commitments of $75.0 million. As of January 31, 2013, we had available capacity under the credit facility of $50 million. On April 11, 2013, TUSA amended its credit facility to increase the maximum credit available to $500.0 million with a current borrowing base of $110.0 million. The

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ability to maintain and increase this facility and borrow additional funds is dependent on a number of variables, including our proved reserves, and assumptions regarding the price at which oil and natural gas can be sold. Further, we expect that our borrowing base will increase with the addition of proved properties resulting from our ongoing drilling and completion activities. We are subject to restrictive covenants under the credit facility. For further details on our credit facility refer to Note 12 - Long-Term Debt under Item 8 in this annual report.

RockPile Credit Facility. On February 25, 2013, RockPile, entered into a Credit and Security Agreement (the “RockPile Credit Agreement”) by and between RockPile, as borrower, and Wells Fargo Bank, National Association, as lender (the “Lender”). The RockPile Credit Agreement provides for a $7,500,000 revolving loan facility, a $10,500,000 equipment term loan facility and a $2,000,000 capex term loan facility. Borrowings under the RockPile Credit Agreement are available to: (i) provide for the working capital and general corporate requirements of RockPile, (ii) purchase equipment, (iii) pay any fees and expenses in connection with the RockPile Credit Agreement, and (iv) support letters of credit. As of February 25, 2013, the full $10,500,000 of the equipment term loan was drawn and was outstanding, and there were no revolving borrowings, letters of credit, or capex term loans outstanding under the agreement. The borrowing base is supported by eligible accounts receivable and inventory and is re-determined periodically when a borrowing base certificate is filed with the Lender. The maturity date of the Credit Agreement is February 25, 2016, unless sooner terminated as provided in the Credit Agreement. We are subject to restrictive covenants under this credit facility. For further details on the RockPile Credit Agreement refer to Note 20 — Subsequent Events.

Common Equity Private Placement. In March 2013, the Company sold to two affiliates of NGP Triangle Holdings, LLC 9,300,000 shares of common stock of the Company in a private placement at $6.00 per share for aggregate consideration of $55.8 million.

Capital Requirements Outlook

In addition to the common equity private placement, we are dependent on our anticipated cash flows from operations and the expected borrowing availability under the TUSA credit facility and the RockPile Credit Agreement to fund our fiscal year 2014 capital expenditures budget and other contractual commitments (refer to Note 12-Long-Term Debt and Note 19-Commitments and Contingencies under Item 8 in this annual report for further details). While we expect such sources of capital to be sufficient for such purposes, there can be no assurance that we will achieve our anticipated future cash flows from operations, that credit will be available under our credit facilities when needed, or that we would be able to complete alternative transactions in the capital markets, if needed. Our ability to obtain financing on commercially reasonable terms is dependent on a number of factors, many of which we cannot control, including changes in our credit rating, interest rates, market perceptions of us and the oil and natural gas exploration and production industry and tax burdens due to new tax laws.

If our existing and potential sources of liquidity are not sufficient to satisfy such commitments and to undertake our currently planned expenditures, we believe that we have the flexibility in our commitments to alter our drilling program. If we were not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our planned expenditures or restructure our operations (by way of reducing our rig count which may result in termination fees depending on the timing and requirements of the underlying agreements), we would be unable to implement our original exploration and drilling program, and we may be unable to service our debt obligation or satisfy our contractual obligations.

Convertible Note

In July 2012, the Company sold a convertible promissory note with an initial principal amount of $120,000,000 (the “Convertible Note”) to NGP. The net proceeds from the Convertible Note were primarily used to finance fiscal year 2013 drilling and completion projects. The Convertible Note does not have a stated maturity. Following the fifth anniversary of the closing, if the price of the Company’s common stock exceeds $11.00 per share and certain trading volume requirements are met, the Company can elect to redeem all (but not less than all) of the Convertible Note at a price equal to the outstanding principal amount plus accrued and unpaid interest, payable, at the Company’s option, in cash or common stock. Following the eighth anniversary of the closing, the Company can elect to redeem all (but not less than all) of the Convertible Note at a price equal to the principal plus accrued and unpaid interest, payable in cash. Further, following either the tenth anniversary of the closing or a change of control of the Company, the holders of the Convertible Note will have the right to require the Company to redeem the Convertible Note at a price equal to the principal amount plus accrued and unpaid interest, with an additional make-whole payment for

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scheduled interest payments remaining if such right is exercised prior to the fifth anniversary of closing. For further details regarding the Convertible Note, refer to Note 12 - Long-Term Debt under Item 8 in this annual report.

Working Capital

As part of our cash management strategy, we frequently use available funds to reduce any balance on the TUSA credit facility. Accordingly, we generally maintain low cash and cash equivalent balances. Our working capital was $3.3 million at January 31, 2013, as compared to $58.8 million at January 31, 2012.

Registered Offerings

Historically, we have financed our operations, property acquisitions and other capital investments from the proceeds of offerings of our equity and debt securities. We currently have on file with the SEC two effective shelf registration statements to allow us to offer up to $400 million and approximately $157 million of securities in the future, respectively. Under the registration statements, we may offer from time to time debt securities, common stock, warrants and other securities or any combination of such securities in amounts, prices and on terms announced when and if the securities are offered. The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus supplement at the time of any such offering.

Derivative Instruments

We utilize various derivative instruments in connection with anticipated crude oil sales to minimize the impact of product price fluctuations and ensure cash flow for future capital needs. Currently, we utilize single day puts and costless collars. Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. If actual commodity prices are higher than the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than if we had no derivative instruments. Conversely, if actual commodity prices are lower than the fixed or floor prices in our derivative instruments, our cash flows will be higher than if we had no derivative instruments.

Net Cash Used by Operating Activities

Cash flows provided by operating activities was $2.8 million for the fiscal year ended January 31, 2013. Cash flows used in operating activities was $12.8 million for the fiscal year ended January 31, 2012. The increase in operating cash flows was primarily due to higher oil revenues driven by higher sales volumes, partially offset by increases in production expenses, production taxes, general and administrative expenses, and other expenses associated with the growth of our operations during the year.

Net Cash Used by Investing Activities

In fiscal year 2013, investing activities used $179.7 million in cash compared to $111.0 million in fiscal year 2012. The increase in cash flows used in investing activities in fiscal year 2013 was primarily due to our larger capital budget and drilling program which used $136.8 million and the capital costs incurred for the start-up of RockPile which used $29.2 million. The use of cash for capital expenditures was partially offset by proceeds of $3.3 million received from dispositions of non-strategic assets during the year. In addition to capital expenditures, we had a $12.0 million increase in cash used for the investment in Caliber and a $3.9 million increase in cash used for the purchase of derivative contracts.

Net Cash Provided by Financing Activities

Cash flows provided by financing activities for the fiscal year ended January 31, 2013 totaled $141.2 million. The cash in-flow was primarily a result of proceeds from the $120 million Convertible Note and proceeds from the TUSA credit facility (see Note 12 — Long-Term Debt).

Research and Development

As an exploration and production natural resource company, we do not normally engage in research and development (“R&D”). There were no R&D activities or expenditures made in the last three fiscal years.

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Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Contractual Obligations as of January 31, 2013

The following table lists information with respect to our known contractual obligations as of January 31, 2013:

(in thousands)	Payments due by period
Contractual Obligations	Total		Less than 1		1 - 3 years		3 - 5 years		More than 5
Office leases (a)	$	1,476	$	368	$	657	$	451	$	—
Drilling rigs (b)	5,642		5,642		—		—		—
Office equipment (c)	4		4		—		—		—
Credit facility (d)	25,000		—		—		25,000		—
Convertible note (e)	123,023		—		—		—		123,023
Pressure pumping (f)	6,241		2,418		2,585		383		855
Midstream services (g)	337,129		12,469		67,770		76,048		180,842
	$	498,515	$	20,901	$	71,012	$	101,882	$	304,720

(a) The Company leases office facilities in Denver, Colorado and Calgary, Alberta, Canada under operating lease agreements that expire in September 2013, July 2014 and September 2017.

(b) As of January 31, 2013, the Company was subject to commitments on two drilling rig contracts. The contracts expire in September 2013 and March 2013. In the event of early termination of the contracts, the Company would be obligated to pay an aggregate amount of approximately $5.64 million as of January 31, 2013 as required under the terms of the contracts.

(d) Calculated based on our January 31, 2013 outstanding borrowings under the TUSA credit facility of $25.0 million and assumes no principal repayment until the maturity date in April 2017. For further discussion regarding the terms of the credit facility please refer to Note 12 - Long-Term Debt under Item 8 in this annual report.

(e) Calculated based on our January 31, 2013 outstanding aggregate principal amount of $120.0 million of 5% Convertible Note with no stated maturity date. The interest on the Convertible Note is payable in kind and added to the principal balance of the note. For further discussion regarding the terms of the Convertible Note, please refer to Note 12 - Long-Term Debt under Item 8 in this annual report.

(f) As of January 31, 2013, RockPile had various commitments for future expenditures relating to (i) leases of land, rail spur, rail cars and tractor trailer units, (ii) transloading services and track rental and (iii) an agreement relating to the use of technology and equipment for transportation, transloading and storage of bulk commodities.

(g) On October 1, 2012, TUSA entered into two midstream services agreements with Caliber North Dakota LLC, one for crude oil gathering, stabilization, treating and redelivery and one for (i) natural gas compression, gathering, dehydration, processing and redelivery; (ii) produced water transportation and disposal services; and (iii) fresh water transportation for TUSA’s oil and natural gas drilling and production operations. Under the agreements, TUSA committed to deliver minimum monthly revenues derived from the fees paid by TUSA to Caliber for volumes of oil, natural gas, produced water, and fresh water for a primary term of 15 years beginning on the in-service date of the Caliber facilities (the date on which the Caliber central facility has been substantially completed and has commenced commercial operation, estimated to occur between July 31, 2013 and September 1, 2013). The total revenue commitment over the 15 year term is $337,128,710, received interchangeably across all four classes of service.

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As is customary in the oil and natural gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost.

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.

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, internal costs directly 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.

Full Cost Accounting’s Non-recognition of Service Income with Third Parties in Certain Circumstances

Both the successful efforts accounting method and the full cost accounting method require the elimination of revenue, cost of sales and gross profit for intercompany transactions in consolidated financial statements. Hence, upon consolidation, Triangle eliminates RockPile’s revenues, costs of sales and gross profit on a well to the extent of Triangle’s working interest in the well.

Unlike the successful efforts accounting method, the full cost accounting method also restricts or eliminates recognition of service income with third parties in certain circumstances. The full cost accounting method’s Rule

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4-10(c)(6)(iv)(C) is to be broadly applied whereby Triangle may recognize no pressure pumping services income on behalf of third parties, as well as Triangle, with regard to a well operated by Triangle or a Triangle affiliate. If Triangle or a Triangle affiliate is the well’s operator, then no income earned on RockPile pressure pumping services for the well may be currently recognized in Triangle’s financial statements, regardless of how much economic interest Triangle may have in that well. Such income is credited to Triangle’s capitalized well costs and indirectly recognized later through a lower amortization rate as proved reserves are produced. Such income is pressure pumping revenue in excess of related expenses in providing pressure pumping services, including the portion of RockPile general and administrative expenses (i) identifiable with those pressure pumping services and (ii) incurred in the period of service.

Where Triangle (or a Triangle affiliate) is not the well operator, the full cost accounting method’s Rule 4-10(c)(6)(iv)(A) restricts recognition of consolidated service income (such as pressure pumping) for a well to such income that exceeds Triangle’s share of costs incurred and estimated to be incurred in connection with the drilling and completion of the well, for Triangle’s related property interests acquired within the twelve-month period preceding engagement for the service. As a simplified example, if RockPile provides pressure pumping services on a well not operated by Triangle, but in which Triangle has a recently acquired 5% working interest for which Triangle’s share of well cost are $500,000 (after elimination of consolidated intercompany profit), then Triangle cannot recognize the first $500,000 of other pressure pumping income on the well. To the extent income cannot be currently recognized, Triangle charges such service income against service revenue and credits the well’s capitalized costs. The deferred income is indirectly recognized later through a lower amortization rate as proved reserves are produced.

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

We use the units-of-production method to amortize over proved reserves the cost of our oil and natural gas properties. Changes in our estimates of proved reserve quantities will cause corresponding changes in amortization expense for the revision period and for periods thereafter as the reserves are produced. In some cases, a reduction in reserve estimates will lead to a full cost ceiling limitation charge in the period of the revision.

The process of estimating quantities of oil and natural gas reserves is complex, requiring significant decisions and judgments in the evaluation of available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and varying economic conditions, particularly as to the economic viability of proved undeveloped reserves in light of upfront development costs. As a result, material revisions to existing reserve estimates may occur from time to time.

At January 31, 2013, 59% of our total proved reserves are categorized as proved undeveloped. All of these proved undeveloped reserves are in the Bakken Shale formation or Three Forks formation in North Dakota.

Our internal Senior Reservoir Engineer reviews our reserve estimates at least quarterly and revises our proved reserve estimates, as significant new information becomes available.

Derivative Instruments

The Company has entered into commodity derivative instruments, primarily utilizing single day puts or costless collars to reduce the effect of price changes on a portion of our future oil production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the gain/loss on derivatives line on the consolidated statement of operations. We value our derivative instruments by obtaining independent market quotes, as well as using industry-standard models that

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consider various assumptions, including quoted forward prices for commodities, risk free interest rates, and estimated volatility factors, as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or us, as appropriate. We utilize our valuations to assess the reasonableness of counterparties’ valuations. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. For additional discussion, please refer to Note 13 - Commodity Derivative Instruments under Item 8 of this annual report.

Income Taxes

Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are accounted for using the liability method. Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized. The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense.

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

Triangle recognizes compensation related to all equity-based awards in the consolidated financial statements based on their estimated grant-date fair value. We grant various types of equity-based awards including restricted stock units and stock options at Triangle, and restricted units at RockPile (“Series B Units”). The fair value of stock option and Series B Unit awards is determined using the Black-Scholes option pricing model. Service-based restricted stock 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 10 — Stock Based Compensation for additional information regarding our stock-based compensation.

Revenue Recognition

All revenue is recognized when persuasive evidence of an arrangement exists, the service is complete or the equipment has been delivered to the customer, the amount is fixed or determinable and collectability is reasonably assured, as follows:

Oil and Natural Gas Revenue. The Company recognizes revenues from the sale of crude oil and natural gas using the sales method of accounting. Revenues from the sale of crude oil and natural gas are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract.

Pressure Pumping Revenue. The Company enters into arrangements with its customers to provide hydraulic fracturing services, which can be either on a spot market basis or under term contracts. We only enter into arrangements with customers for which we believe that collectability is reasonably assured. Revenue is recognized and customers are invoiced upon the completion of each job, which generally consists of numerous fracturing stages. Once a job has been completed to the customer’s satisfaction, a field ticket is written that includes charges for the service performed and the chemicals and proppants consumed during the course of the service. The field ticket also includes charges for the mobilization of the equipment to the location, additional equipment used on the job, if any, and other miscellaneous consumables. Rates for services performed on a spot market basis are based on agreed-upon market rates. With respect to services performed under term contracts, customers are invoiced a monthly mandatory payment as defined in the contract, whether or not those services are actually utilized. To the

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our primary market risk is market changes in oil and natural gas prices. The market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future, which will impact our prospective revenues from the sale of products or properties. Currently, we use single-day puts and costless collars to reduce the effect of price changes on a portion of our future oil production. We do not enter into derivative instruments for trading purposes. All hedges are accounted for using mark-to-market accounting.

We use costless collars to establish floor and ceiling prices on our anticipated future oil production. We neither receive nor pay net premiums when we enter into these arrangements. These contracts are settled monthly. When the settlement price (the market price for oil or natural gas on the settlement date) for a period is above the ceiling price, we pay our counterparty. When the settlement price for a period is below the floor price, our counterparty is required to pay us.

We have used single day puts as a hedge against Caliber revenue commitments. We paid a cash premium for these contracts which are settled on a single day in the future. If the oil price is below the strike price on the date of settlement, we receive a cash settlement. If the oil price is above the strike price on the date of settlement, nothing is owed by the Company to the counterparty.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. TUSA is currently a party to derivative contracts with one counterparty. The Company has a netting arrangement with the counterparty that provides for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. Although the instruments are valued using indices published by established exchanges, the instruments are traded directly with the counterparty. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and natural gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, these instruments may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions.

The Company’s commodity derivative contracts as of March 31, 2013 are summarized below:

Contract Type	Basis (1)	Quantity	Strike Price	Term or End Date
Collar	NYMEX	500 bopd	$85.00 / $104.30	February 1, 2013 - December 31, 2013
Collar	NYMEX	250 boepd	$90.00 / $102.50	February 1, 2013 - September 30, 2013
Collar	NYMEX	250 boepd	$90.00 / $102.50	February 1, 2013 - September 30, 2013
Collar	NYMEX	500 bopd	$85.00 / $100.50	February 1, 2013 - December 31, 2013
Collar	NYMEX	250 bopd	$90.00 / $101.50	February 1, 2013 - December 31, 2013
Collar	NYMEX	500 bopd	$80.00 / $101.20	January 1, 2014 - December 31, 2014
Collar	NYMEX	250 bopd	$85.00 / $99.50	January 1, 2014 - December 31, 2014
Put	NYMEX	200,000 bbl	$75.00	June 17, 2013
Put	NYMEX	100,000 bbl	$75.00	June 17, 2013
Put	NYMEX	100,000 bbl	$75.00	June 17, 2013
Put	NYMEX	300,000 bbl	$75.00	December 16, 2013
Put	NYMEX	100,000 bbl	$75.00	December 16, 2013
Put	NYMEX	100,000 bbl	$75.00	December 16, 2013

(1) NYMEX refers to quoted prices on the New York Mercantile Exchange

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Triangle Petroleum Corporation

Consolidated Balance Sheets

	January 31,			January 31,
	2013			2012
ASSETS
CURRENT ASSETS
Cash and equivalents	$	33,116,535		$	68,815,040
Deposits and prepaid expenses	904,372			161,650
Accounts receivable:
Oil and natural gas sales	10,624,823			5,422,453
Trade	28,541,209			3,929,465
Other	954,695			474,016
Investment in marketable securities	5,065,324			—
Derivative asset	602,489			—
Inventory	1,402,980			—
Total current assets	81,212,427			78,802,624

LONG-TERM ASSETS
Oil and natural gas properties at cost, using the full cost method of accounting:
Unproved properties and properties under development, not being amortized	94,528,875			111,716,360
Proved properties	219,172,577			33,172,419
	313,701,452			144,888,779
Less: accumulated amortization	(16,666,001		)	(3,118,000		)
Net oil and natural gas properties	297,035,451			141,770,779
Other property and equipment (less accumulated depreciation of $1,618,202 and $85,122, respectively)	36,378,097			1,226,725
Equity investment	11,767,891			—
Deposits on equipment under construction	181,606			5,647,576
Other long-term assets	1,745,394			2,396,950
Total assets	$	428,320,866		$	229,844,654

LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable	$	37,042,949		$	3,428,917
Accrued liabilities:
Exploration and development	30,433,477			11,807,040
Other	7,485,353			3,189,806
Asset retirement obligations	2,948,790			1,539,871
Total current liabilities	77,910,569			19,965,634

LONG-TERM LIABILITIES
Long-term borrowings on Credit Facility	25,000,000			—
5% Convertible Note	123,022,969			—
Asset retirement obligations	473,560			83,418
Derivative liability	291,680			—
Total liabilities	226,698,778			20,049,052

COMMITMENTS AND CONTINGENCIES (Note 19)
STOCKHOLDERS’ EQUITY
Common stock, $0.00001 par value, 70,000,000 shares authorized; 46,733,011 and 43,515,958 shares issued and outstanding at January 31, 2013 and 2012, respectively	468			435
Additional paid-in capital	323,641,545			314,199,952
Accumulated deficit	(122,019,925		)	(108,260,139		)
Accumulated other comprehensive income	—			—
Total parent company stockholders’ equity	201,622,088			205,940,248
Noncontrolling interest in subsidiary	—			3,855,354
Total stockholders’ equity	201,622,088			209,795,602
Total liabilities and stockholders’ equity	$	428,320,866		$	229,844,654

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

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Triangle Petroleum Corporation

Consolidated Statements of Operations and Comprehensive Loss

For the Years Ended January 31, 2013, 2012 and 2011

	2013			2012			2011
REVENUES:
Oil and natural gas sales	$	39,614,211		$	8,135,972		$	563,670
Pressure-pumping services	20,747,321			—			—
Other	340,081			—			—
	60,701,613			8,135,972			563,670
EXPENSES:
Production taxes	4,492,836			896,062			94,654
Other lease operating expenses	3,566,360			1,541,890			62,324
Gathering, transportation and processing	150,530			21,510			14,535
Depletion, depreciation and amortization	15,081,081			3,113,872			135,296
Impairment of oil and natural gas properties	—			10,416,202			14,917,356
Gain on sale of oil and natural gas properties	—			—			(1,006,294		)
Accretion of asset retirement obligations	183,501			166,925			250,319
Pressure-pumping	16,605,413			—			—
General and administrative:
Stock-based compensation	6,465,782			7,567,312			1,066,311
Salaries and benefits	14,922,376			4,628,027			1,211,972
Other general and administrative	7,402,934			4,737,001			4,189,382
Foreign exchange loss	656			21,938			(35,615		)
Total operating expenses	68,871,469			33,110,739			20,900,240

LOSS FROM OPERATIONS	(8,169,856		)	(24,974,767		)	(20,336,570		)

OTHER INCOME (EXPENSE):
Loss on derivative activities	(3,570,151		)	—			—
Interest expense	(2,818,118		)	—			—
Loss from equity investment	(282,712		)	—			—
Interest income	134,478			286,643			59,373
Other income (loss)	222,630			265,181			—
Total other income (expense)	(6,313,873		)	551,824			59,373

NET LOSS BEFORE INCOME TAXES	(14,483,729		)	(24,422,943		)	(20,277,197		)
Income tax provision	—			—			—
NET LOSS	(14,483,729		)	(24,422,943		)	(20,277,197		)
Less: net (income) loss attributable to noncontrolling interest in subsidiary	723,942			144,647			—
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(13,759,787	)	$	(24,278,296	)	$	(20,277,197	)

Net loss per common share outstanding - basic and diluted	$	(0.31	)	$	(0.60	)	$	(1.63	)

Weighted average common shares outstanding - basic and diluted	44,475,201			40,707,957			12,463,751

COMPREHENSIVE LOSS:
Net loss attributable to common stockholders	$	(13,759,787	)	$	(24,278,296	)	$	(20,277,197	)
Other comprehensive income (loss)	—			—			—
Total comprehensive loss	$	(13,759,787	)	$	(24,278,296	)	$	(20,277,197	)

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

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Triangle Petroleum Corporation

Consolidated Statements of Cash Flows

For the Years Ended January 31, 2013, 2012 and 2011

	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(14,483,729	)	$	(24,422,943	)	$	(20,277,197	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	15,081,081			3,113,872			135,296
Impairment of oil and natural gas properties	—			10,416,202			14,917,356
Stock-based compensation	6,637,409			7,567,312			1,066,311
Interest expense not paid in cash	2,738,303			—			—
Gain on sale of oil and natural gas properties	—			—			(1,006,294		)
Accretion of asset retirement obligations	183,501			166,925			250,319
Unrealized loss on derivatives	3,578,191			—			—
Unrealized loss on equity investment	282,712			—			—
Unrealized income on securities held for investment	(204,316		)	—			—
Changes in related current assets and liabilities:
Prepaid expenses and deposits	(1,152,665		)	(135,648		)	26,566
Accounts receivable:
Oil and natural gas sales	(5,202,370		)	(5,266,964		)	—
Trade	(24,611,744		)	(3,918,934		)	—
Other	(480,679		)	(407,204		)	80,956
Inventory	(1,402,980		)	—			—
Accounts payable and accrued liabilities	22,053,800			424,767			1,295,523
Asset retirement expenditures	(253,476		)	(303,655		)	(29,363		)
Cash provided by (used in) operating activities	2,763,038			(12,766,270		)	(3,540,527		)

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property expenditures	(135,818,178		)	(107,594,044		)	(16,255,639		)
Sale of oil and natural gas properties	3,264,745			46,800			976,900
Purchase of other property and equipment	(31,036,877		)	(1,318,597		)	—
Investment in Caliber Midstream Partners, L.P.	(12,000,603		)	—			—
Purchase of derivative contracts	(3,889,000		)	—			—
Restricted cash	—			105,264			(105,264		)
Deposits on equipment under construction	(181,606		)	(5,647,576		)	—
Non-controlling interest in subsidiary	(50,000		)	4,000,000			—
Proceeds from return of long-term deposit	—			86,080			—
Cash advanced to operators for oil and natural gas	—			(723,510		)	(715,009		)
Cash used in investing activities	(179,711,519		)	(111,045,583		)	(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		)
Proceeds from issuance of convertible note	120,000,000			—			—
Debt issuance costs	(1,269,772		)	—			—
Proceeds from credit facility	41,700,000			—			—
Repayments to credit facility	(16,700,000		)	—			—
Cash paid to settle tax on vested restricted stock units	(1,883,752		)	—			—
Purchase minority interest In RockPile	(609,000		)	—			—
Issuance of common stock for exercise of options	12,500			110,651			234,956
Cash provided by financing activities	141,249,976			134,853,624			72,534,207

NET INCREASE (DECREASE) IN CASH	(35,698,505		)	11,041,771			52,894,668
CASH, BEGINNING OF PERIOD	68,815,040			57,773,269			4,878,601
CASH, END OF PERIOD	$	33,116,535		$	68,815,040		$	57,773,269

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

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Triangle Petroleum Corporation

Consolidated Statement of Stockholders’ Equity

For the Years Ended January 31, 2013, 2012 and 2011

	Shares of Common Stock	Common Stock at Par Value		Additional Paid-in Capital			Warrants			Accumulated Deficit			Noncontrolling interest in Subsidiary			Total Equity
Balance - February 1, 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 $3.10/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		)
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
Non-controlling interest in subsidiary	—	—		—			—			—			4,000,000			4,000,000
Net loss for the year	—	—		—			—			(24,278,296		)	(144,647		)	(24,422,943		)
Balance - January 31, 2012	43,515,958	435		314,199,952			—			(108,260,138		)	3,855,353			209,795,602

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Triangle Petroleum Corporation

Consolidated Statement of Stockholders’ Equity (continued)

For the Years Ended January 31, 2013, 2012 and 2011

	Shares of Common Stock	Common Stock at Par Value		Additional Paid-in Capital			Warrants		Accumulated Deficit			Noncontrolling interest in Subsidiary			Total Equity
Common stock issued for the purchase of oil and natural gas properties	225,000	2		1,203,748			—		—			—			1,203,750
Shares issued for consulting services	10,000	1		72,899			—		—			—			72,900
Exercise of stock options	4,167	—		12,500			—		—			—			12,500
Common stock issued pursuant to termination agreement (net of shares surrendered for taxes)	17,230	—		98,728			—		—			—			98,728
Vesting of restricted stock units (net of shares surrendered for taxes)	774,941	8		(1,883,760		)	—		—			—			(1,883,752		)
Acquire minority interest in subsidiary	2,185,715	22		2,522,392			—		—			(3,131,411		)	(608,997		)
Stock-based compensation	—	—		7,415,086			—		—			—			7,415,086

Net loss for the year	—	—		—			—		(13,759,787		)	(723,942		)	(14,483,729		)
Balance - January 31, 2013	46,733,011	$	468	$	323,641,545		$	—	$	(122,019,925	)	$	—		$	201,622,088

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF BUSINESS

Triangle Petroleum Corporation (“Triangle” or the “Company” or “we” or “our”) 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.

RockPile Energy Services, LLC, a wholly-owned subsidiary founded in June 2011, is a provider of hydraulic pressure pumping and complementary well completion services to oil and natural gas exploration and production companies in the Williston Basin of North Dakota and Montana.

The Company also holds leasehold interests in acreage in the Maritimes Basin of Nova Scotia, which we fully impaired as of January 31, 2013.

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) Triangle USA Petroleum Corporation (“TUSA”), incorporated in the State of Colorado, and its wholly-owned subsidiaries, (ii) RockPile Energy Services, LLC (“RockPile”), organized in the state of Delaware (83.33% ownership through December 28, 2012), and its wholly-owned subsidiaries, (iii) Elmworth Energy Corporation, incorporated in the Province of Alberta, Canada, (iv) Leaf Minerals, LLC, organized in the State of Colorado, (v) Integrated Operating Solutions, LLC, organized in the State of Colorado, (vi) Caliber Midstream, LLC, organized in the State of Delaware, and (vii) Triangle Caliber Holdings, LLC, organized in the State of Delaware. All significant intercompany balances and transactions have been eliminated. The Company’s fiscal year-end is January 31.

These consolidated financial statements and related notes are presented in accordance with accounting principles generally accepted in the United States of America (“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 — Summary of Significant Accounting Policies 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;

· 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;

· impairment of undeveloped properties and other assets;

· depreciation of property and equipment; and

· valuation of commodity derivative instruments.

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 fiscal year 2013 financial statement presentation. Such reclassifications had no impact on net income, statements

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of cash flows, working capital or equity previously reported.

Change in Accounting Principle

RockPile changes fiscal year-end from December 31 to January 31

RockPile historically had a December 31 fiscal year-end. Thus, RockPile’s financial results included in our consolidated financial statements were a month behind the financial results of our oil and natural gas exploration and production operating segment. With the start of RockPile operations in July 2012, RockPile has changed to a January 31 fiscal year-end. The change is preferable as it results in contemporaneous reporting of RockPile’s financial results in providing pressure pumping services for owners of oil wells operated by our subsidiary TUSA. The change avoids the need to provide supplemental disclosure of material intervening events arising from a one-month lag in financial reporting.

A change in a subsidiary’s fiscal year-end is a change in accounting principle for Triangle. Paragraph 810-10-45-13 of the Accounting Standards Codification (“ASC”) requires that the elimination of a reporting lag between a parent and subsidiary be reported as a change in accounting principle. Topic 250 of the ASC requires this change to be applied retrospectively in financial statements for all periods presented. Accordingly, the financial statements presented herein reflect RockPile financial results as if RockPile had always had a January 31 fiscal year-end.

Since RockPile began pressure pumping operations in July 2012, the accounting change has the following notable effects on the statement of operations for the year ended January 31, 2013:

· Recognition of $4.2 million in pressure-pumping revenue and $4.4 million in pressure-pumping expenses for the month of January 2013,

· Increasing general and administrative expenses by approximately $3.6 million,

· Increasing consolidated net loss by $3.8 million,

· Increasing net loss attributable to common stockholders by $3.8 million, and

· Increasing net loss per share by approximately $.09.

For the Consolidated Balance Sheet as of January 31, 2012, the change in accounting principle:

· Decreased current assets by $.7 million,

· Decreased total assets by $.7 million,

· Decreased current liabilities and total liabilities by $.2 million each,

· Increased accumulated deficit by $.4 million, and

· Decreased stockholders’ equity by $.5 million.

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 and cash equivalents consist of all highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (See Note 15 — Fair Value Measurements), marketable securities (See Note 14 — Investment in Marketable Securities) and long-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximates fair value as it bears interest at variable rates over the term of the loan. The Company’s Convertible Note is recorded at cost and the fair value is disclosed in Note 15 - Fair Value Measurements. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize

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upon the sale or refinancing of such instruments.

Accounts Receivable and Credit Policies

We have certain trade receivables due under normal trade terms and primarily consisting of oil and natural gas sales receivables and trade receivables from third parties participating in the drilling, completion and production of wells we operate. 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, 2013 and 2012, management had determined that no allowance for uncollectible oil and natural gas trade or sales receivables was necessary.

Pressure pumping accounts receivable are stated at the amount billed to customers and are ordinarily due within 30 days of the invoice date. As of the date of these consolidated financial statements, and since inception, the Company has collected all amounts owed. As a result, the Company has not provided for an allowance for doubtful accounts as of the date of the consolidated financial statements. Our current customer base is comprised of our parent company and other highly credit-worthy third-party customers. Periodically, the Company performs a review of its customer base including outstanding receivables, historical collection information, existing economic conditions and the customer’s creditworthiness to determine the need for establishing an allowance for doubtful accounts. A provision for doubtful accounts would be recorded when non-payment of amounts owed is deemed probable.

Inventories

Inventories currently maintained by the Company consist of well equipment and sand and/or ceramic proppant for hydraulic pressure pumping and complementary well completion services. Inventories are stated at the lower of cost or market (net realizable value) on an average cost basis with consideration given to deterioration, obsolescence and other factors in evaluating net realizable value.

Inventories at January 31, 2013, consisted of the following:

Well equipment	$	1,285,276
Mesh Sand	117,704
Total Inventory	$	1,402,980

Investment in Unconsolidated Entities

The Company accounts for its investments in unconsolidated entities by the equity method. The Company’s share of earnings (loss) in the unconsolidated entity is included in other income (loss) on the Consolidated Statements of Operations and Comprehensive Loss. The carrying value of the Company’s investments in unconsolidated entities is recorded in the Equity Investment line of the Consolidated Balance Sheets. The Company records losses of the unconsolidated entities only to the extent of the Company’s investment. See discussion in Note 7 — Investment in Unconsolidated Affiliate.

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 four financial institutions-Wells Fargo Bank, RBC Canada, Citi Private Bank and Chase Bank. We periodically evaluate the credit worthiness of financial institutions, and we maintain cash accounts only in large high quality financial institutions. We believe that credit risk associated with cash is remote. The Company often has balances in excess of the federally insured limits.

The Company’s receivables are comprised of oil and natural gas revenue receivables, joint interest billings receivable and receivables associated with pressure pumping services. The amounts are due from a limited number of entities. Therefore, the collectability is dependent upon the general economic conditions of a few purchasers, joint interest owners and customers. The receivables are not collateralized. However, to date the Company has had no bad debts.

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Other Property and Equipment

We record at cost any long-lived tangible assets that are not oil and natural gas properties. 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. Depreciation is recorded using the straight-line method (to the extent of estimated salvage values) over the estimated useful lives of the related assets as follows:

		Depreciable
Asset		Life (years)
Building and improvements		10 - 20
Pressure pumping equipment		5
Vehicles		5
Leasehold improvements		10
Software and computers		3 - 5
Office equipment		3

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.

Oil and Natural Gas Reserves

Our internal Senior Reservoir Engineer reviews our reserve estimates at least quarterly and revises our proved reserve estimates, as significant new information becomes available.

Deferred Financing Costs

Deferred financing costs include origination, legal, engineering, and other fees incurred to issue the debt in connection with the Company’s Credit Facility and Convertible Note. Deferred financing costs are amortized to interest expense on a straight-line basis over the respective borrowing term.

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Commodity Derivative Instruments

Our derivative contracts are recorded on the Consolidated Balance Sheets at fair value. The accounting treatment for settlements and the changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge for accounting treatment purposes. We did not choose to apply hedge accounting treatment to any of the contracts we entered into during the periods covered in these consolidated financial statements. Realized and unrealized gains and losses on derivatives that are not designated as hedges are recognized currently in costs and expenses associated with operating income in our consolidated statements of operations. Cash settlements of our derivative contracts are included in cash flows from operating activities in our consolidated statements of cash flows.

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.

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, 2013.

Revenue Recognition

Under the full cost method, we do not currently recognize consolidated service income (such as pressure pumping services) for wells that we operate, and we recognize consolidated service income (such as pressure

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pumping) for other wells to the extent such income exceeds our share of costs incurred and estimated to be incurred in connection with the drilling and completion of a well, for our related property interests acquired within the twelve-month period preceding performance of the service. To the extent income cannot be recognized currently, we charge such service income against service revenue and credit the well’s capitalized costs. The deferred income is indirectly recognized later through a lower amortization rate as proved reserves are produced.

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.

Off Balance Sheet Arrangements

We have no significant off balance sheet arrangements.

Segment Information

In accordance with accounting guidance for disclosures about segments of an enterprise and related information, we have two reportable operating segments. Our exploration and production operating segment and our pressure pumping services operating segment are managed separately because of the nature of their products and services. The exploration and production operating segment is responsible for finding and producing oil and natural gas. The pressure pumping services operating segment is responsible for pressure pumping for both Triangle-operated wells and wells operated by third-parties. See Note 4 — Segment Reporting in the Consolidated Financial Statements.

Recently Issued Accounting Standards

No significant accounting standards applicable to Triangle have been issued during the fiscal year ended January 31, 2013.

4. SEGMENT REPORTING

RockPile is a pressure pumping services company that was formed in June 2011 and initially capitalized between June and October 2011. Historically, our pressure pumping services business was presented as part of other operations as it had not yet begun operations and was not considered significant. RockPile began operations in July 2012, and as a result is now being recognized as a reportable segment.

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Management evaluates the performance of our segments based upon income (loss) before income taxes. The following table presents selected financial information for Triangle’s operating segments for the fiscal year ended January 31, 2013.

	Exploration and Production			Pressure Pumping Services		Eliminations and Other			Consolidated Total
Revenues
Oil and natural gas sales	$	39,614,211		$	—	$	—		$	39,614,211
Pressure-pumping services for third parties	—			22,534,586		(1,787,265		)	20,747,321
Intersegment revenues	—			34,672,441		(34,672,441		)	—
Other	340,081			—		—			340,081
	39,954,292			57,207,027		(36,459,706		)	60,701,613
Expenses
Production taxes and other lease operating	8,059,196			—		—			8,059,196
Gathering, transportation and processing	150,530			—		—			150,530
Depletion, depreciation and amortization	13,955,747			2,856,904		(1,731,570		)	15,081,081
Accretion of asset retirement obligations	183,501			—		—			183,501
Pressure-pumping	—			39,533,380		(22,927,967		)	16,605,413
General and Administrative:
Stock-based compensation	5,848,648			617,134		—			6,465,782
Other general and administrative	11,195,686			11,129,624		—			22,325,310
Foreign exchange loss	656			—		—			656
Total operating expenses	39,393,964			54,137,042		(24,659,537		)	68,871,469
Income (loss) from operations	560,328			3,069,985		(11,800,169		)	(8,169,856		)
Other income (expense)	(6,317,870		)	3,997		—			(6,313,873		)
Net income (loss) before income taxes	$	(5,757,542	)	$	3,073,982	$	(11,800,169	)	$	(14,483,729	)

Total Assets	$	403,097,333		$	38,668,376	$	(13,444,843	)	$	428,320,866
Net oil and natural gas properties	$	308,835,620		$	—	$	(11,800,169	)	$	297,035,451
Other property and equipment - net	$	2,658,856		$	33,719,241	$	—		$	36,378,097
Total Liabilities	$	216,498,315		$	11,845,137	$	(1,644,674	)	$	226,698,778

Eliminations and Other

For consolidation, intercompany revenues and expenses are eliminated. In the elimination of intercompany pressure pumping revenues and $10,012,905 gross profit, there is a corresponding $10,012,905 reduction in Triangle’s capitalized well costs.

Under the full cost method, we deferred recognition of an additional $1,787,265 in service income in fiscal year 2013— charging such service income against service revenue and crediting capitalized costs of the related wells. The deferred income of $1,787,265 is indirectly recognized later through a lower amortization rate as proved reserves are produced.

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5. PROPERTY AND EQUIPMENT

Property and equipment as of January 31, 2013 and 2012 consisted of the following:

	January 31,			January 31,
	2013			2012
Oil and natural gas properties, full cost method:
Unproved properties and properties under development, not being amortized	$	94,528,875		$	111,716,360
Proved properties	219,172,577			33,172,419
	313,701,452			144,888,779
Less accumulated amortization	(16,666,001		)	(3,118,000		)
Net carrying value of oil and natural gas properties	297,035,451			141,770,779
Cost of other property and equipment	37,996,299			1,311,847
Deposits on equipment under construction	181,606			5,647,576
Less accumulated depreciation and amortization	(1,618,202		)	(85,122		)
Net property and equipment	$	333,595,154		$	148,645,080

During fiscal year 2013, we acquired oil and natural gas properties and participated in the drilling and/or completion of wells, for total consideration of approximately $176.5 million ($29.3 million for the acquisition of leaseholds), which consisted of cash in the amount of $136.8 million, accrued liabilities and prepaid well costs of $38.5 million and common stock consideration of $1.2 million.

On April 30, 2012, we entered into an agreement to sell a 7% interest (approximately 3,700 net undeveloped acres) in the Station Prospect for $2.7 million. The proceeds of this sale were recorded as a reduction of the full cost pool consistent with full cost accounting rules.

On January 9, 2013, we sold approximately 1,590 net acres in McKenzie County in exchange for approximately 120 net acres in McKenzie County and 851,315 shares of Emerald Oil, Inc. common stock as further discussed in Note 14 — Investment in Marketable Securities. The proceeds of this sale were recorded as a reduction of the full cost pool consistent with full cost accounting rules.

In the fiscal year ended January 31, 2013 and 2012, we capitalized $2.0 million and $0.6 million, respectively, of internal land and geology department costs directly associated with property acquisition, exploration (including lease record maintenance) and development. The internal land and geology department costs were capitalized to unevaluated costs.

In fiscal year ending January 31, 2013, we capitalized interest expense of $0.4 million to the full cost pool.

Other property and equipment is located in the U.S. The fiscal year 2013 balance includes approximately $33.7 million spent to acquire pressure pumping equipment and facilities for RockPile.

Deposits on equipment under construction at January 31, 2013 and 2012 consisted of deposits for pressure pumping equipment of RockPile. Fiscal year 2013 equipment costs are for equipment that has not been put into service and is not currently depreciated. The equipment is anticipated to go into service in the second quarter of fiscal year 2014. The equipment associated with the fiscal year 2012 costs was placed into service in July 2012.

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.

During fiscal year 2012, we recorded a $6.0 million “ceiling test” impairment expense of the capitalized costs of our U.S. oil and natural gas properties. During fiscal year 2012, we also recorded impairments of $4.4 million in connection with our properties in the Maritimes Basin of Nova Scotia. We assess all unproved property for possible

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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 underwent an extensive hydraulic fracturing review to determine whether and how hydraulic fracturing will be allowed in the future. 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.

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,
	2013		2012
Costs incurred during the year:
Acquisition of properties:
Proved	$	623,243	$	—
Unproved	20,569,654		87,225,544
Exploration	55,583,340		40,724,287
Development	91,666,473		4,705,568
Oil and natural gas expenditures	168,442,710		132,655,399
Asset retirement obligation, net	369,963		3,493
	$	168,812,673	$	132,658,892

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, 2013 and 2012:

	2013			2012
Proved properties	$	219,172,577		$	33,172,419
Unproved properties and properties under development, not being amortized	94,528,875			111,716,360
	313,701,452			144,888,779
Less accumulated amortization	(16,666,001		)	(3,118,000		)
Net oil and natural gas properties	$	297,035,451		$	141,770,779

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Costs Not Being Amortized

The following table summarizes oil and natural gas property costs not being amortized at January 31, 2013, by year that the costs were incurred:

			Type of Capitalized Cost
	Total		Acquisition		Exploration
Capitalized at January 31, 2013
Not yet being amortized	$	94,528,875	$	85,349,906	$	9,178,969
Incurred in fiscal year 2013	$	29,143,254	$	19,964,285	$	9,178,969
Incurred in fiscal year 2012	$	57,035,599	$	57,035,599	$	—
Incurred in fiscal year 2011	$	8,350,022	$	8,350,022	$	—
Incurred in prior years	$	—	$	—	$	—

The $94.5 million of costs not being amortized includes $9.2 million in costs for unevaluated wells in progress expected to be completed prior to January 31, 2014. 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.

The majority of the unproved oil and natural gas property costs, which are not subject to amortization, relate to oil and natural gas property acquisitions and leasehold acquisition costs as well as work-in-progress on various projects. The Company expects that substantially all of its unproved property costs as of January 31, 2013 will be reclassified to proved properties over fiscal years 2014 through fiscal year 2017.

Amortization Expense

Amortization expense of oil and natural gas properties in the U.S. for fiscal years 2013, 2012 and 2011 was $13,548,000 ($27.75/boe), $3,022,000 ($31.85/boe) and $96,000 ($9.48/boe), respectively. Outside the United States, we had no oil production, natural gas production or amortization expense of oil and natural gas properties in those three fiscal years.

6. ASSET RETIREMENT OBLIGATIONS

The following table reflects the components of the changes in the carrying amount of the asset retirement obligations for the years ended January 31, 2013 and 2012:

	2013			2012
Balance, beginning of period	$	1,623,289		$	1,403,697
Liabilities incurred	1,769,615			423,111
Revision of estimates	147,862			(52,966		)
Sale of assets	(48,441		)	(13,822		)
Liabilities settled	(253,476		)	(303,656		)
Accretion	183,501			166,925
Balance, end of period	3,422,350			1,623,289
Less current portion of obligations	(2,948,790		)	(1,539,871		)
Long-term asset retirement obligations	$	473,560		$	83,418

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The $2,948,790 of current obligations consist of (a) an estimated $1,448,790 for (i) reclamation of man-made “ponds” holding produced formation water and (ii) the plugging and abandonment of well bores in the Maritimes Basin of Canada and (b) $1,500,000 for the estimated costs to plug and abandon several producing (but marginally economic) vertical wells drilled years ago on North Dakota leases we acquired in the second half of fiscal year 2013. These North Dakota leases are “held by production”, i.e., continue in force by production. We intend to drill, complete and produce horizontal wells on the leases in fiscal year 2014, allowing us to plug and abandon the marginally economic vertical wells and still hold the leases by production.

7. INVESTMENT IN UNCONSOLIDATED AFFILIATE

On October 1, 2012, Triangle Caliber Holdings, LLC (“Triangle Caliber Holdings”), a wholly owned subsidiary of Triangle, entered into a joint venture with FREIF Caliber Holdings LLC (“FREIF Caliber Holdings”), a wholly-owned subsidiary of First Reserve Energy Infrastructure Fund, L.P. The newly formed joint venture entity, Caliber Midstream Partners, L.P. (“Caliber”), plans to provide crude oil, natural gas and water transportation services to the Company and third-parties primarily within the Williston Basin of North Dakota and Montana.

In connection with the joint venture, Triangle Caliber Holdings entered into a Contribution Agreement, dated October 1, 2012 (the “Contribution Agreement”), with FREIF Caliber Holdings, Caliber, and Caliber Midstream GP LLC (“Caliber GP” and together with Caliber, the “Caliber Joint Venture Entities”). Pursuant to the terms of the Contribution Agreement, Triangle Caliber Holdings agreed to transfer certain assets, consisting primarily of rights-of-way located in McKenzie County, North Dakota, as well as cash consideration with an aggregate value of $30 million to the Caliber Joint Venture Entities in exchange for (A) a fifty percent (50%) membership interest in Caliber GP, (B) 3,000,000 Class A Units representing a thirty percent (30%) limited partner interest in Caliber, and (C) 4,000,000 Class A Trigger Units. Also pursuant to the terms of the Contribution Agreement, FREIF Caliber Holdings agreed to contribute $70 million to the Caliber Joint Venture Entities in exchange for (A) a fifty percent (50%) membership interest in Caliber GP, and (B) 7,000,000 Class A Units representing a seventy percent (70%) limited partner interest in Caliber.

Upon the achievement of certain operational thresholds, the Class A Trigger Units held by Triangle Caliber Holdings will convert into Class A Units, resulting in Triangle Caliber Holdings and FREIF Caliber Holdings each owning a 50% limited partner interest in Caliber. A portion of the above referenced cash contribution amounts to Caliber by each of Triangle Caliber Holdings and FREIF Caliber Holdings were funded concurrently with the execution of the Contribution Agreement, with the balance of the contributions to be funded in two equal contributions. The first of the two contributions occurred in the fourth quarter of fiscal year 2013 and the second of the two will be paid in the first quarter of fiscal year 2014.

Triangle also received (A) 4,000,000 Class A warrants with an exercise price of $14.69, which have a 12-year life, contain a cashless exercise feature, and have standard provisions whereby the strike price is reduced by the amount of any per unit Class A distributions, subject to a $5.00 floor; (B) 2,400,000 Class A warrants with a strike price of $24.00 (and feature the same provisions of the $14.69 warrants); and (C) 1,600,000 Class A Trigger warrants which become warrants with a $14.69 strike price as described above, subject to certain business performance metrics associated with the Class A Trigger units.

While the Contribution Agreement sets forth the minimum initial capital contributions to the joint venture by Triangle Caliber Holdings and FREIF Caliber Holdings, the limited partnership agreement governing the joint venture permits the contribution of additional capital in return for additional Class A units in the joint venture.

We use the equity method of accounting for our investment in Caliber, with earnings or losses reported in other income (loss) on the Consolidated Statement of Operations and Comprehensive Loss.

As of January 31, 2013, the balance of Triangle’s investment was $11.8 million. The investment balance was decreased by $282,712, which was Triangle’s share of Caliber’s net loss for the fiscal year.

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8. 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 2013, 2012 and 2011:

	2013			2012			2011
Current tax benefit	$	—		$	—		$	—
Deferred tax benefit	(2,442,774		)	(7,874,028		)	(5,866,580		)
Valuation Allowance - United States and Canada	2,442,774			7,874,028			5,866,580
Income tax expense	—			—			—
Loss before income taxes	$	(14,483,729	)	$	(24,422,943	)	$	(20,277,197	)
Effective income tax rate	0%			0%			0%

Reconciliations of the income tax benefit calculated at the federal statutory rate of 35.0% to the total income tax (benefit) expense are as follows for fiscal years 2013, 2012 and 2011:

	2013			2012			2011
Federal statutory tax benefit	$	5,069,305		$	8,360,735		$	7,097,019
State income taxes, net of federal income tax benefit	360,839			565,005			608,316
Permanent differences	(2,280,460		)	(131,527		)	(19,597		)
Difference in foreign tax rates	(27,850		)	(600,189		)	(1,936,736		)
Effect of tax rate change	70,713			(82,859		)	—
Changes in valuation allowance	(2,442,774		)	(7,874,028		)	(5,866,580		)
Other	(749,773		)	(237,137		)	117,578
Provision for income taxes	$	—		$	—		$	—

The difference in foreign tax rate of $27,850 is a result of adjusting the US effective tax rate of 35.0% down to the Canadian effective tax rate of 25.0%.

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The components of Triangle’s net deferred income tax assets are as follows for fiscal years 2013 and 2012:

	2013			2012
Current:
Assets:
Uncollectible accounts receivable	$	—		$	—
Non-Current:
Assets:
Canadian oil and natural gas properties	6,094,752			6,104,357
United States net losses carried forward	37,815,594			26,975,337
Canadian net losses carried forward	1,725,703			1,610,721
Asset retirement obligations	1,102,112			416,137
Stock-based compensation	1,356,203			1,957,820
Investment in RockPile	—			128,483
Investment in Caliber Midstream Partners	105,993			—
Property and equipment	157,219			23,059
Derivative assets	1,341,513			—
Other	672,928			2,626
Total assets	50,372,017			37,218,540
Liabilities:
United States oil and natural gas properties	(15,274,608		)	(8,011,710		)
Other	(76,601		)	—
Gross deferred income tax assets	35,020,808			29,206,830
Valuation allowance	(35,020,808		)	(29,206,830		)
Net deferred income tax asset	$	—		$	—

In accordance with ASC 740, Accounting for Income Taxes, and consistent with prior periods, Triangle has determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that the net deferred tax assets will not be realized. Hence, all deferred tax benefits will be reserved through a valuation allowance recorded as part of the effective tax rate. The key negative evidence considered in this determination includes the following: (1) a history of both book and tax losses; (2) cumulative losses in recent years; (3) an expectation of tax losses during the next four to five years; (4) no taxable income in available carryback years; (5) no current tax planning strategies contemplated to realize the valued deferred tax assets. Furthermore, the combination of historical/cumulative losses as well as an expectation of tax losses in the foreseeable future is the basis for the full valuation allowance (to the extent of the net deferred tax asset).

The Company has a U.S. net operating loss carry-forward for federal tax purposes of approximately $101 million, and a Canadian NOL of approximately $6.9 million at January 31, 2013 that could be utilized to offset taxable income of future years. The U.S. NOL carryforwards begin expiring in 2023 and the Canadian NOL carryforwards begin expiring in 2026. Although certain tax years are closed under the statute of limitations, tax authorities can still adjust tax losses being carried forward to open tax years.

At January 31, 2013 and 2012, 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 2010 to 2012 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 2010 to 2012, except for Colorado which is open for the fiscal years 2009 to 2012. We also file with various Canadian taxing authorities which remain open for fiscal years 2009 to 2012.

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9. 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, 2013.

A summary of our common stock activity for the fiscal year ended January 31, 2013 is as follows:

· We issued 2,185,715 shares of common stock in December 2012 for the purchase of the minority interest (16.67% remaining interest) of RockPile.

· We issued 774,941 shares of common stock (net of shares surrendered for taxes) for restricted stock units that vested during the period.

· We issued 225,000 shares of common stock as additional consideration for interests in federal oil and natural gas leases (720 net acres) in McKenzie County, North Dakota.

· We issued 17,230 shares of common stock (net of shares surrendered for taxes) in connection with an employment termination agreement.

· We issued 10,000 shares of common stock for consulting services.

· We issued 4,167 shares of common stock pursuant to the exercise of stock options.

10. SHARE-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 could 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 available for issuance automatically increased or decreased as the number of issued and outstanding shares of common stock changed. Pursuant to the Rolling Plan, stock options became exercisable ratably in one-third increments on each of the first, second and third anniversaries of the date of the grant, and could be granted at an exercise price of not less than fair value of the common stock at the time of grant and for a term not to exceed ten years.

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 granted under the Rolling Plan. All outstanding awards under the Rolling Plan shall continue in accordance with their applicable terms and conditions.

The 2011 Plan, as amended in November 2012, authorizes the Company to issue stock options, stock appreciation rights (“SAR”s), 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 and its subsidiaries. The maximum number of shares of common stock reserved for issuance under the 2011 Plan is 5,900,000 shares, subject to adjustment for certain transactions.

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

	Years Ended January 31,
	2013			2012			2011
Restricted stock units	$	6,639,319		$	7,511,959		$	792,893
Stock options	59,906			81,057			93,418
Stock issued pursuant to termination agreements	98,728			184,840			180,000
RockPile stock based compensation related to Series B Units	617,134			—			—
	7,415,087			7,777,856			1,066,311
Less amounts capitalized to oil and natural gas properties	(949,305		)	(210,544		)	—
Compensation expense	$	6,465,782		$	7,567,312		$	1,066,311

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

Restricted Stock Units

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

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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.

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

	Number of Shares		Weighted- Average Award Date Fair Value
Restricted stock units outstanding - January 31, 2010	—
Units granted in fiscal year 2011	509,636		$	5.61
Restricted stock units outstanding - January 31, 2011	509,636		$	5.61
Units granted in fiscal year 2012	2,645,110		$	7.06
Units forfeited in fiscal year 2012	(134,000	)	$	6.81
Units that vested in fiscal year 2012	(532,404	)	$	6.20
Restricted stock units outstanding - January 31, 2012	2,488,342		$	7.02
Units granted in fiscal year 2013	1,041,400		$	6.37
Units forfeited in fiscal year 2013	(105,600	)	$	7.59
Units that vested in fiscal year 2013	(1,000,057	)	$	6.90
Restricted stock units outstanding - January 31, 2013	2,424,085		$	6.68

For the fiscal years 2013 and 2012, the Company recorded $6,639,319 and $7,511,959, respectively, of stock-based compensation related to previous grants of restricted stock units.

The total grant date fair value of the restricted stock units that vested during fiscal years 2013 and 2012 was $6,903,217 and $3,300,905, respectively.

Unamortized compensation cost related to unvested restricted stock units at January 31, 2013 was $12.779 million. We expect to recognize that cost over a weighted average period of 2.03 years.

Subsequent to January 31, 2013, the Company awarded 450,000 restricted stock units to certain officers and directors. The vesting period of such restricted stock units is between one and five years.

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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 three 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	(79,166	)	$	3.00
Options outstanding - January 31, 2011 (125,833 exercisable)	343,334		$	1.60
Less: options forfeited	(25,000	)	$	3.00
Less: options exercised	(82,501	)	$	1.34
Options outstanding - January 31, 2012 (142,500 exercisable)	235,833		$	1.50
Less: options exercised	(4,167	)	$	3.00
Options outstanding - January 31, 2013 (231,666 exercisable)	231,666		$	1.48

The intrinsic value of options exercised during fiscal years 2013 and 2012 was $12,000 and $447,000, respectively. The Company received approximately $12,500 for the exercise of 4,167 options in fiscal year 2013 and 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:

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

		Remaining
Exercise price		contractual life	Number of shares
per share		(years)	Outstanding		Exercisable
$	3.00	.99	30,000		30,000
$	1.25	1.83	201,666		201,666
			231,666		231,666

Weighted average exercise price per share			$	1.48	$	1.48

Weighted average remaining contractual life			1.72		1.72

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 $59,906 and $81,057 for fiscal years 2013 and 2012, respectively.

As of January 31, 2013, there was no remaining unrecognized compensation cost related to non-vested stock options.

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A summary of the status of the Company’s non-vested stock options as of January 31, 2013, and changes during the years ended January 31, 2013, 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
Options vested	(93,332	)	$	1.02
Non-vested options - January 31, 2013	—		$	—

RockPile Share Based Compensation (Series B Units)

At January 31, 2013, Triangle owned all of the 24,000,000 Series A Units of ownership of RockPile (an LLC), issued to the three parties who had contributed the initial $24,000,000 in RockPile’s paid-in capital prior to October 31, 2011. Triangle had contributed $20,000,000 and received 20,000,000 Series A Units by October 31, 2011. On December 28, 2012, Triangle acquired the other 4,000,000 Series A Units from the other two original owners of Series A units.

Effective October 22, 2012, RockPile’s Board of Directors approved the Second Amended and Restated Limited Liability Company Agreement (“LLC Agreement”) which includes provisions allowing RockPile to make equity grants in the form of restricted units (“Series B Units”) pursuant to Equity Grant Agreements. The LLC Agreement , which was formally executed by the Company and its members on October 31, 2012, authorizes RockPile to issue an aggregate of up to 6,000,000 Series B Units in multiple series designated by a sequential number (i.e., Series B-1, Series B-2, etc.) with the right to re-issue forfeited or redeemed Series B Units. As of January 31, 2013, RockPile had granted 3,160,000 Series B Units, of which 1,501,667 were unvested at that date. The grants were to several RockPile employees in key positions at RockPile.

The Series B Units are intended to constitute interests in future profits, i.e., “profit interests” within the meaning of Internal Revenue Service Revenue Procedures 93-27 and 2001-43. Accordingly, the capital account associated with each Series B Unit at the time of its issuance shall be $0. RockPile’s Board of Directors may designate a “Liquidation Value” applicable to each tranche of a Series B Unit so as to constitute a net profits interest in RockPile. The Liquidation Value shall equal the dollar amount per unit that would, in the reasonable determination of RockPile’s Board of Directors, be distributed with respect to the initial Series B tranche if, immediately prior to the issuance of a new Series B tranche, the assets of RockPile were sold for their fair market value and the proceeds (net of any liabilities of RockPile) were distributed.

RockPile’s Series A Units are entitled to a return of contributed capital and an 8.0% preferred return since July 11, 2011 on such capital before Series B Units participate in profits. The initial Series B tranche (Series B-1 Units) participates pro-rata with the Series A Units once the preferred return has been achieved. However, no distributions shall be made with respect to any Series B-1 Unit until total cumulative distributions to the Series A Units total $40 million. After distributions totaling $40 million have been made to the Series A units, future distributions will be allocated to the Series B-1 units until the per unit profits distributed to the Series B-1 Units is equivalent to the per unit profits distributed to the Series A units. Thereafter, all further distributions would be distributed on a pro-rata basis. Subsequent issuances of Series B Units will begin participating on a pro rata basis once the per unit profits allocated to the Series B-1 Units reaches the Liquidation Value of the subsequent Series B Unit issuance.

Series B Units currently have a 15 to 34 month vesting period. Compensation costs are determined using a Black-Scholes option pricing model based upon the grant date calculated fair market value of the award and is recognized ratably over the applicable vesting period.

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Series B Units are valued using a waterfall valuation approach beginning with the initial asset valuation contained in the LLC Agreement with each tranche of Series B Units constituting a waterfall valuation event. Additionally, due to the limited operating history of RockPile, its private ownership and the nature of the equity grants, RockPile has made use of estimates as it relates to employee termination and forfeiture rates, used different valuation techniques including income and/or market approaches, and utilized certain peer group derived information. The assumptions used in the Black-Scholes option pricing model consist of the underlying equity value, the estimated time to liquidity which is based upon the projected exit path, volatility based upon the midpoint volatility of a publicly traded peer group, and the risk-free interest rate which is based upon the rate for zero coupon US Government issues with a term equal to the expected life.

A summary of RockPile’s Series B Unit activity for the fiscal year ended January 31, 2013 is as follows:

	Number of Series B Units	Weighted Average Award Date Unit Fair Value
Series B Units outstanding February 1, 2012	—	$	—
Series B-1 Unit Grants	3,100,000	$	0.37
Series B-2 Unit Grants	60,000	$	0.24
Series B Units outstanding January 31, 2013	3,160,000

A summary of RockPile’s Series B Unit vesting status for the year ended January 31, 2013 is as follows:

	Remaining Vesting Period (Years)	Number of Series B Units	Vested	Unvested
Series B Units outstanding, February 1, 2012		—	—	—
Series B-1 Unit Grants	1.43	3,100,000	1,658,333	1,441,667
Series B-2 Unit Grants	2.58	60,000	—	60,000
Series B Units outstanding, January 31, 2013		3,160,000	1,658,333	1,501,667

Non-cash compensation cost related to the Series B Units was $617,134 for the fiscal year ended January 31, 2013.

As of January 31, 2013, there was $538,209 of unrecognized compensation cost related to non-vested Series B Units. We expect to recognize such cost on a pro-rata basis on the Series B Units vesting schedule during the next three fiscal years.

11. EARNINGS PER SHARE

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. Diluted net income per common share includes shares of restricted stock units, and the potential dilution that could occur upon exercise of options to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of the options (which were assumed to have been made at the average market price of the common shares during the reporting period).

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The table below sets forth the computations of net loss per common share (basic and diluted) for the years ended January 31, 2013, 2012, and 2011.

	2013			2012			2011
Net loss attributable to common shareholders	$	(13,759,787	)	$	(24,278,296	)	$	(20,277,197	)
Adjustments for dilution	—			—			—
Net loss attributable to common shareholders, adjusted for dilution	$	(13,759,787	)	$	(24,278,296	)	$	(20,277,197	)

Basic weighted average common shares outstanding	44,475,201			40,707,957			12,463,751
Effect of dilutive securities	—			—			—
Diluted weighted average common shares outstanding	44,475,201			40,707,957			12,463,751

Basic net loss per share	$	(0.31	)	$	(0.60	)	$	(1.63	)
Diluted net loss per share	$	(0.31	)	$	(0.60	)	$	(1.63	)

Stock options, restricted stock units and the convertible note payable, which could be potentially dilutive in future periods, were not included in the computation of diluted net income per share because the effect would have been anti-dilutive for the periods reflected in the table above.

12. LONG-TERM DEBT

As of January 31, 2013 and 2012, respectively, the Company’s long-term debt consisted of the following:

	2013	2012
Credit Facility	25,000,000	—
5% Convertible Note	123,022,969	—
Total long-term debt	148,022,969	—
Less: Current portion of long-term debt	—	—
Total long-term debt, net of current portion	148,022,969	—

Credit Facility

On April 12, 2012, TUSA entered into a Credit Agreement (the “Credit Facility”) with Wells Fargo Bank, National Association, as administrative agent and issuing lender and with other banks and financial institutions party thereto, as co-lenders. The maximum credit available under the Credit Facility was $300 million. As of January 31, 2013, the Credit Facility had a borrowing base of $75 million. As of January 31, 2013, TUSA, as borrower, had $25 million outstanding under the Credit Facility.

The Credit Facility is secured by (1) certain of TUSA’s assets, including (i) at least 85% of the adjusted engineered value of TUSA’s proved oil and natural gas interests evaluated in determining the borrowing base for the revolving Credit Facility, and (ii) all of the personal property of TUSA and its subsidiaries, and (2) a pledge by Triangle of the equity interests it holds in TUSA. The obligations under the Credit Facility were guaranteed by each of Triangle and a domestic subsidiary of TUSA.

Borrowings under the Credit Facility bear interest, at TUSA’s option, at either (i) the Adjusted Base Rate (the highest of (A) the Administrative Agent’s prime rate, (B) the federal funds rate plus 0.5%, and (C) the Eurodollar Rate (as defined in the Credit Facility) plus 1%), plus an applicable margin that ranges between 0.75% and 1.75%, depending on TUSA’s utilization percentage of the then effective borrowing base or (ii) the Eurodollar Rate plus an applicable margin that ranges between 1.75% and 2.75%, depending on the utilization percentage of the then effective borrowing base. Additionally, the Credit Facility provides for a commitment fee of 0.375% to 0.50%, depending on borrowing base usage.

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The Credit Facility contains representations, warranties and covenants that are customary for similar credit arrangements, including, among other things, covenants relating to (i) financial reporting and notification, (ii) payment of obligations, (iii) compliance with applicable laws and (iv) notification of certain events. The Credit Facility also contains various covenants and restrictive provisions which may, among other things, limit TUSA’s ability to sell assets, incur additional indebtedness, make investments or loans and create liens.

The Credit Facility contains financial covenants requiring TUSA to comply with the following: (i) TUSA must maintain a ratio of consolidated current assets (as defined in the Credit Facility) to consolidated current liabilities (as defined in the Credit Facility) of at least 1.0 to 1.0; and (ii) the ratio of TUSA’s consolidated debt to consolidated EBITDAX (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) may not be greater than 4.0 to 1.0. As of January 31, 2013, TUSA was in compliance with all financial covenants under the Credit Facility.

Convertible Note

On July 31, 2012, pursuant to a Note Purchase Agreement between the Company and NGP Triangle Holdings, LLC (“NGP”), the Company sold to NGP a convertible promissory note with an initial principal amount of $120,000,000 (the “Convertible Note”), which is also the purchase price for the Convertible Note. Pursuant to the Note Purchase Agreement, the Company also entered into an Investment Agreement (the “Investment Agreement”) and a Registration Rights Agreement (the “Registration Rights Agreement”) with NGP.

The Convertible Note is convertible into shares (the “Conversion Shares”) of the Company’s common stock, at an initial conversion price of $8.00 per share. The Convertible Note accrues interest at a rate of 5.0% per annum, compounded quarterly, to be paid on each December 31, March 31, June 30 and September 30, and on the date of any redemption, conversion or exchange of the Convertible Note. Such interest payments will be paid-in-kind by adding to the principal balance of the Convertible Note, provided that, following the fifth anniversary of closing, the Company has the option to make such interest payments in cash.

The Convertible Note does not have a stated maturity. Following the fifth anniversary of the closing, if the price of the Company’ common stock exceeds $11.00 per share and certain trading volume requirements are met, the Company can elect to redeem all (but not less than all) of the Convertible Note at a price equal to the outstanding principal amount plus accrued and unpaid interest, payable, at the Company’s option, in cash or common stock. Following the eighth anniversary of the closing, the Company can elect to redeem all (but not less than all) of the Convertible Note at a price equal to the principal plus accrued and unpaid interest, payable in cash. Further, following either the tenth anniversary of the closing or a change of control of the Company, the holders of the Convertible Note will have the right to require the Company to redeem the Convertible Note at a price equal to the principal amount plus accrued and unpaid interest, with an additional make-whole payment for scheduled interest payments remaining if such right is exercised prior to the fifth anniversary of closing.

So long as not less than 50% of the initial aggregate principal amount of the Convertible Note is outstanding and held by NGP, the Company has agreed to obtain the prior written consent of NGP before submitting certain resolutions or matters to a vote of the holders of common stock for approval or to require the approval of such holders of common stock as would be required to approve such resolution or matter if all then-outstanding Convertible Note(s) held by NGP had been converted into Conversion Shares immediately prior to the record date for such meeting of stockholders and NGP had voted all of such Conversion Shares against such resolution or matter. The foregoing will not apply to stockholder-initiated proposals required to be submitted to the stockholders of the Company by federal law or pursuant to the bylaws of the Company or to proposals regarding the election or removal of directors of the Company, the ratification of the appointment of independent auditors, matters required to comply with terms of the Convertible Note or advisory votes required to be submitted to the stockholders of the Company by federal law.

The Convertible Note includes customary events of default (each an “Event of Default”), including, among other things, payment defaults, covenant breaches, insolvency, certain events of bankruptcy, liquidation and material judgments. If any such Event of Default occurs, the Company must pay interest on the principal amount and any other amounts then past due from time to time outstanding under the Convertible Note at a default interest rate of 11%.

The Convertible Note contains transfer restrictions prohibiting NGP from transferring the Convertible Note to any transferee other than an affiliate of NGP without the prior written consent of the Company (which consent shall not be unreasonably withheld following the fifth anniversary of the closing).

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Total interest expense related to the Convertible Note was $3,023,000 for the fiscal year ended January 31, 2013.

Investment Agreement

Pursuant to the Investment Agreement, NGP is entitled to designate one director to the Board of Directors of the Company (the “Board”) until such time as NGP (1) ceases to hold at least the lesser of (i) 50% of the shares of common stock that would have been be issuable to NGP upon conversion of the Convertible Note on the original issuance date of the Convertible Note (without taking into account any shares of Common Stock acquired by NGP other than through conversion of the Convertible Note), and (ii) 10% of the then-outstanding shares of Common Stock (without taking into account any shares of Common Stock acquired by the Purchase other than through conversion of the Convertible Note and pursuant to its preemptive rights under the Investment Agreement), or (2) is in material breach of its standstill obligations or anti-hedging covenant (each, a “Termination Event”).

The Investment Agreement grants NGP the right to purchase its pro-rata share on an as-converted basis of any future equity offerings by the Company until such time as a Termination Event occurs. Such rights are subject to customary exclusions such as securities offered in connection with employee benefits plans, business combinations, pro-rata distributions, and stockholder rights plans.

The Investment Agreement further provides that, for so long as at least 50% of the Convertible Note originally issued is outstanding and held by NGP, the Company shall not take certain actions without the prior written consent of NGP, as follows:

· Enter into affiliate transactions, subject to certain exceptions;

· effect any amendment, modification or restatement of Company’s articles of incorporation or bylaws in any manner that could reasonably be expected to be materially adverse to NGP;

· make any dividend or distribution in respect of, or redeem or repurchase, any equity securities of the Company;

· issue any equity securities that are senior to the common stock or any debt securities that are convertible into equity securities that are senior to the common stock;

· incur any indebtedness (other than pursuant to the Company’s senior credit facility or the terms of the Convertible Note) unless the Consolidated Leverage Ratio (as defined in the Investment Agreement) does not exceed 5.0 to 1.0 and no Event of Default (as defined in the Convertible Note) would result.

NGP and its parent, NGP Natural Resources X, L.P., are subject to certain customary “standstill” provisions that limit their ability to acquire additional shares of common stock, solicit proxies or take certain other actions towards influencing or controlling the Company. The standstill provisions of the Investment Agreement survive until the later to occur of (1) the third anniversary of the closing and (2) such time as NGP ceases to own at least 10% of the Company’s outstanding common stock (assuming full conversion of the outstanding Convertible Note).

In connection with a private placement of 9,300,000 shares of the Company’s common stock to two affiliates of NGP in March 2013, Triangle and NGP entered into an amendment to the Investment Agreement. The amendment modified the definition of Termination Event to provide that the shares of Common Stock issued in the private placement will be included in calculating whether NGP holds 10% of the then-outstanding shares of common stock.

Registration Rights Agreement

Pursuant to the Registration Rights Agreement, NGP is entitled to certain demand registration rights and unlimited piggyback registration rights under the Securities Act of 1933, as amended, for the shares of common stock into which the Convertible Note is convertible. Also in connection with the March 2013 private placement to affiliates of NGP, the Registration Rights Agreement was amended and restated to specify that the shares sold in the private placement would also be subject to the registration rights thereunder.

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13. COMMODITY DERIVATIVE INSTRUMENTS

Through TUSA, the Company has entered into commodity derivative instruments, as described below. The Company has utilized single-day puts and costless collars to reduce the effect of price changes on a portion of our future oil production. A collar requires us to pay the counterparty if the settlement price is above the ceiling price and requires the counterparty to pay us if the settlement price is below the floor price. The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and natural gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with one counterparty. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the same underlier with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the derivative activities line on the consolidated statement of operations. The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.

The Company’s commodity derivative contracts as of January 31, 2013 are summarized below:

Contract Type	Counterparty	Basis (1)	Quantity	Strike Price ($/Bbl)	Term or End Date
Collar	Wells Fargo Bank, N.A.	NYMEX	500 bopd	$85.00 / $104.30	February 1, 2013 - December 31, 2013
Collar	Wells Fargo Bank, N.A.	NYMEX	500 bopd	$85.00 / $100.50	January 4, 2013 - December 31, 2013
Collar	Wells Fargo Bank, N.A.	NYMEX	250 bopd	$90.00 / $101.50	February 1, 2013 - December 31, 2013
Collar	Wells Fargo Bank, N.A.	NYMEX	250 bopd	$85.00 / $99.50	January 1, 2014 - December 31, 2014
Collar	Wells Fargo Bank, N.A.	NYMEX	500 bopd	$80.00 / $101.20	January 1, 2014 - December 31, 2014
Put	Wells Fargo Bank, N.A.	NYMEX	200,000 bbl	$75.00	June 17, 2013
Put	Wells Fargo Bank, N.A.	NYMEX	100,000 bbl	$75.00	June 17, 2013
Put	Wells Fargo Bank, N.A.	NYMEX	100,000 bbl	$75.00	June 17, 2013
Put	Wells Fargo Bank, N.A.	NYMEX	300,000 bbl	$75.00	December 16, 2013
Put	Wells Fargo Bank, N.A.	NYMEX	100,000 bbl	$75.00	December 16, 2013
Put	Wells Fargo Bank, N.A.	NYMEX	100,000 bbl	$75.00	December 16, 2013

(1) NYMEX refers to quoted prices on the New York Mercantile Exchange

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The following table details the fair value of the derivatives recorded in the applicable consolidated balance sheets, by category:

Underlying Commodity	Location on Consolidated Balance Sheet	As of January 31, 2013		As of January 31, 2012
Crude oil derivative contract	Current assets	$	602,489	$	—

Crude oil derivative contract	Long-term liabilities	$	291,680	$	—

The amount of income recognized related to the Company’s derivative financial instruments was as follows:

	As of January 31,
	2013			2012		2011
Unrealized gain (loss) on derivative contracts	$	(3,578,191	)	$	—	$	—
Realized gain (loss) on derivative contracts	8,040			—		—
	$	(3,570,151	)	$	—	$	—

Unrealized gains and losses resulting from derivatives are recorded at fair value on the consolidated balance sheets and changes in fair value are recognized on the consolidated statements of operations and comprehensive loss. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the derivative activities line on the consolidated statements of operations.

14. INVESTMENT IN MARKETABLE SECURITIES

On January 9, 2013, Triangle USA Petroleum Corporation entered into an agreement with Emerald Oil, Inc. (“Emerald”) to sell oil and natural gas leases (1,590 acres) to Emerald for consideration of 120 acres and shares of Emerald common stock (ticker symbol: EOX). Upon closing, this resulted in TUSA receiving 851,315 shares of Emerald stock in addition to the oil and natural gas leases. The shares were valued on the closing date and recorded at an initial value of $4,861,009.

The Company’s marketable securities are classified as available-for-sale securities and are included as a current asset in the consolidated balance sheets. We have elected the fair value option for this investment in equity securities and are therefore recording the change in fair value during the period in the statement of operations. The cost basis of the Company’s available-for-sale securities as of January 31, 2013 was $4.9 million. We recorded an unrealized gain of $204,000 for fiscal year 2013 which was included in other income (loss) on the Consolidated Statements of Operations and Comprehensive Loss for fiscal year 2013.

15. FAIR VALUE MEASUREMENTS

ASC Topic 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

· Level 1: Quoted prices are available in active markets for identical assets or liabilities;

· Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;

· Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

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The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no significant assets or liabilities that were measured at fair value on a non-recurring basis in periods after initial recognition.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of January 31, 2013 by level within the fair value hierarchy:

	Level 1		Level 2		Level 3		Total
Assets:
Investment in marketable securities	$	5,065,324	$	—	$	—	$	5,065,324
Derivative assets	$	—	$	602,489	$	—	$	602,489

Liabilities:
Derivative liabilities	$	—	$	291,680	$	—	$	291,680

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third-parties, the credit rating of each counterparty, and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At January 31, 2013, derivative instruments utilized by the Company consist of both costless collars and single-day puts. The crude oil derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

The carrying value of the Company’s credit facility of $25,000,000 approximated fair value as it bears interest at variable rates over the term of the loan which are based on quoted prices in active markets (Level 2).

The Convertible Note (carried at $123,022,969 at January 31, 2013) has an estimated fair value at January 31, 2013 of $132,900,000, based on discounted cash flow analysis and option pricing (Level 3). The excess of fair value over carrying value is largely due to an increase in option value for Triangle common stock’s closing price being $6.29/share at January 31, 2013 compared with $5.59/share when the Convertible Note was issued on July 31, 2012.

The following table presents the rollforward of Level 3 financial liabilities:

Beginning balance, February 1, 2011	$	—
Total net unrealized gain (loss)	—
Ending balance, January 31, 2012	$	—
Sale of Convertible Notes	120,000,000
Interest paid in-kind	3,022,969
Total net unrecognized loss	9,877,031
Ending balance, January 31, 2013	$	132,900,000

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16. SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

	For the Years Ended January 31,
	2013		2012		2011
Cash paid during the period for:
Interest expense	$	75,214	$	—	$	—
Interest paid in-kind (including capitalized amounts)	$	3,022,969	$	—	$	—

Non-cash investing activities:
Additions to oil and natural gas properties through:
Increased accrued liabilities and decreased prepaid well costs	$	36,653,755	$	13,180,627	$	2,076,609
Capitalized stock based compensation	$	949,305	$	—	$	—
Issuance of common stock	$	1,203,748	$	11,780,344	$	—
Change in asset retirement obligations	$	1,869,037	$	52,668	$	—
Purchase minority interest In RockPile	$	12,349,290	—		—

17. RELATED PARTY TRANSACTIONS

On October 1, 2012, TUSA entered into two midstream services agreements with Caliber North Dakota LLC (a wholly-owned subsidiary of Caliber): one for crude oil gathering, stabilization, treating and redelivery and one for (i) natural gas compression, gathering, dehydration, processing and redelivery; (ii) produced water transportation and disposal services; and (iii) fresh water transportation for TUSA’s oil and natural gas drilling and production operations. Under the agreements, TUSA committed to deliver minimum monthly revenues derived from the fees paid by TUSA to Caliber for volumes of oil, natural gas, produced water, and fresh water for a primary term of 15 years beginning on the in-service date of the Caliber facilities (the date on which the Caliber central facility has been substantially completed and has commenced commercial operation, estimated to occur between July 31, 2013 and September 1, 2013. As of January 31, 2013, no significant services had been provided to TUSA by Caliber.

On October 1, 2012, Triangle entered into a Services Agreement with Caliber GP and Caliber to provide administrative services to Caliber necessary to operate, manage, maintain and report the operating results of Caliber’s gathering pipelines, transportation pipelines, related equipment and other assets of Caliber.

RockPile is a provider of hydraulic pressure pumping and complementary well completion services to TUSA. All revenue and cost of goods sold associated with work on Triangle wells is eliminated in consolidation. See Note 4 — Segment Reporting for further discussion of the RockPile elimination.

Except for the items listed in the preceding paragraphs, the Company had no reportable related party transactions in fiscal years 2013, 2012 and 2011.

18. BENEFIT PLANS

In fiscal year 2013 RockPile established a 401(k) plan for the benefit of its employees. Eligible employees may make voluntary contributions not exceeding statutory limitations to the plan. The Company does not match employee contributions.

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19. COMMITMENTS AND CONTINGENCIES

The Company leases office facilities in Denver, Colorado and Calgary, Alberta, Canada under operating lease agreements that expire in September 2017, July 2014 and September 2013. Rent expense was $508,645, $200,199 and $94,351 for the years ended January 31, 2013, 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
2014	$	371,953
2015	$	325,596
2016	$	331,663
2017	$	337,730
2018	$	113,251

As of January 31, 2013 the Company was subject to commitments on two drilling rig contracts. The contracts expire in September 2013 and March 2013. In the event of early termination of the contracts, the Company would be obligated to pay an aggregate amount of approximately $5.6412 million as of January 31, 2013 as required under the terms of the contracts.

On October 1, 2012, TUSA entered into two midstream services agreements with Caliber North Dakota LLC, one for crude oil gathering, stabilization, treating and redelivery and one for (i) natural gas compression, gathering, dehydration, processing and redelivery; (ii) produced water transportation and disposal services; and (iii) fresh water transportation for TUSA’s oil and natural gas drilling and production operations. Under the agreements, TUSA committed to deliver minimum monthly revenues derived from the fees paid by TUSA to Caliber for volumes of oil, natural gas, produced water, and fresh water for a primary term of 15 years beginning on the in-service date of the Caliber facilities (the date on which the Caliber central facility has been substantially completed and has commenced commercial operation, estimated to occur between July 31, 2013 and September 1, 2013). The total revenue commitment over the 15 year term is $337,128,710, received interchangeably across all four classes of service. As of January 31, 2013, no significant services had been provided to TUSA by Caliber.

The Company also entered into an agreement with an outside party for fresh water supply beginning in November 2012. The Company will pay $60,760 per month through April 2013 and $173,508 per month from May 2013 through October 2014.

As of January 31, 2013, RockPile had various commitments for future expenditures relating to (i) leases of land, rail spur, rail cars and tractor trailer units, (ii) transloading services and track rental and (iii) an agreement relating to the use of technology and equipment for transportation, transloading and storage of bulk commodities. The commitments by fiscal year are as follows:

Fiscal year ending January 31,	Annual rental amount
2014	$	2,417,972
2015	$	2,006,492
2016	$	578,633
2017	$	188,627
2018	$	194,285
Thereafter	$	855,469

At January 31, 2013, there were no known environmental or other regulatory matters related to the Company’s operations that were reasonably expected to result in a material liability other than asset retirement obligations which are reflected on the consolidated balance sheet. Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on the Company’s financial position, results of operations or cash flows.

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20. SUBSEQUENT EVENTS

We have evaluated subsequent events and are not aware of any significant events that occurred subsequent to January 31, 2013 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, except as discussed below.

NGP Common Stock Purchase

On March 8, 2013, the Company sold to two affiliates of NGP, 9,300,000 shares of common stock of the Company in a private placement at $6.00 per share for aggregate consideration of $55.8 million.

RockPile Credit Facility

On February 25, 2013, RockPile, entered into a Credit and Security Agreement (the “Credit Agreement”) by and between RockPile, as borrower, and Wells Fargo Bank, National Association, as lender (the “Lender”). The Credit Agreement provides for a $7,500,000 revolving loan facility, a $10,500,000 equipment term loan facility and a $2,000,000 capex term loan facility. Borrowings under the Credit Agreement are available to: (i) provide for the working capital and general corporate requirements of RockPile, (ii) purchase equipment, (iii) pay any fees and expenses in connection with the Credit Agreement, and (iv) support letters of credit. As of February 25, 2013, the full $10,500,000 of the term loan was drawn and was outstanding, and there were no revolving borrowings, letters of credit, or capex term loans outstanding under the Credit Agreement. The maturity date of the Credit Agreement is February 25, 2016, unless sooner terminated as provided in the Credit Agreement.

The borrowings under the Credit Agreement are also guaranteed by the Company and each subsidiary of RockPile, provided that the Lender will consider releasing the guaranty of the Company upon receipt and review of RockPile’s audited financial statements for the fiscal year ending January 31, 2014. If the Lender chooses not to release the Company’s guaranty within 30 days following receipt of RockPile’s audited financial statements for the fiscal year ending January 31, 2014, RockPile will have no obligation to pay a termination fee should it opt to refinance with another lender or otherwise prepay and terminate the Credit Agreement. Borrowings under the Credit Agreement are secured by certain of RockPile’s assets, including all of its equipment and other personal property of RockPile but excluding any owned real property. In addition, the subsidiary guarantors (and not the Company) pledged certain of their assets to secure their obligations under the guaranty.

The Credit Agreement contains standard representations, warranties and covenants for a transaction of its nature, including, among other things, covenants relating to (i) financial reporting and notification, (ii) payment of obligations, (iii) compliance with applicable laws, and (iv) notification of certain events. The Credit Agreement also contains various covenants and restrictive provisions which may, among other things, limit RockPile’s ability to sell assets, incur additional indebtedness, make investments or loans, and create liens.

Upon an event of default under the Credit Agreement, the Lender may terminate the commitments under the Credit Agreement and declare all amounts owing under the Credit Agreement to be due and payable. In addition, upon an event of default under the Credit Agreement, the Lender is empowered to exercise all rights and remedies of a secured party and foreclose upon the collateral securing the Credit Agreement, in addition to all other rights and remedies under the security documents described in the Credit Agreement.

RockPile Borrowing

On February 15, 2013, RockPile entered into two loan agreements with Dacotah Bank in the amounts of $2,576,000 for construction financing of its residential units in Dickinson, ND and $3,300,000 for construction financing of its administrative and maintenance facility in Dickinson, ND. The loans have a fixed interest rate of 4.75% and a maturity date of December 31, 2013. Payments on the loans are interest only. RockPile intends to obtain new mortgages on the properties prior to the maturity date of the loans. The construction mortgages are guaranteed by Triangle.

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TUSA Amended and Restated Credit Facility

On April 11, 2013, TUSA’s credit facility was amended and restated to, among other things, increase the maximum credit availability to $500 million, and the facility’s borrowing base was increased to $110 million.

Drilling Rig Contract

Subsequent to January 31, 2013, the Company entered in two drilling rig contracts. The first of these contracts has a one year term and is expected to expire in April 2014. In the event of early termination of the contract, the Company would be obligated to pay an aggregate amount of approximately $6,753,000 as required under the terms of the contract. The second contract is a “well-to-well” contract with no early termination penalty.

21. MAJOR CUSTOMERS

Oil and Natural Gas Customers

In the U.S., sales of produced crude oil, natural gas and natural gas liquids are not regulated and are made at negotiated prices. Of our $39.6 million in revenues from oil and gas sales in fiscal year 2013, $38.5 million is revenue from the sales of crude oil, and of that approximately $20.0 million is our share of revenue from sales of crude oil from the 16 wells for which we were the well operator in fiscal year 2013.

In fiscal year 2013, we made oil sales directly to two oil purchasers and oil and natural gas sales through three well operators where for each of those five parties, sales exceeded 10% of our total oil and natural gas revenue for fiscal year 2013. These two purchasers and three operators accounted for approximately 23%, 20%, 16%, 13% and 12%, respectively, of our total oil and natural gas sales for fiscal year 2013. Although a substantial portion of our production is purchased by, or through, these parties, we do not believe the loss of any one customer would have a material adverse effect on our business as other customers should be accessible to us. We regularly monitor the credit worthiness of customers and may require parental guarantees, letters of credit or prepayments when deemed necessary.

Pressure Pumping Customers

RockPile’s principal customers consist of independent oil and natural gas producing companies needing completion of horizontal wells in western North Dakota and eastern Montana. Since commencing operations in July 2012 and through January 31, 2013, RockPile provided pressure pumping services for twelve of the sixteen wells operated by TUSA and for five wells operated by three third parties.

22. 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 natural gas exploration

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and production activities in the United States for the periods indicated. 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,
	2013			2012			2011
Oil and natural gas revenues from production (all sold to unaffiliated parties)	$	39,614,211		$	8,135,972		$	563,670
Less operating costs and income taxes:
Production taxes	(4,492,836		)	(896,062		)	(94,654		)
Other lease operating expenses	(3,619,943		)	(922,750		)	(45,231		)
Impairment of oil and natural gas properties	—			(6,000,000		)	—
Amortization of oil and natural gas properties	(13,548,000		)	(3,022,000		)	(96,000		)
Accretion of asset retirement obligation	(21,119		)	(6,950		)	(5,148		)
Operating income before income tax expense	17,932,313			(2,711,790		)	322,637
Less income tax expense at statutory rates	(6,696,822		)	1,012,718			(120,489		)
Results of oil and natural gas operations (excluding general corporate overhead and interest expense)	$	11,235,491		$	(1,699,072	)	$	202,148
Amortization rate per Boe	$	27.75		$	31.85		$	9.48
Lease Operating Expenses (per Boe)	$	7.11		$	9.50		$	3.03
Gathering, Transportation and Processing (per Boe)	$	0.31		$	0.23		$	1.44

Oil and Natural 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.

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The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the three-year period ended January 31, 2013. Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”) an independent petroleum engineering firm, audited our estimate of proved oil and natural gas reserves as of January 31, 2013 and our determination of 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, 2013. 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 PV-10 Value at January 31, 2012. 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.

	Crude Oil		Natual Gas
	(Mbbls)		(MMcf)
Total proved reserves at January 31, 2010	—		—
Revisions of previous estimates	—		—
Purchase of reserves	—		—
Extensions, discoveries and other additions	1,240		—
Sale of reserves	—		—
Production	(4	)	—
Total proved reserves at January 31, 2011	1,236		—
Revisions of previous estimates	(932	)
Purchase of reserves
Extensions, discoveries and other additions	1,154		686
Sale of reserves
Production	(93	)	(12	)
Total proved reserves at January 31, 2012	1,365		674
Revisions of previous estimates	665		1,832
Purchase of reserves	230		181
Extensions, discoveries and other additions	10,960		10,251
Sale of reserves	(229	)	(165	)
Production	(452	)	(188	)
Total proved reserves at January 31, 2013	12,539		12,585

Proved Developed Reserves included above:
January 31, 2010	—		—
January 31, 2011	215		—
January 31, 2012	538		202
January 31, 2013	4,985		5,906

Proved Undeveloped Reserves included above:
January 31, 2010	—		—
January 31, 2011	1,021		—
January 31, 2012	827		472
January 31, 2013	7,555		6,679

Extensions and Discoveries in Fiscal Year 2013

The 11.0 million barrels of oil and 10.3 bcf of natural gas of proved reserves added by extensions and discoveries in North Dakota are primarily due to our increased completion of wells, particularly operated wells, and other parties completing wells offsetting our properties. In fiscal year 2013, we participated in 71 gross (11.3 net) productive wells completed, and we added 57 gross (18.8 net) new proved undeveloped well locations discussed later in this Note.

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Revisions in Fiscal Year 2013

The 664,508 barrels (49%) upward revision in crude oil proved reserves was due to longer production histories that favorably supported the significant increase in proved oil reserves. At the beginning of fiscal year 2013, all of our oil production was from wells operated by third parties. The majority of those wells in which we had significant interests had only a few months production history at the start of fiscal year 2013, with some of those wells having erratic production in the first few months. Consequently at the beginning of fiscal year 2013, our reserve estimator (Ryder Scott & Company) had limited information from which to estimate with reasonable certainty our proved producing reserves as well as proved undeveloped reserves for planned wells offsetting productive wells.

The 1.8 bcf upward revision on natural gas proved reserves was due to both (i) more favorable oil and natural gas production history and (ii) more wells connected to natural gas pipelines and sales of natural gas. Fiscal year 2013 sales of natural gas were 188 Mmcf, compared with 12 Mmcf in fiscal year 2012.

Purchases of Proved Properties in Fiscal Year 2013

The proved reserve additions in fiscal year 2013 for property purchases were primarily acquisitions of additional interests in two proved undeveloped locations. Such acquisitions include cases of trades where we received additional interests in drill spacing units in exchange for interests we had in other drill spacing units.

Sales in Fiscal Year 2013 of Properties Having Proved Reserves

The fiscal year 2013 sales of properties having proved reserves were primarily trades where we traded away lease rights in small portions of proved undeveloped well spacing units in exchange for third-party lease rights we desired in other well spacing units.

At January 31, 2013, we had proved undeveloped oil and natural gas reserves of 8,667 Mboe, up 7,762 Mboe from 905 Mboe at January 31, 2012. Changes in our proved undeveloped reserves are summarized in the following table:

	(Mboe)		Gross Wells		Net Wells
Proved Undeveloped Reserves at January 31, 2010	—		—		—
Net revisions	—		—		—
Became developed reserves in fiscal year 2011	—		—		—
Acquisitions	—		—		—
Extensions and discoveries of proved reserves	1,021.3		19.00		3.03
Proved Undeveloped Reserves at January 31, 2011	1,021.3		19.00		3.03
Net revisions	(819.0	)	(13.00	)	(2.46	)
Became developed reserves in fiscal year 2012	(52.9	)	(3.00	)	(0.12	)
Acquisitions	—		—		—
Extensions and discoveries of proved reserves	755.1		14.00		2.15
Proved Undeveloped Reserves at January 31, 2012	904.5		17.00		2.60
Became developed reserves in fiscal year 2013	(362.9	)	(9.0	)	(1.2	)
Traded for net acres in other drill spacing units	(256.3	)	(5.0	)	(0.7	)
Negative revisions	(35.6	)	(1.0	)	(0.1	)
Positive revisions	101.4		0.0		0.0
Acquisition of additional interests in PUD location	171.7		0.0		0.3
Additional proved undeveloped locations	8,144.2		57.0		18.9
Proved Undeveloped Reserves at January 31, 2013	8,667.0		59.0		19.8

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Additions in fiscal year 2013 to proved undeveloped reserves are for 57 drilling locations, whose status is summarized in the following table:

		Development
	PUD	Wells
	Locations	Gross	Net
Proved undeveloped locations:
For which Triangle operated wells are to be drilled and completed by June 30, 2017	34	34	16.83
For which non-operated wells were in-progress at January 31, 2013 and are expected to be completed in fiscal year 2014	17	17	1.22
That are proposed non-operated wells with drilling permits	3	3	0.32
That are non-operated wells to be drilled by 01/31/2015	3	3	0.48
Total	57	57	18.85

Standardized Measure of Discounted Future Net Cash Flows

Authoritative accounting guidance by the FASB requires the Company to calculate and disclose for January 31, 2013 and 2012 (i) a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves (“Standardized Measure”) and (ii) changes in the Standardized Measure for fiscal years 2013 and 2012. 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 natural gas properties and (ii) net operating loss carryforwards relating to our oil and natural 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,
	2013		2012		2011
Oil per Bbl	$	84.76	$	89.71	$	68.76

Natural Gas per Mcf	$	5.23	$	8.19	N/A

Most of our natural gas sales in fiscal year 2013 and 2012 were for ‘wet’ natural gas sold before processing to extract natural gas liquids from the wet natural gas.

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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)	2013			2012			2011
Future cash inflows	$	1,128,676		$	127,955		$	84,954
Future costs:
Production	(333,185		)	(48,919		)	(19,054		)
Development	(199,173		)	(23,362		)	(20,003		)
Future income tax expense	(87,313		)	—			(2,627		)
Future net cash flows	509,005			55,674			43,270
10% discount factor	(297,653		)	(26,246		)	(30,403		)
Standardized measure of discounted future net cash flows relating to proved reserves	$	211,352		$	29,428		$	12,867

The $199 million in estimated future development costs at January 31, 2013 includes $3,574,000 of estimated future net costs (at current cost rates), net of estimated equipment salvage value, for site restoration and well plugging upon the abandonment of the wells. The $3,574,000 in costs decreased the Standardize Measure by $34,026. For the Standardized Measure at January 31, 2012 and 2011, the estimated future costs (net of estimated equipment salvage value) for site restoration and plugging of wells was zero.

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

	January 31,
(Amounts in thousands)	2013			2012			2011
Standardized measure, beginning of period	$	29,428		$	12,866		$	—
Extensions and discoveries, net of future production and development costs	193,107			28,414			18,959
Sales, net of production costs	(31,502		)	(5,677		)	—
Previously estimated development costs incurred during the period	10,368			2,084
Revision of quantity estimates	15,910			(9,536		)
Net change in prices, net of production costs	2,779			1,001			(68		)
Acquisition of reserves	2,119			—			—
Divestiture of reserves	(3,273		)	—			—
Accretion of discount	2,943			1,316			—
Changes in future development costs	801			(494		)	(5,735		)
Change in income taxes	(13,509		)	290			(291		)
Change in production timing and other	2,181			(837		)	1
Standardized measure, end of period	$	211,352		$	29,428		$	12,866

We calculate the projected income tax effect using the “year-by-year” method for purposes of the supplemental oil and natural 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 limits total capitalized costs for oil and natural gas properties (net of accumulated DD&A and deferred income taxes) to no more than the sum of (i) the present value discounted at 10% of estimated future net cash flows from proved reserves, (ii) the cost of properties not being amortized, (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized and (iv) all related tax effects.

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23. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The Company’s quarterly financial information for fiscal years 2013 and 2012 is as follows (in thousands):

	For the Year Ended January 31, 2013
	First Quarter*			Second Quarter**			Third Quarter			Fourth Quarter
Total revenue	$	5,241		$	10,132		$	21,300		$	24,028
Loss from operations	$	(3,336	)	$	(1,389	)	$	(617	)	$	(2,828	)
Net loss	$	(3,324	)	$	(1,335	)	$	(672	)	$	(9,153	)
Net loss attributable to common stockholders	$	(3,028	)	$	(1,079	)	$	(598	)	$	(9,055	)
Net loss per common share -basic and diluted	$	(0.07	)	$	(0.02	)	$	(0.01	)	$	(0.20	)

	For the Year Ended January 31, 2012
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Total revenue	$	513		$	625		$	3,462		$	3,535
Loss from operations	$	(967	)	$	(6,427	)	$	(2,242	)	$	(15,339	)
Net loss	$	(8,718	)	(6,328		)	(2,139		)	(7,238		)
Net loss attributable to common stockholders	$	(872	)	$	(6,328	)	$	(2,110	)	$	(14,968	)
Net loss per common share -basic and diluted	$	(0.03	)	$	(0.15	)	$	(0.05	)	$	(0.56	)

* In July 2012, RockPile changed its year-end from December 31 to January 31. Triangle’s consolidated results reported above reflect that change in year-end, whereas the consolidated results reported in Triangle’s April 30, 2012 Quarterly Report filed on Form 10-Q did not reflect such change in year-end. Consequently, the above revenue and loss amounts for the first quarter of fiscal year 2013 vary slightly (by less than 2%) of the corresponding amounts reported in Triangle’s April 30, 2012 Quarterly Report on Form 10-Q.

**For the second quarter of fiscal year 2013, the amounts shown above reflect a $126,135 reduction in other revenue, recorded in the fourth quarter of fiscal year 2013. The revenue reduction was to capitalize miscellaneous second quarter service income billed to third-parties that must be credited to our well costs under Full Cost accounting rules. (See Note 4-Segment Reporting.)

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

1. 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, 2013, that disclosure controls and procedures were not effective in providing reasonable assurance that material information is made known to them by others within the Company.

2a. 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, 2013. 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.

2b. Material Weakness in Accounting for Consolidated Pressure Pumping Income

On April 17, 2013, Triangle’s Board approved the Audit Committee’s and management’s recommendation that Triangle file an Amendment No. 1 on Form 10-Q/A (the “Amendment”) to amend and restate its Quarterly Report on Form 10-Q for the three months ended October 31, 2012, which was filed with the SEC on December 10, 2012. The Amendment includes an error correction that eliminates $1.8 million of previously recognized pressure pumping income, pursuant to recognition exception rules set forth in subsection (6)(iv) of the SEC’s Full Cost

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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, 2013, 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.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. A material weakness related to ineffective controls related to the identification of proper accounting of contractual service income that resulted in a restatement of the Company’s unaudited interim financial statements for the three months ended October 31, 2012 has been identified and included in management’s assessment in Item 9A.2. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets as of January 31, 2013 and 2012, and the related consolidated statements of operations and comprehensive loss, cash flows, and stockholders’ equity for the years then ended of Triangle Petroleum Corporation and subsidiaries. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2013 consolidated financial statements, and this report does not affect our report dated April 30, 2013, which expressed an unqualified opinion on those consolidated financial statements.

In our opinion, because of the effect of the aforementioned material weakness on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of January 31, 2013, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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ITEM 9B. OTHER INFORMATION

Concurrently with the filing of this annual report, the Company entered into an Employment Agreement (the “Employment Agreement”) with Justin Bliffen, the Company’s Chief Financial Officer. The Employment Agreement provides for an annual salary to Mr. Bliffen of not less than $250,000. Upon signing the Employment Agreement, the Company granted Mr. Bliffen an initial signing grant of 250,000 restricted stock units vesting ratably on each of the first five anniversaries of the date of the agreement. In addition, Mr. Bliffen is eligible to receive an annual bonus (the “Bliffen STI Award”), as determined by the Compensation Committee of the Board of Directors. Additionally, he is entitled to participate in any and all benefit plans in effect for executives from time to time, along with vacation, sick and holiday pay in accordance with our policies established and in effect from time to time. In the event that Mr. Bliffen’s employment is terminated by us without cause, he is entitled to the continuation of payment of annual salary for six months and benefits for a six-month period. In the event that Mr. Bliffen’s employment is terminated by us after a Change of Control (as defined in the agreement), he is entitled to a lump sum cash payment of one times his annual salary, any unpaid Bliffen STI Award, the target Bliffen STI Award for the year in which termination occurs (pro-rated for the period worked prior to the termination), benefits for a 12-month period, and the immediate vesting of all outstanding equity incentive awards. Payment of severance benefits may be conditioned upon Mr. Bliffen’s execution of a release of claims against us.

The above summary is qualified in its entirety by reference to the Employment Agreement, a copy of which is attached as Exhibit 10.7 to this Annual Report on Form 10.K and incorporated herein by reference.

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 2013 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than May 31, 2013.

ITEM 11. EXECUTIVE COMPENSATION

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Exhibit No.		Description

2.1		Agreement and Plan of Merger, dated November 29, 2012, filed as Exhibit 2.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2012 and incorporated herein by reference.

3.1		Certificate of Incorporation of Triangle Petroleum Corporation, filed as Exhibit 3.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2012 and incorporated herein by reference.

3.2		Bylaws of Triangle Petroleum Corporation, filed as Exhibit 3.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2012 and incorporated herein by reference.

4.1		Form of Common Stock Certificate of Triangle Petroleum Corporation, filed as Exhibit 4.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2012 and incorporated herein by reference.

4.2		5% Convertible Promissory Note, dated July 31, 2012, filed as Exhibit 4.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2012 and incorporated herein by reference.

4.3		Investment Agreement, dated July 31, 2012, among Triangle Petroleum Corporation, NGP Triangle Holdings, LLC and NGP Natural Resources X, L.P., filed as Exhibit 4.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2012 and incorporated herein by reference.

4.4		First Amendment to Investment Agreement, dated March 8, 2013, between Triangle Petroleum Corporation, NGP Triangle Holdings, LLC, NGP Natural Resources X, L.P., and NGP Natural Resources X Parallel Fund, L.P., filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 13, 2013 and incorporated herein by reference.

4.5		Amended and Restated Registration Rights Agreement, dated March 8, 2013, between Triangle Petroleum Corporation, NGP Triangle Holdings, LLC, NGP Natural Resources X, L.P., and NGP Natural Resources X Parallel Fund, L.P., filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 13, 2013 and incorporated herein by reference.

10.1 †		Stock Option Plan, filed as Exhibit 10.1 to the Registration Statement on Form S-8 filed with the Securities and Exchange Commission on January 31, 2011 and incorporated herein by reference.

10.2 †		Amended and Restated 2011 Omnibus Incentive Plan, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 16, 2012 and incorporated herein by reference.

10.3		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 Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 20, 2009 and incorporated

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		herein by reference.

10.4 †		Second Amended and Restated Employment Agreement, dated May 18, 2012, by and between Triangle Petroleum Corporation and Dr. Peter Hill, filed as Exhibit 10.04 to the Annual Report on Form 10-K/A filed with the Securities and Exchange Commission on May 18, 2012 and incorporated herein by reference.

10.5 †		Second Amended and Restated Employment Agreement, dated May 18, 2012, by and between Triangle Petroleum Corporation and Jonathan Samuels, filed as Exhibit 10.05 to the Annual Report on Form 10-K/A filed with the Securities and Exchange Commission on May 18, 2012 and incorporated herein by reference.

10.6 †		Employment Agreement, dated May 18, 2012, by and between Triangle Petroleum Corporation and Joseph Feiten, filed as Exhibit 10.06 to the Annual Report on Form 10-K/A filed with the Securities and Exchange Commission on May 18, 2012 and incorporated herein by reference.

10.7*†		Employment Agreement, dated May 1, 2013, by and between Triangle Petroleum Corporation and Justin Bliffen.

10.8		Amended and Restated Credit Agreement, dated April 11, 2013, among Triangle USA Petroleum Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and Issuing Lender, and the Lenders Named Herein, as Lenders, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 17, 2013 and incorporated herein by reference.

10.9		Note Purchase Agreement, dated July 31, 2012, between Triangle Petroleum Corporation and NGP Triangle Holdings, LLC, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2012 and incorporated herein by reference.

10.10		Contribution Agreement, dated October 1, 2012, by and among Triangle Caliber Holdings, LLC, Caliber Midstream GP LLC, Caliber Midstream Partners, L.P., and FREIF Caliber Holdings LLC, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on October 1, 2012 and incorporated herein by reference.

10.11		Purchase and Sale Agreement, dated December 28, 2012, between Triangle Petroleum Corporation and DCF Partners, L.P., filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on January 4, 2013 and incorporated herein by reference.

10.12		Credit and Security Agreement, dated February 25, 2013, between RockPile Energy Services, LLC and Wells Fargo Bank, National Association, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 1, 2013 and incorporated herein by reference.

10.13		Stock Purchase Agreement, dated March 2, 2013, between Triangle Petroleum Corporation and NGP Triangle Holdings, LLC, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 4, 2013 and incorporated herein by reference.

14.1		Code of Business Conduct and Ethics, filed as Exhibit 14.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 6, 2011 and incorporated herein by reference.

21.1*		List of Subsidiaries.

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23.1*		Consent of Ryder Scott Petroleum Consultants.

23.2*		Consent of Cawley, Gillespie & Associates, Inc.

23.3*		Consent of KPMG LLP.

23.4*		Consent of KPMG LLP — Calgary.

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

31.1*		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.

31.2*		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.

32.1*		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.

99.1		Reserve Estimate Report of Ryder Scott Company L.P., filed as Exhibit 99.02 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 16, 2012 and incorporated herein by reference.

99.2*		Reserves Audit Report of Cawley, Gillespie & Associates, Inc.

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.

† Management Contract or Compensatory Plan or Arrangement.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

TRIANGLE PETROLEUM CORPORATION

Date: April 30, 2013	By:	/s/ JONATHAN SAMUELS
	Jonathan Samuels
	President and Chief Executive Officer (Principal Executive Officer)

Date: April 30, 2013	By:	/s/ JUSTIN BLIFFEN
	Justin Bliffen
	Chief Financial Officer (Principal Financial Officer)

Date: April 30, 2013	By:	/s/ JOSEPH FEITEN
	Joseph Feiten
	Principal Accounting 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 report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name	Position	Date

/s/ JONATHAN SAMUELS	President and Chief Executive Officer and Director,	April 30, 2013
Jonathan Samuels	(Principal Executive Officer)

/s/ JUSTIN BLIFFEN	Chief Financial Officer (Principal Financial Officer)	April 30, 2013
Justin Bliffen

/s/ JOSEPH FEITEN	Principal Accounting Officer	April 30, 2013
Joseph Feiten

/s/ PETER HILL	Director	April 30, 2013
Peter Hill

/s/ F. GARDNER PARKER	Director	April 30, 2013
F. Gardner Parker

/s/ GUS HALAS	Director	April 30, 2013
Gus Halas

/s/ RANDAL MATKALUK	Director	April 30, 2013
Randal Matkaluk

/s/ ROY ANEED	Director	April 30, 2013
Roy Aneed

		Page
Part I

Item 1.	Business	3

Item 1A.	Risk Factors	21

Item 1B.	Unresolved Staff Comments	36

Item 2.	Properties	36

Item 3.	Legal Proceedings	44

Item 4.	Mine Safety Disclosures	44

Part II

Item 5.	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	45

Item 6.	Selected Financial Data	47

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	48

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	64

Item 8.	Consolidated Financial Statements and Supplementary Data	66

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosures	109

Item 9A.	Controls and Procedures	109

Item 9B.	Other Information	113

Part III

Item 10.	Directors, Executive Officers and Corporate Governance	113

Item 11.	Executive Compensation	113

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	113

Item 13.	Certain Relationships and Related Transactions, Director Independence	113

Item 14.	Principal Accounting Fees and Services	113

Part IV

Item 15.	Exhibits; Financial Statement Schedules	114

Signatures.		117

	Total Number of Shares Purchased	Average Price Paid Per Share
	(1)	(2)
November 1, 2012 - November 30, 2012	1,296	$	5.49
December 1, 2012 - December 31, 2012	33,892	5.95
January 1, 2013 - January 31, 2013	9,287	5.97
	44,475	$	5.94

(signed) KPMG LLP

Chartered Accountants
Calgary, Canada
April 13, 2011

Reports of Independent Registered Public Accounting Firms	67

Consolidated Balance Sheets as of January 31, 2013 and 2012	69

Consolidated Statements of Operations and Comprehensive Loss for each of the years ended January 31, 2013, 2012 and 2011	70

Consolidated Statements of Cash Flows for each of the years ended January 31, 2013, 2012 and 2011	71

Consolidated Statement of Stockholders’ Equity for each of the years ended January 31, 2013, 2012 and 2011	72

Notes to Consolidated Financial Statements	74