10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the year ended January 31, 2015

001-34945

(Commission File No.)

TRIANGLE PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

STATE OF DELAWARE	98-0430762
(State or Other Jurisdiction of Incorporation)	(I.R.S. Employer Identification No.)

1200 17th Street, Suite 2600, Denver, Colorado 80202

(Address of principal executive offices)

Registrant’s telephone number, including area code: 303.260.7125

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

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

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 in Rule 405 of the Securities Act. Yes ☐No☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐No☒

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 90days.Yes☒   No☐

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

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

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

Large accelerated filer☐	Accelerated filer☒
Non-accelerated filer☐	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 ☐No☒

As of July 31, 2014, the last business day of the registrant’s most recently completed second quarter, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $695,506,738 based on a closing price of $10.80 per share as reported on the NYSE MKT on such date. 

As of April 1, 2015, the registrant had75,288,381shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Part III incorporated by reference from the registrant’s Definitive Proxy Statement for its 2015 Annual Meeting of Stockholders to be filed, pursuant to Regulation 14A, no later than 120 days after the close of the registrant’s  fiscal year.

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TRIANGLE PETROLEUM CORPORATION

FORM 10-K FOR THE YEAR ENDED JANUARY 31, 2015

TABLE OF CONTENTS

		Page
Part I
Item 1.	Business	5
Item 1A.	Risk Factors	21
Item 1B.	Unresolved Staff Comments	38
Item 2.	Properties	38
Item 3.	Legal Proceedings	38
Item 4.	Mine Safety Disclosures	38
Part II
Item 5.	Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	39
Item 6.	Selected Financial Data	42
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	58
Item 8.	Consolidated Financial Statements and Supplementary Data	60
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosures	102
Item 9A.	Controls and Procedures	102
Item 9B.	Other Information	105
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	105
Item 11.	Executive Compensation	105
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	105
Item 13.	Certain Relationships and Related Transactions, Director Independence	105
Item 14.	Principal Accounting Fees and Services	105
Part IV
Item 15.	Exhibits; Financial Statement Schedules	106
Signatures		109

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Where You Can Find More Information

Triangle Petroleum Corporation (“Triangle,” the “Company,” “we,” “us,” “our,” or “ours”) files annual, quarterly, and current reports with the Securities and Exchange Commission (the “SEC”).  These reports and other information can be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549.  Please call the SEC at 1-800-732-0330 for further information on the operation of the Public Reference Room.  The SEC also maintains an Internet site at http://www.sec.gov that contains reports, proxy, and information statements, and other information regarding issuers that file electronically with the SEC, including Triangle.

Investors can also access financial and other information via Triangle’s website at www.trianglepetroleum.com. Triangle makes available, free of charge through its website, copies of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, any amendments to such reports, and all reports filed under Section 16 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), reporting transactions in Triangle securities.  Access to these reports is provided as soon as reasonably practical after such reports are electronically filed with the SEC.  Information contained on or connected to Triangle’s website which is not directly incorporated by reference into the Company’s Annual Report on Form 10-K should not be considered part of this report or any other filing made with the SEC.

Finally, you may request a copy of filings, other than an exhibit to a filing unless that exhibit is specifically incorporated by reference into that filing, at no cost by writing Triangle at 1200 17th Street, Suite 2600, Denver, Colorado 80202 or by calling Triangle at 1-303-260-7125.

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 statements of historical facts are hereby identified as forward-looking statements for the purpose of the safe harbor provided by Section 21E of the Exchange Act, and Section 27A of the Securities Act of 1933, as amended (the “Securities Act”).

These forward-looking statements include, but are not limited to, statements about:

· Triangle’s future capital expenditures and performance;

· anticipated drilling and development;

· drilling results;

· results of acquisitions;

· Triangle’s relationships with partners; and

· Triangle’s plans for its subsidiaries.

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 in “Risk Factors” and elsewhere, and the risks detailed from time to time in our future SEC reports.  Many of the important factors that will determine these results are beyond Triangle’s ability to control or predict.  Risks and uncertainties that could affect future results include those relating to:

· oil and natural gas prices;

· substantial capital requirements and access to additional capital;

· our indebtedness and borrowing capacity;

· reserves assumptions;

· potential future impairments;

· our ability to develop or acquire additional reserves;

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

· reliance on third party experts and service providers;

· potential increase in non-consenting non-operator partners;

· challenging agreements with operators and joint venture partners;

· our inability to control properties we do not operate;

· government regulation and taxation of the oil and natural gas industry;

· potential regulation affecting hydraulic fracturing;

· environmental regulations, including climate change regulations;

· unavailability and cost of facilities, services, raw materials, and infrastructure;

· uninsured or underinsured risks;

· Triangle’s ability to manage growth in its businesses;

· lack of diversification;

· competition in the oil and natural gas industry;

· seasonal weather conditions;

· unavailability of qualified personnel;

· potential restatement of financial statements;

· cybersecurity risks;

· aboriginal claims;

· the influence of significant stockholders;

· lack of control over Caliber and potential dilution of our economic interest;

· changes in the fair value of our derivative instruments; and

· expiring commodity derivatives.

You are cautioned not to put undue reliance on any forward-looking statements, which speak only as of the date of this annual report.  Triangle does not assume any obligation to 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.

Units of Measurement and Glossary of Industry Terms

Units of measurement and industry terms are defined in the Units of Measurement and Glossary of Industry Terms, included at the end of this annual report.

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PART I

You should read this entire report carefully; including the risks described under Part I, Item 1A. Risk Factors and our consolidated financial statements and the notes to those consolidated financial statements included elsewhere in this report.  Unless the context otherwise requires, references in this report to “Triangle,” the “Company,”“we,”“us,”“our,” or “ours” refer to Triangle Petroleum Corporation and its subsidiaries.Our fiscal year-end is January 31.As such, the fiscal years ended January 31, 2015, 2014, and 2013 are referred to in this annual report as fiscal year 2015, fiscal year 2014, and fiscal year 2013, respectively.  The fiscal year ending January 31, 2016 is referred to in this annual report as fiscal year 2016.

ITEM 1.  BUSINESS

Company Overview

We are  an independent energy holding company with three principal lines of business: oil and natural gas exploration, development, and production; oilfield services; and midstream services.  We conduct these activities in the Williston Basin of North Dakota and Montana through the Company’s two principal wholly-owned subsidiaries and our equity joint venture:

· Triangle USA Petroleum Corporation (“TUSA”) conducts our exploration and production operations by acquiring and developing unconventional shale oil and natural gas resources;

· RockPile Energy Services, LLC (“RockPile”) is a provider of hydraulic pressure pumping and complementary services; and

· Caliber Midstream Partners, L.P. (“Caliber”) is our 28.3% owned joint venture with First Reserve Energy Infrastructure Fund (“FREIF”).  Caliber provides crude oil, natural gas and fresh and produced water gathering, processing, and transportation services.

Our primary focus at TUSA is to grow our production volumes through the efficient development of our operated Bakken Shale and Three Forks drilling inventory.  We completed our first operated well in May 2012.  From May 2012 through January 31, 2015, we have completed 96 gross (68.8 net) operated wells.  Our average net daily production for the year ended January 31, 2015 was approximately11,441 Boe/d, approximately 86% of which was operated production.At January 31, 2015, we had estimated proved reserves of approximately 58.9 MMboe, based on adjusted prices of $79.71 per Bbl for oil, $34.61 per Bbl for natural gas liquids, and $6.09 per Mcf for natural gas.We use pad drilling, which increases efficiencies while controlling costs and minimizing environmental impact.  We also use advanced completion, collection, and production techniques designed to optimize reservoir production while reducing costs.  

In an effort to better control key operations, reduce costs, and retain supply chain value in the Williston Basin, which we view as a historically resource-constrained and cost-heavy basin, we formed RockPile and entered into a joint venture arrangement with FREIF to form Caliber. RockPile’s services lower our realized well completion costsand affords us greater control over completion schedules and quality control.  We expect that Caliber will reduce the cost and environmental impacts associated with trucking oil and water and reduce or eliminate the emissions generated by the flaring of produced natural gas from our operated wells.  In addition to providing services to TUSA, RockPile and Caliber are focused on growing their respective businesses through securing independent, third-party contracts. 

Triangle has two reportable operating segments.  Our exploration and production operating segment and our oilfield services operating segment are managed separately because of the nature of their products and services.  The focus of the exploration and production operating segment is finding and producing oil and natural gas.  The focus of the oilfield services operating segment is pressure pumping and complementary services for both TUSA-operated wells and third-party-operated wells.See Part II. Item 8. Consolidated Financial Statements and Supplementary Data.

We were incorporated in the State of Nevada on December 11, 2003 under the name Peloton Resources Inc.  On May10, 2005, we changed our name to Triangle Petroleum Corporation.  On November 30, 2012, we changed our state of incorporation from Nevada to Delaware.

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Exploration, Development and Production

Williston Basin – United States.  As of January 31, 2015, we held leasehold interests in approximately 126,037 net acres in the Williston Basin.  Approximately 83,373 net acres are located in our core focus area in McKenzie and Williams Counties, North Dakota, and eastern Roosevelt and Sheridan Counties, Montana,which we refer to as our “Core Acreage.”  Our Core Acreage has high oil saturation, is slightly over-pressured, and has the potential for multiple benches.  We operate approximately 51,434 net acres in our Core Acreage.  We also hold approximately 42,664 net undeveloped acres in the Station Prospect located in Sheridan and Roosevelt Counties, Montana.  The majority of our Williston Basin leaseholds are held primarily under fee leases.  These leases typically carry a primary term of three to five 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 January 31, 2015, we have completed a total of 96 gross  (68.8 net) operated wells in the Williston Basin.  As of that date we were running a four-rig drilling program.  We have subsequently released two rigs upon expiration of the underlying contracts, and we currently plan to run an average of less than two rigs through fiscal year 2016.  During fiscal year 2016, we anticipate drilling approximately 25 to 27 gross operated wells and completing approximately 27 to 29 gross operated wells in North Dakota or eastern Montana for completion in the Bakken Shale or Three Forks formations.  We target the Middle Bakken formation between the Upper and Lower Bakken Shales at an approximate vertical depth of 10,300 to 11,300 feet.  We also target the Three Forks formation, which is present immediately below the Lower Bakken Shale.

The operations of our non-operated leasehold positions are primarily conducted through agreements with major operators in the Williston Basin, including Oasis Petroleum, Slawson Exploration Company, Newfield Production Company, Statoil, Whiting Petroleum, and EOG Resources.  These companies are experienced operators in the Williston Basin.  As of the end of fiscal year 2015, we have an interest in 480 gross (26.5 net) non-operated wells, 412 gross (23.8 net) of which are producing and 68 gross (2.7 net) are in various stages of permitting, drilling or completion.

Discussed below are key aspects of our drilling program in our Core Acreage:

· Long Laterals.  Based upon our analysis of well costs and the performance from our operated wells and other operators’ wells, we believe long laterals (~10,000 feet) in our horizontal wells will generate higher rates of return than short laterals (~5,000 feet or less) for wells in our Core Acreage.  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 more than offset by the associated incremental increase in oil production cash flows.  Accordingly, we plan to continue drilling ~10,000 foot laterals throughout our Core Acreage position.

· Multi-Well Pads.  We typically drill two or more wells per drilling rig visit to each pad.  As we continue the development stage of our drilling, we expect the average number of wells drilled per pad to increase.  We have designed our initial pads to accommodate the increased number of wells expected on each pad.  We plan to continue capitalizing on the many benefits of pad drilling to increase our efficiencies and reduce costs.  Pad drilling allows for the reduction of rig mobilization and demobilization costs, the aggregation of necessary infrastructure and distribution of costs for the same.  Pad drilling also allows for increased efficiencies and cost savings when completing our wells using techniques such as zipper fracturing.  Utilization of zipper fracturing techniques allows the simultaneous completion of two or more wells by alternating perforation and pressure pumping operations.  We also perform other simultaneous operations on our well pads, allowing for continuous production from an existing well while drilling and completing another well on the same pad.  Pad drilling also reduces the surface footprint of our operations.

· Wellbore Spacing.Consistent with other operators near our Core Acreage position, we are developing our wellbores on tighter spacing patterns.  We have test drilled wellbores within 600 feet, laterally, of one another in the Middle Bakken formation, and these wells continue to perform well.  These and other tests performed by Triangle and other operators suggest that up to eight Middle Bakken wells can be drilled per DSU without significant communication between wellbores.

· Contiguous Acreage.  Our Core Acreage operated leasehold is largely contiguous and, by virtue of our high working interest and operatorship, we can control the development pace and location of surface facilities.  We believe this strategy, combined with pad drilling, Caliber’s infrastructure, and efficiencies provided by RockPile, 6

should maximize the efficiency of our drilling and completion program and minimize the capital costs of developing our acreage position.

· Acreage Held by Production.  Our drilling activity has resulted in the vast majority of our operated drilling units being held by production.  This provides increased flexibility in our capital program and allows us to more efficiently develop our leaseholds toward the proper ultimate spacing for each drilling unit.

· Infrastructure.  As of January 31, 2015, we had119 operated wells, 107 (90%) of which are currently connected to Caliber or third-party midstream pipelines and processing facilities for natural gas liquids, allowing for the reduction of flared volumes and the capture of additional revenue from the liquids-rich gas that is produced with our oil.  Caliber had 93of our operated wells connected to fresh water delivery and 89 operated wells connected to its oil and produced water gathering infrastructure.  Most of our Core Acreage will soon be served by similar Caliber or third-party oil and natural gas gathering systems.  The majority of our wells are also in the process of being connected to regional oil and natural gas pipelines.  Moving produced fluids (oil, natural gas, and water) through pipelines eliminates trucking costs and associated environmental disturbance, and mitigates weather-related production interruptions.  Following completion of Caliber’s Medium Haul Pipeline to Alexander, North Dakota in September 2014, a large portion of our production has access to various means of transportation to market, which helps maximize revenue while minimizing impacts to the environment.

Reserves

Net Reserves of Crude Oil, Natural Gas, and Natural Gas Liquids at Fiscal Year-End 2015,  2014, and 2013.  Approximately 99% of the Company’s proved reserves at January 31, 2015 are associated with properties located in our Core Acreage.  Our proved reserves are located in the Bakken Shale and Three Forks formations.  The table below summarizes our estimates of proved reserves as of January 31, 2015,  2014, and 2013, the estimated projected future cash flows (before income taxes) from those proved reserves, and the PV-10 Value of the proved reserves at January31, 2015,  2014, and 2013:

	For the Years Ended January 31,
	2015		2014		2013
Proved developed:
Oil (Mbbls)		29,605		13,734		4,985
Natural gas (MMcf)		24,136		10,930		5,906
NGL (Mbbls)		2,350		1,440		—
Proved undeveloped:
Oil (Mbbls)		18,486		18,182		7,555
Natural gas (MMcf)		16,049		15,574		6,679
NGL (Mbbls)		1,731		2,541		—
Total proved oil reserves (Mbbls)		48,091		31,916		12,540
Total proved natural gas reserves (MMcf)		40,185		26,504		12,585
Total proved NGL reserves (Mbbls)		4,081		3,981		—
Total proved oil, NGL and natural gas reserves (Mboe)		58,870		40,314		14,637
PV-10 Values (in thousands) of proved reserves:
PV-10 Value of proved developed reserves	$	803,303	$	471,764	$	165,484
PV-10 Value of proved undeveloped reserves	$	179,510	$	206,141	$	59,377
PV-10 Value of total proved reserves	$	982,813	$	677,905	$	224,861

The increase in our total proved reserves in fiscal year 2015 of 18,556 Mboe resulted primarily from our drilling and completion activity on our Core Acreage.  The gross number of proved undeveloped (“PUD”) locations decreased from 104 at fiscal year-end 2014 to 103 gross locations at fiscal year-end 2015, but the number of net PUD locations increased from 52.5 to 54.0 over the same period.  These PUD locations offset our existing producing wells or are located in drill spacing units that offset producing wells.  The small growth in net PUD locations from fiscal year-end 2014 to fiscal year-end 2015, as contrasted with the significant growth during the prior year period, resulted from revised drilling schedules reflecting current commodity prices and increased infill drilling.

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In estimating 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 31estimation date except that future commodity prices used in the projections reflected a simple average of prices for our operated and non-operated properties on the first day of each of the twelve months in the year ended on the estimation date.  Prices of $91.22 per Bbl for oil, $50.07 per barrel for natural gas liquids, and $4.20 per MMbtu for natural gas were adjusted for regional price differentials; gathering, transportation, and processing; and other factors to arrive at prices of $79.71 per Bbl for oil, $34.61 per barrel for natural gas liquids, and $6.09 per Mcf for natural gas, which were used in the calculation of proved reserves at January 31, 2015.

Volumes of reserves that will actually be recovered and cash flows that will actually be received from 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, among other things, the quality of available data, and engineering and geological interpretation and judgment.  In addition, results of drilling, testing, and production subsequent to the date of an estimate may justify revision of such estimates, particularly for undeveloped locations where estimates may be more imprecise than for established producing oil and natural gas properties.  Accordingly, reserve estimates are often different from the quantities that are ultimately recovered.

The following table reconciles (a) the standardized measure of discounted future net cash flows related to our proved oil and natural gas reserves (“Standardized Measure”), a measure calculated in accordance with generally accepted accounting principles (“GAAP”) to (b) the PV-10 Value (a non-GAAP financial measure) of our proved reserves.  The difference is due to the fact that PV-10 Value excludes the impact of income taxes.

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Standardized Measure, for total proved reserves	$	821,492	$	573,235	$	211,352
Add back: Discounting at 10% per annum		977,088		690,564		297,653
Future cash flows, after income taxes		1,798,580		1,263,799		509,005
Add: future undiscounted income taxes		394,538		364,340		87,313
Undiscounted future net cash flows before taxes		2,193,118		1,628,139		596,318
Less: Discounting at 10% per annum		(1,210,305)		(950,234)		(371,457)
PV-10 Value of total proved oil and natural gas reserves	$	982,813	$	677,905	$	224,861

The Standardized Measure is presented more fully and discussed further in Part II. Item 8.Consolidated Financial Statements and Supplementary Data.

Proved Undeveloped Reserves.  At January 31, 2015, we estimated proved undeveloped reserves of 22,892 Mboe, which represents 39% of our total proved reserves, as compared to 23,319 Mboe or 58% of our total proved reserves at January 31, 2014.  In connection with our drilling and completion program, we incurred approximately  $151.6 million (averaging $8.2 million per net well) related to the conversion of 8,461 Mboe  (30 gross wells, 18.5 net wells) from proved undeveloped reserves to proved developed reserves.

Changes in our proved undeveloped reserves are summarized in the following table:

	(Mboe)	Gross Wells	Net Wells
Proved Undeveloped Reserves at January 31, 2014	23,319	104	52.5
Became developed reserves in fiscal year 2015	(8,461)	(30)	(18.5)
Revisions	1,676	(14)	4.7
Acquisitions	528	6	1.3
Extensions and discoveries of proved reserves	5,830	37	14.0
Proved Undeveloped Reserves at January 31, 2015	22,892	103	54.0

At January 31, 2015, we have no proved undeveloped reserves that are scheduled for development five years or more beyond the date the reserves were initially recorded.

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

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(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, 2015,2014, and 2013, Triangle’s Reservoir Manager used the following 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 was 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.

Internal Controls over Reserve Estimation.  The Company engaged Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”), an independent petroleum engineering firm, to perform an audit of Triangle’s internal estimates of proved reserves.  Cawley Gillespie’s  fiscal year-end 2015 reserves audit 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.  The internal reserve estimates and supporting schedules are prepared by our Reserve Engineer and reviewed by management prior to being provided to Cawley Gillespie.

Cawley Gillespie’s  fiscal year-end 2015 reserves audit report (filed as Exhibit 99.1 to this annual report) states that Cawley Gillespie is a Texas Registered Engineering Firm (F-693), comprised 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 Mr. W. Todd Brooker, Senior Vice President at Cawley Gillespie 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 Cawley Gillespie as a Reservoir Engineer in 1992.

Our Reservoir Manager, Corey Meyer, is the technical person primarily responsible for overseeing the preparation of the Company’s reserves estimates. He has over 20 years of experience as a petroleum engineer and is a member of the Society of Petroleum Engineers. He holds an undergraduate degree in Petroleum Engineering from the Colorado School of Mines. The Company’s internal estimates of proved reserves are based on available geoscience and engineering data, including North Dakota online files of monthly production for wells in which we have an interest and wells adjacent to drill spacing units in which we have an interest. The internal reserve schedules and certain supporting schedules are reviewed by various members of management before our Reservoir Manager prepares a final internal summary of proved reserves and a final listing (by well and drilling location) of proved reserves, which is then provided to Cawley Gillespie.

Developed and Undeveloped Acreage

As of January 31, 2015, we had approximately 3,804 lease agreements representing approximately 248,258 gross  (126,037 net) acres in the Williston Basin of North Dakota and Montana.  The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases:

	DevelopedAcres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
North Dakota	157,597	61,227	30,061	12,165	187,658	73,392
Montana	6,662	6,187	53,938	46,458	60,600	52,645
Total Williston Basin	164,259	67,414	83,999	58,623	248,258	126,037

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 (i) make extension payment(s) under the lease terms, (ii) renew the existing lease, (iii) establish commercial production in paying quantities, or (iv) trigger some other “savings clause” in the relevant lease.  Out of our 83,999 gross (58,623 net) undeveloped acres as of January 31, 2015, the portion of our net undeveloped acres that is subject to expiration over the next three years, if not successfully developed or renewed, is approximately 37% in fiscal year 2016, 34% in fiscal year 2017, and 23% in fiscal year 2018.  We expect

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to establish production from most of our Core Acreage prior to expiration of the applicable lease. However, there can be no guarantee we will do so.

Drilling and Other Exploratory and Development Activities

The following table presents the gross and net number of exploration wells and development wells drilled in the U.S. during fiscal years  2015, 2014, and 2013 targeting oil reserves, based on the date of first sales or the date the well became capable of selling.  The number of wells drilled refers to the number of wells completed at any time during the 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 2015		Fiscal Year 2014		Fiscal Year 2013
	Gross	Net	Gross	Net	Gross	Net
Productive exploratory wells:
Operated by Triangle	17	11.7	9	7.2	6	3.2
Operated by others	78	3.3	37	2.0	41	0.6
Total	95	15.0	46	9.2	47	3.8
Dry exploratory wells	—	—	—	—	1	—
Productive development wells:
Operated by Triangle	32	22.8	22	16.3	10	6.9
Operated by others	18	0.8	44	2.6	14	0.7
Total	50	23.6	66	18.9	24	7.6
Dry development wells	—	—	—	—	—	—
Total productive wells	145	38.6	112	28.1	71	11.4

As of January 31, 2015, we had 531 gross productive wells and 111.9 net productive wells, all located in North Dakota except for 13 gross wells located in Roosevelt and Sheridan Counties, Montana.  None of our gross productive wells had completions within multiple zones.  Our count of productive wells does not include 75 gross (16.0 net) wells that were awaiting completion, in the process of completion, or awaiting flowback subsequent to fracture stimulation as of that date.  Although we encounter and produce natural gas as a byproduct of drilling wells targeting crude oil, we have not participated in any wells specifically targeting natural gas reserves.

Costs Incurred and Capitalized Costs

The table below presents costs incurred in oil and natural gas acquisition, exploration, and development activities during fiscal years 2015, 2014, and 2013. 

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Property acquisition	$	138,778	$	121,578	$	21,193
Exploration		180,174		96,731		55,583
Development		226,765		216,046		91,666
Total	$	545,717	$	434,355	$	168,442

We anticipate our unproved properties and properties under development costs at January 31, 2015 of $142.9 million will be included in the amortization computation over the next five years.  We are unable to predict the future impact on amortization rates.

Oilfield Services

RockPile, our wholly-owned subsidiary initially capitalized in October 2011, is a provider of hydraulic pressure pumping and complementary services to oil and natural gas exploration and production companies primarily in the Williston Basin.  RockPile purchased its first set of equipment, collectively known as a “spread”, in the first half of 2012. 

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RockPile’s first spread commenced 12-hour operations in July 2012 and 24-hour operations in September 2012.  RockPile commenced 24-hour operations with a second spread in July 2013, with a third spread in April 2014, and with a fourth spread in September 2014.  RockPile’s management team has extensive experience providing oilfield services.RockPile provides a variety of oilfield services including, but not limited to, pressure pumping, wireline, perforating, pump rental, and workover services. 

The use of RockPile’s services lowers our realized well completion costs and affords us greater control over completion schedules and quality control.  In fiscal year 2015,  RockPile increased year-over-year completions by approximately 83%, completing 49 TUSA-operated wells and 99 third-party wells, as compared to 31 TUSA operated wells and 50 third-party wells in fiscal year 2014.  RockPile contributed $288.5 million to our consolidated revenue for the year ended January 31, 2015.  We believe that the breadth of RockPile’s services and the experience and expertise of its personnel give it a competitive advantage relative to many of its competitors in the region.

RockPile’s customers use hydraulic fracturing or pressure pumping services to enhance the production of oil and natural gas from formations with low permeability, which restricts the natural flow of hydrocarbons.  Hydraulic fracturing involves pumping fluid down a well casing or tubing at sufficient pressure to cause the underground producing formation to fracture, allowing the oil or natural gas to flow more freely.  A propping agent, or proppant, is suspended in the fracturing fluid and pumped into the fractures created by the fracturing process in the underground formation to prop the fractures open.  Proppants generally consist of sand, bauxite, resin-coated sand or ceramic particles, and other engineered proprietary materials.  The extremely high pressure required to stimulate wells in the areas in which we operate presents a challenging environment for achieving a successfully fractured horizontal well.  As a result, an important element of the services RockPile provides to producers is assisting with well completion design, which includes determining the proper fluid, proppant, and injection specifications to maximize production.

In addition, RockPile’s workover rig division provides intervention and remedial services such as drill-outs, clean-outs, installation, and replacement of pumps, packers and frac strings, swabbing, and well repair and maintenance.  As the Williston Basin matures, demand for remedial service is also expected to increase.

RockPile has historically operated primarily in the Williston Basin.  While RockPile expects that the Williston Basin will remain the focus of its operations, RockPile has provided pressure pumping services in one other basin and is currently evaluating opportunities in other areas.

Midstream Services

Caliber is an energy infrastructure company that provides a full suite of midstream services to us and other producers in the Williston Basin.  Caliber’s midstream services include crude oil and natural gas gathering, transportation, treating and processing, produced water transportation and disposal, and freshwater sourcing and transportation via pipeline. 

Caliber was created in October 2012, and capitalized through initial funding commitments of $100.0 million in equity capital contributions ($70.0 million from FREIF, $30.0 million from Triangle).  FREIF committed an additional $80.0 million in equity capital contributions in September 2013, followed by an equity capital contribution of $34.0 million in February 2015.  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.  We currently hold a 28.3% Series A Units economic interest in Caliber.

Caliber’s operations are principally located in McKenzie County, North Dakota.  Since its inception, Caliber has constructed over 250 miles of pipelines across its four service lines.  Caliber’s crude oil infrastructure includes two stabilization facilities and an interconnection with the Enbridge pipeline at the Alexander Market Center. Caliber also owns and operates the Hay Butte Gas Plant, which consists of a mechanical refrigeration unit with a capacity of 10 MMcf per day.  Processed natural gas and natural gas liquids are delivered via pipeline for further distribution downstream.  Caliber also operates two produced water disposal wells.  The disposal wells are connected to the produced water pipeline system or they can receive water from producers by truck.  Finally, Caliber is completing construction of a 23 mile freshwater transportation pipeline to an intake facility on the Yellowstone River.  The fresh water pipeline allows access to 13,200 acre feet per year of fresh water supply to Triangle and other producers for well completions and maintenance water.      

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As of January 31, 2015, we had connected 93 of our operated wells to one or more services provided by Caliber’s midstream system.

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 Years Ended January 31,
	2015		2014		2013
Net Sales Volume
Crude oil (Mbbls)		3,511		1,754		452
Natural gas (MMcf)		2,429		626		188
Natural gas liquids (Mbbls)		260		70		5
Total barrels of oil equivalent (Mboe)		4,176		1,929		488
Average Sales Price Per Unit
Oil price (per Bbl)	$	75.00	$	88.07	$	85.29
Natural gas price (per Mcf)	$	5.27	$	4.39	$	4.78
Natural gas liquids price (per Bbl)	$	32.26	$	46.72	$	36.01
Weighted average price (per Boe)	$	68.13	$	83.22	$	81.15
Operating Expenses Per Unit
Lease operating expenses (per Boe)	$	6.15	$	7.49	$	7.31
Gathering, transportation and processing (per Boe)	$	4.43	$	2.23	$	0.31
Production taxes (per Boe)	$	7.13	$	9.33	$	9.20

Sales from our operated wells began in May 2012.  Our net sales volumes from operated wells totaled 3,579 Mboe for fiscal year 2015.  We sold crude oil, natural gas liquids, and natural gas through delivery points on Caliber’s  and others’ gathering systems in fiscal year 2015.

Significant Customers

Oil, Natural Gas,and Natural Gas Liquids Customers.  For wells that we operate, produced oil 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. 

In fiscal year 2015, we made sales of operated well production directly to 18 oil purchasers, two NGL purchasers and three natural gas purchasers.  In fiscal year 2015, we had revenues from three TUSA customers that exceeded 10% of our $573.0 million in total revenues for the year.  For our topthree TUSA customers, our fiscal year 2015  revenues were approximately $210.5 million or 37% of our total revenues. 

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 2015, 2014, and 2013 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.

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 2015, 2014,

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or 2013. 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.

Oilfield Services 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 and design 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 producers in need of horizontal well completion and oilfield services primarily in the Williston Basin.  During fiscal year 2015, RockPile provided pressure pumping services for 49 wells operated by TUSA and 99 wells operated by third parties.  We do not believe that the loss of any single customer would have a material adverse effect on our Company since there are numerous operators in the Williston Basin in need of pressure pumping and related services.

In fiscal year 2015, we made sales of pressure pumping and well completion services directly to 11 oilfield services customers.In fiscal year 2015, we had revenues from two oilfield services customers that exceeded 10% of our $573.0 million in total revenues for the year.  For our toptwo oilfield services customers, our fiscal year 2015  revenues were approximately $152.3 million or 27% of our total revenues. 

Delivery Commitments

In October 2012, TUSA entered into two midstream services agreements with Caliber North Dakota LLC (“Caliber North Dakota”), an affiliate 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 completion 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 (occurred in April 2014).  On September12, 2013, TUSA and Caliber North Dakota amended and restated the two agreements.  Under the amended and restated agreements, TUSA maintained the revenue commitments included in the original agreements and added a commitment to deliver additional minimum monthly revenues derived from the fees paid by TUSA to Caliber North Dakota related to an increased acreage dedication and increased firm volume commitment.  The additional minimum monthly revenue commitments commenced on the in-service date of certain incremental Caliber North Dakota facilities (occurred in September 2014).  The minimum commitment over the term of the agreements is $405.0 million, of which $359.2 million is outstanding at January 31, 2015.  Also on September 12, 2013, TUSA and Caliber Measurement Services LLC (“Caliber Measurement”), another Caliber affiliate, entered into a gathering services agreement pursuant to which Caliber Measurement provides certain gathering-related measurement services to TUSA.

Competitors

In the Williston Basin, TUSA competes with a number of larger public and private exploration and production companies including, but not limited to, Continental Resources, Statoil, Enerplus Resources Corporation, Oasis Petroleum, Newfield Exploration, and Whiting Petroleum. 

RockPile’s competition includes large integrated oilfield services companies, a significant number of regional competitors, and a limited number of smaller service companies.  RockPile’s competitors include, but are not limited to, Halliburton, Schlumberger, Baker Hughes, PumpCo, Sanjel, and Liberty Oilfield Services.

Caliber competes with large and small-scale pipeline operators, producer-owned midstream systems, trucking companies, and other oilfield services companies.

Seasonality

There is little seasonality in the demand for crude oil produced in North Dakota.  Generally, oil prices in the Williston Basin are impacted by global oil demand and by the availability of crude oil transportation capacity, storage, and related services and infrastructure.  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

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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, which can lessen seasonal demand fluctuations.

Certain of our drilling, completion, and other operations are subject to seasonal limitations.  Our 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, drilling, completion, and other operations can be delayed because of cold, snow, and other winter weather conditions.  Additionally, certain state and local governments in our area of operations have enacted “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 obtain over-the-road permits. Frost laws result in logistical challenges that could potentially result in temporary interruptions in our operations.  Complications from adverse weather conditions are one reason why we are in the process of having future crude oil, natural gas and produced water transported away from the wellhead by pipeline, rather than by truck, for our operated wells. 

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.  Governmental authorities have the power to enforce compliance with these laws and regulations, and violations are subject to injunctive action, as well as administrative, civil and criminal penalties.  The effects of these laws and regulations, as well as other laws or regulations that may be adopted in the future, could have a material adverse impact on our business, financial condition and results of operations.  In view of the many uncertainties concerning 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 are generally no more restrictive on our operations than they are 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 affecting the oil and natural gas industry generally is 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 applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with applicable 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 resolve potential violations could be significant.

Waste Disposal and Contamination Issues.  The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund law,” and comparable state laws may impose joint and several and strict liability, without regard to fault, on certain classes of persons for the release of CERCLA “hazardous substances” into the environment.  These persons include the current and former owners and operators of a site where a release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance at a site.  Under CERCLA, such persons may be subject to joint and several and strict liability for the costs of cleaning up hazardous substances released into the environment and for damages to natural resources.  Strict liability means liability without fault such 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 otherwise without negligence on our part or for the conduct of third parties.  These third

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parties may include prior operators of properties we have acquired, operators of properties in which we have an interest and parties that provide transportation services for us.  If exposed to joint and several liability, we could be responsible for more than our share of a particular clean-up, remediation or other obligation, and potentially for the entire obligation, even where other parties were involved in the activity giving rise to the liability.  In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment.  Such claims may be asserted under CERCLA, as well as state common law theories, or state laws that are modeled after CERCLA.  In the course of our operations, we generate waste that may fall within CERCLA’s definition of “hazardous substances.”  Therefore, governmental agencies or third parties could seek to hold us responsible for all or part of the costs to clean up a site at which such hazardous substances may have been released, or other damages resulting from a release.

The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the management, storage, treatment, disposal, and cleanup of solid and hazardous waste, and authorize substantial fines and penalties for noncompliance.  Drilling fluids, produced waters and many of the other wastes associated with the exploration, development, and production of oil or gas currently are exempt under federal law from regulation as RCRA “hazardous” wastes and instead are regulated as non-hazardous “solid” wastes.  It is possible, however, that oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future.  Any such change could result in an increase in our operating expenses, which could have a material adverse effect on the results of operations and financial position.  Also, in the course of our operations, we generate some industrial wastes, such as paint wastes, waste solvents, and waste oils that may be regulated as hazardous wastes under RCRA and comparable state laws and regulations.

Regulation of Discharges to Water and Water Supplies.  The Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and analogous state laws, impose restrictions and strict controls on the discharge of “pollutants” into “waters of the United States,” including wetlands and other waters without appropriate permits.  These controls generally have become more stringent over time, and it is possible that additional restrictions will be imposed in the future.  Pollutants under the Clean Water Act are defined to include produced water and sand, drilling fluids, drill cuttings, and other substances related to the oil and natural gas industry.  Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for unauthorized discharges or noncompliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.  They also can impose substantial liability for the costs of removal or remediation associated with discharges of pollutants.

The Clean Water Act also regulates stormwater discharges from industrial properties and construction sites, and requires separate permits and implementation of a Stormwater Pollution Prevention Plan (“SWPPP”) establishing best management practices, training, and periodic monitoring of covered activities.  Certain operations also are required to develop and implement Spill Prevention, Control, and Countermeasure (“SPCC”) plans or facility response plans to address potential oil spillsfrom certain above-ground and underground storage tanks.

Our underground injection operations are subject to the federal Safe Drinking Water Act, as well as analogous state laws and regulations. Under Part C of the Safe Drinking Water Act, the Environmental Protection Agency (“EPA”) established the Underground Injection Control (“UIC”) program, which established the minimum program requirements for state programs regulating underground injection activities.  The UIC program includes requirements for permitting, testing, monitoring, recordkeeping, and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water.  Federal and state regulations require permits from applicable regulatory agencies to operate underground injection wells.  In addition, concerns regarding the underground disposal of produced water into Class II UIC wells, including potential seismic impacts, may result in stricter regulation and increased costs associated with oil and natural gas wastewater disposal.

Oil Spill Regulation.  The British Petroleum crude oil spill in the Gulf of Mexico in 2010 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 Oil Pollution Act of 1990 (“OPA”), augments the Clean Water Act and imposes strict liability for owners and operators of facilities that are the source of a release of oil into waters of the United States.  The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills.  For example, operators of oil and natural gas facilities must develop, implement, and maintain facility response plans, conduct annual spill training for employees, and provide varying degrees of financial assurance to cover costs that could be incurred in responding to oil spills.  In addition, owners and operators

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of oil and natural gas facilities may be subject to liability for cleanup costs and natural resource damages as well as a variety of public and private damages resulting from oil spills.

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.  EPA is studying the potential impact of wastewater derived from hydraulic fracturing activities, and in 2015 plans to propose standards that such wastewater must meet before being transported to a treatment plant.  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 also could 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).

Air Emissions and Climate Change.  EPA has finalized major new Clean Air Act (“CAA”) standards (New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells in August 2012 known as “Quad O.”  The standards require, among other things, use of reduced emission completions, or green completions, to reduce volatile organic compound emissions during hydraulically fractured natural gas well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers, and dehydrators.  Following a legal challenge and several petitions for administrative reconsideration of the Quad O rules, EPA issued final amendments related to storage tanks, green completions, and other provisions of the rule in September 2013 and December 2014 respectively.  Most key provisions in Quad O take effect in 2015.  The rules associated with such standards are substantial and will likely increase future costs of our operations and will require us to make modifications to our operations or install new equipment.While the “green completion” requirements likely will not impact our operations since we primarily explore for and produce oil rather than natural gas, the storage vessel requirements apply to a wide array of storage vessels, including those holding condensate and crude oil.  Applicability of these requirements depends on a tank’s potential to emit (PTE) Volatile Organic Compounds (VOCs), not whether it is a gas or oil well.  Thus, while the green completion requirements may not apply to our operations, certain of our tanks may trigger the Quad O storage vessel requirements if they have a PTE that exceeds the applicable threshold.

Wells in the Bakken Shale and Three Forks formations in North Dakota produce natural gas as well as crude oil. Constraints in the current gas gathering network in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold.  The North Dakota Industrial Commission, the State’s chief energy regulator, recently issued an order to reduce the volume of natural gas flared from oil wells in the Bakken Shale and Three Forks formations.  In addition, the Commission is requiring operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed.  Production caps or penalties will be imposed on certain wells that cannot meet the capture goals.

Climate change has emerged as an important topic in public policy debate.  It is a complex issue, with some scientific research suggesting that rising global temperatures are the result of an increase in greenhouse gases (“GHGs”).  Products produced by the oil and natural gas exploration and production industry are a source ofcertain GHGs, primarily carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting and release of fugitive emissions of natural gas could have a significant impact on our future operations.  EPA hasissued a notice of finding and determination that emissions of carbon dioxide, methane, and other GHGs present an endangerment to human health and the environment, which has allowed the EPA to begin regulating emissions of GHGs under existing provisions of the Clean Air Act.  TheEPA has begun to implement GHG-related reporting and permitting rules.  In June 2014, however, the United States Supreme Court invalidated a portion of EPA’s GHG program in the case Utility Air Regulatory Group (“UARG”) v. EPA.  Specifically, under the Supreme Court’s  UARG opinion, sources subject to the federal Title V and/or the Prevention of Significant Deterioration (“PSD”) programs because of emissions of non-GHG pollutants may still be subject to GHG permitting, including requirements to install Best Available Control Technology (“BACT”).  Sources that would be subject to Title V or PSD because of only GHG emissions, however, are no longer subject to GHG permitting requirements, including GHG BACT requirements.  Upon remand, EPA currently is considering how to implement the Court’s decision.

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The U.S. Congress has considered, and may in the future consider, “cap and trade” legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs.Similarly, President Obama has indicated that climate change and GHG regulation is a significant priority for his second term.  The President issued a Climate Action Plan in June 2013 that, among other things, calls for a reduction in methane emissions from the oil and gas sector.  In spring 2014, EPA issued five “Methane White Papers” exploring methane emissions from, and possible controls for, various aspects of the oil and natural gas production process.  Building on these white papers, in January 2015, EPA announced a comprehensive strategy to further reduce methane emissions from the U.S. oil and gas industry, as part of the Obama Administration’s overall GHG reduction strategy.  Proposed rules governing methane emission reductions are expected in 2015, with final rules expected in 2016.  These rules likely will include some additional mandatory requirements, potentially including leak detection and repair obligations, controls for hydraulically fractured oil wells, as well as other control, monitoring, and recordkeeping requirements applicable to a variety of oil and gas facility processes and associated equipment.

In November 2013, the President released an Executive Order charging various federal agencies, including EPA, with devising and pursuing strategies to improve the country’s preparedness and resilience to climate change.  In part through these executive actions, the direct regulation of methane emissions from the oil and gas sector continues to be a focus of regulation.  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.  For example, as part of state-level efforts to reduce these emissions, operating restrictions on emissions by drilling rigs and completion equipment could be enacted, leading to an increase in drilling and completion costs. Also, the emergence of trends such as a worldwide increase in hybrid power motor vehicle sales, and/or decreased personal motor vehicle use by individuals in response to regulatory changes and/or perceived negative impacts on the climate from GHGs could result in lower world-wide consumption of, and prices for, crude oil.

Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs or flaring likely would require us to incur increased operating costs and could have an adverse effect on demand for our production.  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.

Regulation of Hydraulic Fracturing.  Hydraulic fracturing, commonly known as “fracing,” is the primary well-completion method used in the Bakken Shale and Three Forks formations.  Hydraulic fracturing is a process that creates fractures extending from the wellbore into a rock formation that enables oil or natural gas to move more easily through the otherwise impermeable rock to a production well.  Fractures typically are created through the injection of water, chemicals, and sand (or some other type of “proppant”) into the rock formation.  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. 

Several federal agencies, including the EPA, recently have asserted potential regulatory authority over hydraulic fracturing, and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing, with the results of the study anticipated to be available for review in 2015.  Moreover, the EPA also is studying the potential impact of wastewater derived from hydraulic fracturing activities and in2015 plans to propose standards that such wastewater must meet before being transported to a treatment plant. 

On March 20, 2015, the BLM released a final rule that will regulate hydraulic fracturing on federal and Indian lands.The rule requires operators to: (i) submit detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, the depths ofall usable water, estimated volume of fluid to be used, and estimated direction and length of fractures, to the BLM before hydraulically fracturing an existing well; (ii) design and implement a casing and cementing programthat follows best practices and meets performance standards to protect and isolate “usable” water; (iii) monitor cementing operations during well construction; (iv) take remedial action if there are indications of inadequate cementing, and demonstrate to the BLM that the remedial action was successful; (v) perform a successful mechanical integrity test prior to the hydraulic fracturing operation; (vi) monitor annulus pressure during a hydraulic fracturing operation; (vii) manage recovered fluids in rigid enclosed, covered or netted and screened above-ground storage tanks, with very limited exceptions that must be approved on a case-by-case basis; (viii) disclose the chemicals used to the

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BLM and the public, with limited exceptions formaterial demonstrated to be trade secrets; and (ix) provide documentation of all of the above actions to the BLM. 

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.  In the past, such 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 hydraulic 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, Montana and North Dakota have enacted regulations requiring operators to disclose information about hydraulic fracturing fluids on a well-by-well basis, and require specific construction and testing requirements for wells that will be hydraulically fractured.  In addition, in Montana, operators generally must obtain approval from the state before hydraulic fracturing occurs and submit a report after the work is completed.  Some states, municipalities, and other local governmental bodies also have purported to regulate, and in some cases prohibit, hydraulic fracturing activities.  For example, Vermont has banned the use of the technology.

Finally, the EPA is moving forward with Toxic Substances Control Act (“TSCA”) rulemaking, which will collect expansive information on the chemicals used in hydraulic fracturing fluid, including health-related data, from chemical manufacturers and processors.  The EPA expects to issue an Advance Notice of Proposed Rulemaking (“ANPRM”) in 2015.  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”).  In addition, on January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that EPA add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under EPCRA’s Toxics Release Inventory (TRI) program. All of these initiatives present significant, but uncertain, risk of additional regulation of the oil and natural gas industry.

In addition, 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.  We cannot predict the EPA’s future actions in this regard.  Certain states, such asCalifornia and 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.

Regulation of Production of Natural Gas and Oil.  The production of natural gas and oil is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations.  Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations.  The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of natural gas and oil properties, and the regulation of well spacing or density.  The effect of these regulations is to limit the amount of natural gas and oil we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations, or to have reductions in well spacing or density.  Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

The states in which we operate also regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, bonding requirements to drill or operate wells, limits on the location of wells, imposing requirements on the methods of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandonment of wells.

The failure to comply with these rules and regulations can result in substantial penalties.  Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation of Transportation and Sales of Natural Gas.  The transportation and sale of natural gas in interstate commerce are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or NGPA, and regulations issued under those statutes.  FERC regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas we produce, as well as the revenues we receive for sales of our natural gas.  Since 1985, FERC has endeavored to make natural gas

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transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis.  Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

The Domenici Barton Energy Policy Act of 2005, or EP Act of 2005, amended the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provided FERC with additional civil penalty authority.  The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increased FERC’s civil penalty authority under the NGPA to $1.0 million per violation per day.  The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce.  On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing.  The rules make it unlawful to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person.  The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704.

On December 26, 2007, FERC issued Order No. 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing.  Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMbtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices.  It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704.  Order No. 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters.  In some cases, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point of sale locations.  State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory-take requirements.  Although nondiscriminatory-take regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA.  Although FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company.  The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies.  The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state.  Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.  Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation.  In the past, the federal government has regulated the prices at which natural gas could be sold. 

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Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

Our sales of natural gas are also subject to requirements under the Commodity Exchange Act, or CEA, and regulations promulgated thereunder by the Commodity Futures Trading Commission, or CFTC.  The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity.  The CEA also prohibits knowingly delivering, or causing to be delivered, false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take.  We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other producers, gatherers and marketers with which we compete.

Employees

As of January 31, 2015, we had 562 full time employees compared to 332 full time employees at January31, 2014.  We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.

Offices

We maintain our principal office at 1200 17th Street, Suite 2600, Denver, Colorado, 80202, and our telephone number is 1-303-260-7125.  We also own or lease field offices and facilities in North Dakota and Wyoming.

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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 in this section to “we,”“our,”“ours,” and “us” includes our subsidiaries and 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 the expected cash flows from that production and, as a result, adversely affect the quantity and present value 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 TUSA’s credit facility is, and the availability of other sources of capital likely will be, based to a significant degree on the estimated quantity and present value of those reserves.  Declines in prices may also reduce the demand for services provided by RockPile and Caliber.The price of oil fell dramatically in the second half of fiscal year 2015, from a high of $107.26 per barrel in June 2014 to a low of $44.45 per barrel in January 2015, in each case based on WTI prices.  This decline adversely affected TUSA’s revenue and profitability, and also led to a significant reduction in drilling activity in North Dakota, which adversely affected the revenue and profitability of both RockPile and Caliber.  Lower commodity prices have persisted in calendar year 2015.

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 the 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, civil or political unrest in oil and natural gas producing regions, financial and commercial market uncertainty, and worldwide economic conditions.The significant decline in the price of oil that occurred in calendar year 2014 was due to a number of causes outside of our control, including increased overall U.S. production, concerns regarding worldwide economic conditions and a decision by the Organization of Petroleum Exporting Countries not to curtail supply in order to rebalance global crude oil fundamentals.

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 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

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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.

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 conduct the exploration, exploitation and development activities necessary to replace our reserves, and to pay expenses and to satisfy our other obligations.  In recent years, we have chosen to pursue projects that required capital expenditures substantially in excess of cash flows from operations.  That fact has made 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.  Recent declines in commodity prices will likely make it more difficult for us to raise capital on acceptable terms.  Our inability to access sufficient capital for our operations could have a material adverse effect on our business, financial condition, results of operations and prospects.

TUSA’s lenders can limit its borrowing capabilities under its credit facility, which may materially impact our operations.

At January 31, 2015, TUSA had $119.3 million outstanding under its credit facility, with a borrowing base of $435.0 million. The borrowing base under TUSA’s credit facility is redetermined semi-annually based upon a number of factors, including proved reserves growth. In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year.Upon a redetermination, TUSA’s borrowing base could be substantially reduced, and if the new borrowing base is less than the amount of outstanding indebtedness under the credit facility, TUSA will be required to (i) pledge additional collateral, (ii) prepay the principal amount of the loans in an amount sufficient to eliminate the excess, (iii) prepay the excess in five equal monthly installments, or (iv) any combination of options (i) through (iii). TUSA uses cash flows from operations and bank borrowings to fund its exploration, development and acquisition activities. Recent declines in commodity prices significantly increase the risk of adverse changes in the borrowing base.A reduction in TUSA’s borrowing base could materially limit those activities and adversely affect our operations and financial results.

Our substantial level of indebtedness and debt service costs could limit our financial and operating activities, and adversely affect our ability to incur additional debt to fund future needs.

We have outstanding indebtedness under TUSA’s 6.75% Senior Notes, TUSA’s and RockPile’s credit facilities, and our Convertible Note.  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 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 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

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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 service obligations, our substantial indebtedness could limit our ability to incur additional indebtedness if needed for other purposes, including working capital, capital expenditures, acquisitions, and general corporate or other purposes, on satisfactory terms or at all. As a result, 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 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 that 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, availability of capital, estimates of required capital expenditures, 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, 2015, approximately39% of our estimated net remaining proved reserves (Mboe) were proved undeveloped, or PUDs.  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 be recorded only 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, 2015 reflected our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including currently estimated expenditures of approximately $439.7 million during the five years ending on January 31, 2020.  You should be aware that this estimate of our 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 development activities and related expenses, 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 and Standardized Measure 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 and Standardized Measure may not necessarily represent the most appropriate discount factor given actual interest rates and risks to which our business, and the oil and natural gas industry in general, are subject.

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Our 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 an experienced petroleum engineer on our staff and audited by an independent petroleum engineering firm, and determined in 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 fiscal year 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.  Although we had no impairments in fiscal years 2013, 2014 or 2015, there can be no assurance that that we will not recognize impairment expense in future periods.

Much 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 flows and income.

Much 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 flows and income, are highly dependent on our success in developing our undeveloped leasehold acreage.

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 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 as a result of dry holes or 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.  Moreover, even profitable development activity may be less successful than we, investors or analysts expect, potentially resulting in a decline in the market value of our securities.  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.  The currently prevailing lower commodity price environment may reduce certain of these costs.  However, TUSA may not be able to achieve the cost savings it anticipates.  Moreover, RockPile, as a provider of completion services, will have its revenue and profitability reduced by cost reductions demanded by its customers.  In addition, 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;

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· 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 nearly all of the wells we drill in fiscal year 2016 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 wellbore 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 wellbore and not being able to run tools and other equipment consistently through the horizontal wellbore.  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 wellbore during completion operations, and not successfully cleaning out the wellbore 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.

We may not realize the benefits of integrating acquired properties.

The integration into our operations of previously acquired oil and natural gas properties, as well as any future acquired properties, is a significant undertaking and requires significant resources, as well as attention from our management team.  We could encounter difficulties in the integration process, such as the need to revisit assumptions about reserves, future production, revenues, capital expenditures and operating costs, including synergies, the loss of commercial relationships or the need to address unanticipated liabilities.  If we cannot successfully integrate acquired properties into our business, we may fail to realize the expected benefits of those acquisitions.

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 interests and the drilling and completion of productive wells.  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 such assessments are made.  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 will 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 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, or we may not possess sufficient capital to consummate attractive acquisitions.

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Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations.  We may not be able to develop our identified drilling locations as planned.

Producing crude oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors.  The rate of decline may change over time and may exceed our estimates.  Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves.  We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs.  Our failure to do so would adversely affect our future operations, financial condition and results of operations.

We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage.  These well locations represent a significant part of our growth strategy.  Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, midstream constraints, access to and availability of water sourcing and distribution systems, regulatory approvals, and other factors.  Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential well locations.  In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas.  An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis.  Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties.  If these third parties are unwilling to pool their interests with ours, and we are unable to require such pooling on a timely basis or at all, this may limit the total locations we can drill.  As such, our actual drilling activities may materially differ from those presently identified.  Further, our inventory of drilling projects includes locations in addition to those that we currently classify as proved.  The development of and results from these additional projects are more uncertain than those relating to proved locations.

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.

The results of our planned drilling in the Bakken Shale and Three Forks formationsare 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, like that of the industry in general, 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 formations with more 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 resource constrained plays such as the Williston Basin.

If our drilling results are less favorable than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, lack of access to gathering systems and takeaway capacity or otherwise, or oil and natural gas prices decline further, 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.

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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. 

We may experience an increase in non-consenting working interest owners in our operated wells.

Our exploration and development agreements contain customary industry non-consent provisions.  Pursuant to these provisions, if we, as operator, propose a well to be drilled and completed and a working interest owner elects not to participate, we assume the non-participating working interest owners’ share of the costs of such well.  As a penalty for not participating, the portion of the well’s revenues that would otherwise would go to the non-participant flow to us until we receive from 150% to 300% of the capital that we provided to cover the non-participant's share.  We have historically viewed non-consents by other working interest owners in our operated wells favorably as it has the effect of increasing our interest in our operated wells, despite the additional capital outlay.  However, in the current depressed commodity pricing environment, we could experience a significant increase in the number of non-consenting working interest owners that either do not have the capital to participate or choose not to participate at current commodity prices. In either case, we would be required to assume their portion of the well’s expenses.  The potential for such an increase makes it difficult to accurately predict our fiscal year 2016 capital expenditures and could require us to redirect capital budgeted for other expenditures.  Further, redirecting capital to fund the expenses of non-participating working interest owners in our operated wells could cause us to non-consent in wells that we do not operate, and such wells may prove more successful than our operated wells.

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 represent a portion of our production.  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 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.

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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;

· environmental, reclamation, and remediation obligations;

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

· the use of underground and above-ground storage tanks;

· transportation and drilling permits;

· the use of underground injection 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 have increased operating costs and required capital expenditures to remain in compliance.  For example, in 2013, North Dakota, the primary state in which we conduct operations, amended its regulations to impose more stringent regulation of hydraulic fracturing, the disclosure of chemicals used in hydraulic fracturing and more rigorous regulation of pits.  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, under which we could be exposed to liability for clean-up costs and other damages for conduct that was not negligent and was lawful at the time it occurred, or for the conduct of prior owners or 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, under which we could be held responsible for more than our proportionate share of liability for site remediation or other obligations, and potentially the entire obligation, even where other parties also have 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.  Further, our plugging and abandonment obligations will be substantial and may exceed our estimates.  Our operations could also be adversely affected by environmental and other laws and regulations that require us to obtain permits before

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commencing drilling or other activities.  Even when permits are granted in a timely manner, they may be subject to conditions that 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 operations and financial condition.

Caliber’s operations may be subject to additional regulatory risks.  For example, in the future its pipelines may be subject to siting, public necessity, rate and service regulations by 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.  For example, North Dakota adopted new regulations in December 2013 requiring operators to submit data to the state to track construction and reclamation of pipelines, and to track pipeline locations for surface owners.

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.

Climate change has emerged as an important topic in public policy debate.  It is a complex issue, with some scientific research suggesting that rising global temperatures are the result of an increase in GHGs.  Products produced by the oil and natural gas exploration and production industry are a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting and release of fugitive emissions of natural gas could have a significant impact on our future operations.  The EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows the EPA to regulate GHG emissions under existing provisions of the federal Clean Air Act.  The 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 GHG emissions would likely require us to incur increased operating costs and could have an adverse effect on demand for our production.  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 – Governmental Regulation - 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.

Hydraulic fracturing has recently come under increased scrutiny and could be the subject of further regulation, which could impact the timing and cost of development, as well as our investment in RockPile. 

As discussed above in Item 1. Business – Governmental Regulation - Regulation of Hydraulic Fracturing, the regulatory landscape regarding hydraulic fracturing remains in flux.  Depending on the legislation or regulations that ultimately may be adopted, exploration and production activities that employ hydraulic fracturing could be restricted or subject to additional regulation and permitting requirements.  Individually or collectively, such new legislation or regulation could lead to operational delays or increased operating costs for TUSA and RockPile, and could result in additional burdens that could increase the costs and delay or curtail the development of unconventional oil and natural gas

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resources from shale formations that are not commercially viable without hydraulic fracturing.  Further, commercially prohibitive costs or a prohibition or moratorium on hydraulic fracturing in the areas in which RockPile operates could result in a complete loss of our investment in RockPile.  As a result, such legislation or regulation could have a material adverse effect on our business, financial condition and results of operations.

The sale of our oil and natural gas production depends in part on gathering, transportation and processing facilities and services.  Any limitation in the availability of, or our access to, those facilities or services 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 Caliber does 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.  In addition, the use of alternative forms of transportation for oil production, such as trucks or rail, involve risks as well.  For example, recent and well-publicized accidents involving trains delivering crude oil could result in increased levels of regulation and transportation costs. 

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 productionand could force us to reduce production in some circumstances.  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, 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 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.

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 from strong commodity prices in the future, 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.  Costs associated with hydraulic fracturing, such as costs relating to water and proppants, may be subject to similar pressures in areas such as the Williston Basin where hydraulic fracturing activities are widespread.  Moreover, costs in the Williston Basin generally are high relative to many areas of the United States due to its rapid growth in recent years and its distance from major metropolitan areas. Conversely, while certain costs could potentially decrease when commodity prices fall, we may be unable to realize such potential reductions or they may be less significant than we project.

Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely and cost-effective manner.

Water is an essential component of our drilling and hydraulic fracturing processes. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, NGLs and gas, which could have an adverse effect on our business, financial condition and results of operations.

Moreover, new environmental initiatives and regulations could include restrictions on disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or

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production of oil and natural gas. Compliance with environmental regulations and permit requirements for the withdrawal, storage and use of surface water or ground water necessary for hydraulic fracturing of our wells may increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations and cash flows.

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.  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 RockPile’s 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.

We intend to grow Caliber’s business through the construction of pipelines, treatment/processing facilities and other midstream infrastructure.  The construction of this infrastructure requires 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, 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 give the producers the right to 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 those estimates may prove to be inaccurate because of the numerous uncertainties inherent in estimating quantities of proved reserves.  As a result, new infrastructure projects may be unprofitable.

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 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;

abnormally pressured formations;

fires and explosions;

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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.  Also, certain risk events may not be detected or detectable within the period during which notice must be provided under the applicable insurance policy.  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.

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 long-term 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.  Our vertical integration strategy effectively increases the variety of these projects, which adds complexity and may require additional 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.

Our lack of geographic diversification may 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 than we would if our business were more diversified, and this may increase 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 and numerous independent oil and natural gas companies.  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 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 timelier 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 RockPile is 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, its business could be materially and adversely affected.   

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Seasonal weather conditions and other factors could adversely affect our ability to conduct drilling and completion 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 operations 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 resulting shortages or cost increases, 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, legal 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 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.

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

We restated certain financial information in fiscal years 2013 and 2014 as a result of identifying distinct material weakness in our internal controls. In fiscal year 2014, we identified a material weakness in our controls over the accounting for equity investment derivatives.  Our control for the accounting for equity investment derivatives was not designed to consider all of the relevant accounting literature applicable to our Caliber trigger units and warrants.  This material weakness resulted in a material error in our accounting for equity investment derivatives, and we restated our previously issued quarterly financial statements for the three months ended October 31, 2013.  We have implemented system and procedural changes to prevent previously identified material weaknesses from recurring.  However, our vertical integration strategy and midstream joint venture investment create certain accounting issues relating to the relationship of our various businesses that are complex, increasing the risk that we may have to restate or correct financial disclosures in the future.  If other deficiencies in our internal controls arise in the future, we may be unable to provide holders of our securities with required financial information in a timely and reliable manner.

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. 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, may result in stockholder litigation, may cause us to fail to meet our reporting obligations, and may cause investors to lose confidence in our reported financial information, leading to a decline in our stock price.

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.

President Obama has proposed changes to U.S. tax laws that would eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies, including by (i) repealing the percentage depletion allowance for oil and natural gas wells, (ii) eliminating current deductions for intangible drilling and development costs, (iii) eliminating the deduction for certain domestic production activities, and (iv) extending 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

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and oil resources.  Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

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.  Our business partners, including vendors, service providers, operating partners, purchasers of our production, and financial institutions, face similar threats, including with respect to sensitive information of ours.There can be no assurance that the procedures and controls we or our business partners use to monitor these threats and mitigate 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 in Montana or North Dakota.  However, if a claim arose and was successful, it could have an adverse effect on us and our business operations, financial conditions or prospects.

Certain stockholders have 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 to NGP Triangle Holdings, LLC (“NGP”) in July 2012 of our 5% convertible note with an initial principal amount of $120.0 million (the “Convertible Note”), we entered into an Investment Agreement with 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, which is paid-in-kind by adding to the principal balance on a quarterly basis.

In March 2013, we sold to two affiliates of NGP an aggregate of 9,300,000 shares of our common stock in a private placement (the “NGP Private Placement”).  In connection with the NGP 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.  As of April 1, 2015, NGP’s affiliates collectively held (i) 9,300,000 shares of our outstanding common stock and (ii) the Convertible Note with an outstanding principal balance of approximately $135.9 million.  If NGP had fully converted the Convertible Note on April 1, 2015, NGP and its affiliates would have collectively held approximately 29% of our outstanding shares of common stock on that date.  As a result of the Investment Agreement, as amended, and NGP’s current and potential holdings of our common stock, NGP has significant influence over us, our management, our policies, and certain matters requiring stockholder approval.

Further, in August 2013, we sold to ActOil Bakken, LLC (“ActOil”) 11,350,000 shares of our common stock in a private placement.  As of April 1, 2015, ActOil held approximately 15% of our outstanding shares of common stock.

The interests of NGP and its affiliates, including in NGP’s capacity as a creditor, and ActOil may differ from the interests of our other stockholders, and the ability of NGP and ActOil to influence certain of our major corporate decisions

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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.

Our limited partner interest in Caliber may be diluted.

In October 2012, a wholly-owned subsidiary of ours participated in the formation of Caliber,  a joint venture with FREIF to provide crude oil, natural gas, and water transportation and related services to us and third-parties primarily in the Williston Basin.  In connection with its investment in Caliber, our subsidiary received an initial 30% percent limited partner interest, as well as warrants to purchase additional limited partner interests at specified prices, trigger units, and trigger warrants.  Based on initial anticipated funding commitments by the joint venture partners, full exercise and vesting of our warrants, trigger units, and trigger warrants would cause our ownership to increase to a 50% limited partner interest. 

In September 2014,  FREIF committed to providing an anticipated additional $80.0 million to Caliber in return for 8,000,000 limited partner units.  The associated amendment to the joint venture agreement resulted in our 4,000,000 trigger units vesting and converting to limited partner units.  FREIF and our subsidiary received the 8,000,000 and 4,000,000 limited partner units, respectively, on June 30, 2014.  Following the conversion of our 4,000,000 trigger units and the issuance of 8,000,000 limited partner units to our joint venture partner, our limited partner interest in Caliber increased to 32%.

In February 2015, FREIF contributed an additional $34.0 million to Caliber in exchange for 2,720,000 limited partner units, which diluted our limited partner interest to 28.3%.  In conjunction with the contribution, we received warrants to purchase an additional 3,626,667 limited partner units, and FREIF received warrants to purchase an additional 906,667limited partner units.  On a fully-diluted basis, assuming the exercise of all outstanding warrants and no further capital contributions, we and FREIF would each hold a 50% percent limited partner interest in Caliber.

We will be unable to increase our limited partner interest above 28.3% absent a cashless exercise of our warrants or a direct capital outlay to exercise our warrants or commit additional partnership approved capital.  Further, if FREIF makes a partnership approved capital contribution and we choose not to invest additional capital in the joint venture, or if FREIF exercises its warrants and we do not exercise our warrants, we would be diluted below our 28.3% limited partner interest.

We do not control Caliber.

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. Because we do not hold a controlling interest in Caliber, we do not have the ability to direct the activities of Caliber that most significantly impact Caliber’s growth and economic performance.  If we and the other general partner disagree on significant matters relating to Caliber, such an impasse could adversely affects Caliber’s prospects and our investment therein.

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 more predictable cash flows.  These arrangements expose us to the risk of financial loss in some circumstances, including when sales are different than expected, when there is a change in the expected differential between the underlying price in the derivative agreement and actual prices that we receive, or if the counterparty to the derivative contract were to default on its contractual obligations.

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

35

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.

Unrelated to our hedging activities with respect to crude oil prices, we hold warrants in Caliber that are classified as derivatives.  For so long as such warrants remain outstanding, we will be required to estimate their fair market value on a quarterly basis.  We currently use a modified market approach and Black-Scholes option pricing model to value the warrants.  The associated model is based on several assumptions about future events.  While we believe that our model and underlying assumptions are reasonable, there can be no assurance that the assumptions will ultimately prove to be accurate or that our modelis the best model for valuing the warrants.  If the model and underlying assumptions are flawed, then our accounting for the warrants may not reflect their true value.

Most of our commodity derivatives expire by December 31, 2015.

As of January 31, 2015, we had costless collar commodity derivative contracts for 4,356 Bbl/d with a weighted average put strike price of $86.85 and a weighted average call strike price of $98.63 (NYMEX).  These contracts expire by December 31, 2015.  Subsequent to January 31, 2015, the Company entered into crude oil swaps at a weighted average price of $60.07 for 1,500 Bbl/d (NYMEX), effective for the period from October 1, 2015 through December 31, 2016, and crude oil swaps at a weighted average price of $60.30 for 500 Bbl/d (NYMEX), effective for the period from January 1, 2016 through December 31, 2016.  Once our costless collar contracts expire, our commodity derivatives may be limited to those contracts that we have entered into in a depressed pricing environment.  As such, our crude oil production and sales for fiscal year 2017 and beyond may be largely unhedged, or hedged at depressed prices, which will expose us to continued volatility in crude oil market prices, whether favorable or unfavorable.

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:

changes in oil and natural gas prices;

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

liquidity;

sales of common stock by our stockholders, directors, and officers;

changes in our cash flows 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, including adverse public sentiment regarding hydraulic fracturing;

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

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

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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.

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 or private offerings of our common stock, in amounts and at prices and terms to be 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 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 our common stock and could impair our future ability to raise capital through an offering of our equity securities.

The potential future issuance of preferred stock may not enhance stockholder value.

Our Certificate of Incorporation authorizes our board of directors to issue preferred stock without stockholder approval. Shares of preferred stock could be issued in a financing in which investors purchase preferred stock with rights, preferences and privileges that may be superior to those of our common stock.  We could also use the preferred stock for potential strategic transactions, including, among other things, acquisitions, strategic partnerships, joint ventures, restructurings, business combinations and investments.  We cannot provide assurances that any such transactions will be consummated on favorable terms or at all, that they will enhance stockholder value, or that they will not adversely affect our business or the trading price of the common stock.  Further, the existence of outstanding preferred stock may make us a less attractive candidate for third party acquirers.

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 flows 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, limits imposed by our debt agreements, and such other factors as our board of directors deems relevant.

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

We are subject to Section 203 of the Delaware General Corporation Law, 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 stockand that might be supported by a majority of our stockholders.

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ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

The information required by Item 2. Properties is contained in Item 1. Business of this annual report.

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.  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 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

Not applicable.

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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 under the symbol “TPLM.”  The table below sets forth the intraday high and low sales prices for our common stock in each quarter of the last two fiscalyears:

	Fiscal Year 2015
	High		Low
February 1, 2014 to April 30, 2014	$	10.10	$	6.96
May 1, 2014 to July 31, 2014	$	12.48	$	9.05
August 1, 2014 to October 31, 2014	$	12.14	$	6.75
November 1, 2014 to January 31, 2015	$	8.10	$	3.10

	Fiscal Year 2014
	High		Low
February 1, 2013 to April 30, 2013	$	7.32	$	4.85
May 1, 2013 to July 31, 2013	$	7.93	$	5.10
August 1, 2013 to October 31, 2013	$	11.66	$	6.37
November 1, 2013 to January 31, 2014	$	11.36	$	7.46

Holders

Our 75,288,381 shares of common stock outstanding at April 1, 2015 were held by 17 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 and capital requirements, limitations imposed by applicable law and the terms of our debt agreements, and such other factors as our board of directors deems relevant.

Sales of Unregistered Equity Securities

We had no sales of unregistered equity securities during fiscal year 2015.

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Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes our purchases of shares of our common stock during the fiscal quarter ended January 31, 2015:

					Total number of	Maximum number
					shares purchased	of shares that may
	Total Number		Average		as part of publicly	yet be purchased
	of Shares		Price Paid		announced plans	under the plans
	Purchased		Per Share		(2)	at month end
November 1, 2014 to November 30, 2014	2,208,631		$	6.71	2,201,700	9,038,876	(3)
December 1, 2014 to December 31, 2014	4,311,480			4.03	4,298,300	4,949,393	(4)
January 1, 2015 to January 31, 2015	19,484			4.78	—	4,949,393
	6,539,595	(1)	$	4.94	6,500,000

(1) Includes 39,595 shares of common stock surrendered by certain employees to the Company in satisfaction of their tax liability upon the vesting of their restricted stock units. The number of shares of common stock actually issued to such employees upon the vesting of their restricted stock units was net of the shares surrendered in satisfaction of their tax liability. The withheld shares are not issued or considered common stock repurchased under the repurchase program described below.

(2) As reported in Current Reports on Form 8-K filed with the SEC on September 11, 2014 and October 17, 2014, the Company’s Board of Directors approved a program authorizing the repurchase of outstanding shares of the Company’s common stock in amounts equal to the aggregate of (i) $25.0 million of the Company’s common stock (“Tranche 1”), (ii) up to the number of shares of common stock authorized for issuance under the Company’s 2014 Equity Incentive Plan and its CEO Stand-Alone Stock Option Agreement (“Tranche 2”), and (iii) up to the number of shares potentially issuable, at any given time, pursuant to the paid-in-kind interest accrued on the Convertible Note (“Tranche 3”). Shares repurchased under the program may be repurchased from time to time, in amounts and at prices that the Company deems appropriate, subject to market and business conditions and other considerations. The repurchase program may be executed using open market purchases pursuant to Rule 10b-18 under the Exchange Act, pursuant to a Rule 10b5-1 plan, in privately negotiated agreements, or other transactions. The repurchase program has no expiration date and may be suspended or discontinued at any time without prior notice. As of January 31, 2015, an aggregate of 11,431,744 shares of the Company’s common stock have been repurchased under the program.

(3) Includes the number of shares remaining available for repurchase pursuant to Tranche 2, plus the number of shares available for repurchase pursuant to Tranche 3 based on the paid-in-kind interest accrued on the Convertible Note as of September 30, 2014. All shares authorized for repurchase under Tranche 1, as well as a portion of the shares authorized for repurchase under Tranche 2, were exhausted during the fiscal quarter ended October 31, 2014.

(4) Includes an additional 208,817 shares potentially issuable pursuant to the paid-in-kind interest added to the principal balance of the Convertible Note on December 31, 2014.

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Performance Graph

The following graph compares our common stock’s performance with the performance of the Standard & Poor’s 500 Stock Index and the Dow Jones U.S. Oil and Gas Index for the period beginning January 31, 2010 through January31, 2015.  The graph assumes the value of the investment in our common stock and in each index was $100 on January31, 2010 and that any dividends were reinvested.  The common stock performance shown on the graph below is not indicative of future price performance.  The information provided in this section is being furnished to, and not filed with, the SEC.  As such, this information is neither subject to Regulation 14A or 14C nor to the liabilities of Section 18 of the Exchange Act.

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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, 2011 through January 31, 2015.  The data as of and for the 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 Form10-K or 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 Years Ended January 31,
(in thousands, except per share data)	2015		2014		2013		2012		2011
Operating results:
Oil, natural gas, and natural gas liquids sales	$	284,502	$	160,548	$	39,614	$	8,136	$	564
Oilfield services		288,453		98,199		20,747		—		—
Total revenue	$	572,955	$	258,747	$	60,361	$	8,136	$	564
Total operating expenses	$	477,572	$	211,785	$	68,622	$	33,111	$	20,900
Net income (loss) attributable to common stockholders	$	93,397	$	73,480	$	(13,760)	$	(24,278)	$	(20,277)
Income (loss) per share to common stockholders:
Basic	$	1.12	$	1.07	$	(0.31)	$	(0.60)	$	(1.63)
Diluted	$	0.97	$	0.91	$	(0.31)	$	(0.60)	$	(1.63)
Total assets	$	1,654,870	$	1,027,522	$	428,321	$	229,845	$	82,031
Long-term obligations	$	838,010	$	345,054	$	148,788	$	83	$	1,404
Cash flows data:
Net cash provided by (used in) operating activities	$	200,817	$	82,436	$	2,764	$	(12,766)	$	(3,541)
Net cash used in investing activities	$	(577,019)	$	(455,566)	$	(179,712)	$	(111,046)	$	(16,100)
Net cash provided by financing activities	$	362,323	$	421,763	$	141,250	$	134,854	$	72,534
Proved reserves:
Oil (Mbbls)		48,091		31,916		12,540		1,365		1,236
Natural gas (MMcf)		40,185		26,504		12,585		674		—
NGL (Mbbls)		4,081		3,981		—		—		—
Total equivalent (MBoe)		58,870		40,314		14,637		1,477		1,236

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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 of this annual report.

Overview

We are an independent energy holding company with three principal lines of business: oil and natural gas exploration, development and production; oilfield services; and midstream services.  We conduct these activities primarily in the Williston Basin of North Dakota and Montana through TUSA and RockPile, the Company’s two principal wholly-owned subsidiaries, and Caliber, our joint venture with FREIF.

Summary of Fiscal Year 2015 Highlights

During fiscal year 2015, we accomplished the following:

· Production volumes totaled 4,176 Mboe for the year ended January 31, 2015, compared to 1,929 Mboe for the year ended January 31, 2014, an increase of 116%.

· Oil, natural gas and natural gas liquids sales in the year ended January 31, 2015 were $284.5 million compared to $160.5 million for the year ended January 31, 2014, an increase of 77%.

· Oilfield services revenue in fiscal year 2015 was $288.5 million compared to $98.2 million for fiscal year 2014 as RockPile increased its sales to third party customers. The total gross profit contribution from our oilfield services operations grew to $56.1 million for fiscal year 2015, as compared to $10.5 million for fiscal year 2014 and oilfield services gross profit percentages improved to 19.4% for fiscal year 2015 compared to 10.7% for fiscal year 2014.  

· Income from operations was $95.4 million for the year ended January 31, 2015, compared to $47.0 million for the year ended January 31, 2014.

· Cash flows provided by operating activities were $200.8 million for the year ended January 31, 2015 compared to $82.4 million for the year ended January 31, 2014.

· TUSA spud 62 gross (43.9 net) operated wells and completed 49 gross (34.5 net) operated wells during the year ended January 31, 2015.

· TUSA acquired approximately 41,100 net acres in Williams County, North Dakota and Sheridan and Roosevelt Counties, Montana for approximately $90.4 million in June 2014.

· TUSA increased proved reserves from approximately 40,314 Mboe at January 31, 2014 to 58,870 Mboe at January 31, 2015, an increase of approximately 46%.

· TUSA issued $450.0 million aggregate principal amount of 6.75% Senior Notes due 2022 of which $429.5 was outstanding at January 31, 2015.

· TUSA and RockPile amended their credit facilities to provide for additional borrowing capacity and operational flexibility.

· RockPile completed 49 TUSA wells and 99 third-party wells in fiscal year 2015, as compared to 31 TUSA wells and 50 third-party wells in fiscal year 2014.

· RockPile deployed into service its third and fourth hydraulic fracturing spreads.

· Caliber flowed crude oil through its Alexander Market Center, providing stabilization as well as additional takeaway optionality via pipeline and truck to rail (both inbound and outbound loading services).

Summary of Operating Results

The following table reflects the components of our production volumes, average realized prices, oil, natural gas and natural gas liquids revenues, and operating expenses for the periods indicated.  No pro forma adjustments have been

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made for the acquisitions and divestitures of oil and natural gas properties, which will affect the comparability of the data below.  The information set forth below is not necessarily indicative of future results.

	For the Years Ended January 31,
Oil and Natural Gas Operations	2015		2014		2013
Production volumes:
Crude oil (Mbbls)		3,511		1,754		452
Natural gas (MMcf)		2,429		626		188
Natural gas liquids (Mbbls)		260		70		5
Total barrels of oil equivalent (Mboe)		4,176		1,929		488
Average daily production volumes (Boe/d)		11,441		5,286		1,334
Average realized prices:
Crude oil ($ per Bbl)	$	75.00	$	88.07	$	85.29
Natural gas ($ per Mcf)	$	5.27	$	4.39	$	4.78
Natural gas liquids ($ per Bbl)	$	32.26	$	46.72	$	36.01
Total average realized price ($ per Boe)	$	68.13	$	83.22	$	81.15
Oil, natural gas and natural gas liquids revenues (in thousands):
Crude oil	$	263,310	$	154,507	$	38,533
Natural gas		12,804		2,748		899
Natural gas liquids		8,388		3,293		182
Total oil, natural gas and natural gas liquids revenues	$	284,502	$	160,548	$	39,614
Operating expenses (in thousands):
Lease operating expenses	$	25,703	$	14,454	$	3,566
Gathering, transportation and processing		18,520		4,302		150
Production taxes		29,774		18,006		4,492
Oil and natural gas amortization expense		106,903		50,991		13,548
Accretion of asset retirement obligations		167		56		184
Total operating expenses	$	181,067	$	87,809	$	21,940
Operating expenses per Boe:
Lease operating expenses	$	6.15	$	7.49	$	7.31
Gathering, transportation and processing	$	4.43	$	2.23	$	0.31
Production taxes	$	7.13	$	9.33	$	9.20
Oil and natural gas amortization expense	$	25.60	$	26.43	$	27.75

Results of operations for the year ended January 31, 2015 compared to the year ended January 31, 2014

Oil, Natural Gas and Natural Gas Liquids Revenues.  Revenues from oil, natural gas and natural gas liquids production for the year ended January 31, 2015 increased 77% to $284.5 million from $160.5 million for the year ended January 31, 2014, primarily due to the significant increase in oil production from new wells and the acquisition of producing wells in the third quarter of fiscal year 2014 and the second quarter of fiscal year 2015, partially offset by normal production declines and pricing declines in oil and natural gas liquids.  Average realized oil prices for the year ended January, 31 2015 decreased to $75.00 per barrel from $88.07 per barrel for the year ended January 31, 2014.  In addition, during the year ended January 31, 2015, we experienced increases in both our volumes of natural gas and natural gas liquids sold as a result of expanding gathering, transportation and processing infrastructure. 

Lease Operating Expenses.  Lease operating expense decreased to $6.15 per Boe for the year ended January 31, 2015 from $7.49 per Boe for the year ended January 31, 2014.  The cost decrease is primarily the result of efficiencies generated from operating more wells with labor and power costs spread across increased production.

Gathering, Transportation and Processing.  Gathering, transportation and processing (“GTP”) expenses increased to $4.43 per Boe for the year ended January 31, 2015 from $2.23 per Boe for the year ended January 31, 2014, primarily

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because in the third quarter of fiscal year 2014 we commenced gathering, transporting and processing significant amounts of our natural gas production that had previously been flared.  Going forward, we expect our GTP costs to continue to increase (along with our revenues) as Caliber’s and others’ crude oil and natural gas gathering, transportation and processing infrastructure becomes available for operated wells, allowing us to sell oil, natural gas and natural gas liquids downstream, rather than selling at the wellhead or flaring wet natural gas at the wellhead. 

Production Taxes.  The 77% increase in oil, natural gas and natural gas liquids revenues for the year ended January 31, 2015 was the primary reason for the 65% increase in production taxes in fiscal year 2015 to $29.8 million from $18.0 million for fiscal year 2014.  Production taxes decreased to $7.13 per Boe for the year ended January 31, 2015 from $9.33 per Boe for the year ended January 31, 2014 because natural gas and natural gas liquids are becoming a larger portion of our total Boe sales and natural gas and natural gas liquids have lower tax rates than crude oil.

Oil and Natural Gas Amortization.  Oil and natural gas amortization expense increased 110% to $106.9 million for the year ended January 31, 2015 from $51.0 million for the year ended January 31, 2014.  The increase is primarily related to increased production in fiscal year 2015 as compared to fiscal year 2014.  On a per Boe basis our oil and natural gas amortization expense decreased by $0.83 from $26.43 for the year ended January 31, 2014 to $25.60 for the year ended January 31, 2015. This decrease was primarily due to increases in proved reserves from successful development operations, field extensions, and the acquisition of additional oil and natural gas properties.

Oilfield Services Gross Profit.  RockPile commenced operations in July 2012.  We formed RockPile with strategic objectives to have both greater control over one of our largest cost centers as well as to provide locally-sourced, high-quality completion services to TUSA and other operators in the Williston Basin.  Since formation, RockPile has been focused on procuring new oilfield and complementary well completion equipment, building physical and supply chain infrastructure in North Dakota, recruiting and training employees, and establishing third-party customers.  RockPile’s results of operations are affected by a number of variables including drilling and stimulation activity, pricing environment, service performance, equipment utilization, and the ability to secure and retain third-party customers. 

For the year ended January 31, 2015, RockPile performed hydraulic fracturing, cased-hole wireline, pressure pumping and workover services for TUSA and 11 third-party customers.  Equipment utilized to perform these services consisted of four spreads, six wireline trucks, and five workover rigs.  Hydraulic fracturing services resulted in 148 total well completions: 49 for TUSA and 99 for third-parties.  Pressure pumping direct costs include the cost of chemicals and proppant, labor (wages and benefits), logistics expenses, insurance, repairs and maintenance, and safety costs.  Cost of goods sold as a percentage of revenue will vary based upon completion design and equipment utilization.

We recognized $56.1 million and $10.5 million of gross profit from oilfield services for the years ended January 31, 2015 and 2014, respectively, after elimination of $38.9 million and $31.9 million in fiscal year 2015 and fiscal year 2014, respectively, of intercompany gross profit.

The table below summarizes the RockPile contribution to our consolidated results for the years ended January 31, 2015 and 2014:

	For the Year Ended January 31, 2015						For the Year Ended January 31, 2014
(inthousands)	OilfieldServices		Eliminations		Consolidated		OilfieldServices		Eliminations		Consolidated
Revenues
Oilfield services	$	418,103	$	(129,650)	$	288,453	$	193,625	$	(95,426)	$	98,199
Total revenues		418,103		(129,650)		288,453		193,625		(95,426)		98,199
Cost of sales
Oilfield services		301,142		(84,854)		216,288		142,339		(60,012)		82,327
Depreciation		22,008		(5,899)		16,109		8,905		(3,542)		5,363
Total cost of sales		323,150		(90,753)		232,397		151,244		(63,554)		87,690
Gross profit	$	94,953	$	(38,897)	$	56,056	$	42,381	$	(31,872)	$	10,509

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General and Administrative Expenses.  The following table summarizes general and administrative expenses for the years ended January 31, 2015 and 2014:

	For the Year Ended January 31, 2015								For the Year Ended January 31, 2014
	Exploration and		Oilfield				Consolidated		Exploration and		Oilfield				Consolidated
(in thousands)	Production		Services		Corporate		Total		Production		Services		Corporate		Total
Salaries and benefits	$	6,028	$	14,620	$	11,559	$	32,207	$	3,541	$	6,894	$	6,864	$	17,299
Stock-based compensation		1,155		509		6,255		7,919		1,127		590		6,113		7,830
Other general and administrative		9,042		10,598		2,991		22,631		3,939		4,222		1,339		9,500
Total	$	16,225	$	25,727	$	20,805	$	62,757	$	8,607	$	11,706	$	14,316	$	34,629

Total general and administrative expenses increased $28.2 million to $62.8 million for the year ended January 31, 2015 compared to $34.6 million for the year ended January 31, 2014.  The increase in corporate general and administrative expenses is primarily a result of increased compensation and benefit costs for personnel due to the growth of the business.  Salaries and benefits for the year ended January 31, 2015 also includes an accrual for a transaction bonus of $1.9 million due to our President and Chief Executive Officer.  During the year ended January 31, 2015, we incurred a $1.3 million charge associated with the write off of software implementation costs associated with a land and accounting system conversion that is no longer contemplated.

Commodity Derivatives.  We have entered into commodity derivative instruments, primarily costless collars and swaps, to reduce the effect of price changes on a portion of our future oil production.  Our commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities.  During the year ended January 31, 2015, we recognized a $64.1 million gain on our commodity derivative positions due to decreases in underlying crude oil prices, as compared to a gain of $1.1 million for the year ended January 31, 2014.  The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled, and we will likely add to our hedging program.  Therefore, we expect our net income to reflect the volatility of commodity price forward markets.  Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time. We recorded a realized commodity derivative gain of $11.4 million in fiscal year 2015, as compared to a realized commodity derivative loss of $4.6 million in fiscal year 2014.

Income from Equity Investment.  Our equity investment in Caliber consists of Class A Units and equity derivative instruments.  The Company recognized a gain in equity investment derivatives of $0.6 million in fiscal year 2015 and $39.8 million during fiscal year 2014 due to the increase in the fair value of the equity investment derivatives.  The majority of the gain in fiscal year 2014 related to Class A Trigger Units that vested on June 30, 2014.  In addition, during the year ended January 31, 2015, the Company recognized $1.4 million for its share of Caliber’s net income for the period.  This income was offset by $1.3 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in recognized income of $0.1 million. During the year ended January 31, 2014, the Company recognized $2.2 million for its share of Caliber’s net income for the period.  This income was completely offset by $2.2 million of intra-company profit gross recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in no recognized income.

Interest Expense.  The $25.1 million in interest expense for the year ended January 31, 2015 consists of (a) approximately $4.3  million in interest related to the TUSA credit facility, (b) approximately $6.6 million in accrued interest fees related to the Convertible Note, (c) approximately $16.2 million in interest related to the TUSA 6.75% Notes due 2022 (the “TUSA 6.75% Notes”), (d) approximately $2.7 million in interest expense associated with our RockPile credit facility and notes payable, and (e) approximately $0.2 million in interest expense related to our other debt, all net of approximately $4.9 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed.  Approximately $21.4 million of interest expense and capitalized interest was paid in cash. 

The $7.1 million in interest expense for the year ended January 31, 2014 consists of (a) approximately $2.9 million in interest related to the TUSA credit facility, (b) approximately $6.2 million in accrued interest related to our Convertible Note, and (c) approximately $1.0 million in interest expense associated with RockPile’s credit facility and notes payable,

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all net of approximately $3.0 million of capitalized interest.  Approximately $3.6 million of interest expense and capitalized interest was paid in cash.

Income Taxes.  Our fiscal year 2015 income tax provision was $45.5 million compared to $7.9 million in fiscal year 2014.  Our effective tax rate of 32.8% for fiscal year 2015 was less than our U.S. blended statutory rate of 37.6% primarily due to a bad debt deduction taken for amounts owed by our Canadian subsidiary to Triangle that will not be realized because our Canadian operations have ceased except for certain reclamation activities.  We expect future income tax expense to be similar to our U.S. blended statutory rate.  During fiscal year 2014, the effective income tax rate of 10% was less than the U.S. blended statutory rate because Triangle reversed its valuation allowance.  In fiscal year 2014, Triangle determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that the net U.S. deferred tax assets will be realized.

Results of operations for the year ended January 31, 2014 compared to the year ended January 31, 2013

Oil, Natural Gas and Natural Gas Liquids Revenues.  Revenues from oil, natural gas and natural gas liquids production for the year ended January 31, 2014 increased 305% to $160.5 million from $39.6 million for the year ended January 31, 2013, primarily due to the significant increase in oil production from new wells and the acquisition of producing wells in the third quarter of fiscal year 2014, partially offset by normal production declines.  Average realized oil prices for the year ended January, 31 2014 increased to $88.07 per barrel from $85.29 per barrel for the year ended January 31, 2013.  In addition, during the year ended January 31, 2014, we experienced increases in both our volumes of natural gas and natural gas liquids sold as a result of expanding gathering, transportation and processing infrastructure. 

Lease Operating Expenses.  Lease operating expense increased to $7.49 per Boe for the year ended January 31, 2014 from $7.31 per Boe for the year ended January 31, 2013.  The increase in LOE/Boe is primarily the result of a relatively high proportion of oil sales related to sales in fiscal year 2013 for new producing wells (when LOE/Boe is relatively low), and relatively low workover expenses in fiscal year 2013.

Gathering, Transportation and Processing.  GTP expenses increased to $2.23 per Boe for the year ended January 31, 2014 from $0.31 per Boe for the year ended January 31, 2013, primarily because in the third quarter of fiscal year 2014 we commenced gathering, transporting and processing significant amounts of our natural gas production that had previously been flared.  Going forward, we expect our GTP costs to continue to increase (along with our revenues) as Caliber’s crude oil and natural gas gathering, transportation and processing infrastructure becomes available for operated wells, allowing us to sell oil, natural gas, and natural gas liquids downstream, rather than selling at the wellhead or flaring wet natural gas at the wellhead. 

Production Taxes.  The 305% increase in oil, natural gas and natural gas liquids revenues for the year ended January 31, 2014 is the primary reason our production taxes increased approximately 301% to $18.0 million in fiscal year 2014 from $4.5 million for fiscal year 2013.  Production taxes increased to $9.33 per Boe for the year ended January 31, 2014 from $9.20 per Boe for the year ended January 31, 2013.  North Dakota production tax rates were 11.5% of oil revenue and approximately $0.08 per Mcf of natural gas.

Oil and Natural Gas Amortization.  Oil and natural gas amortization expense increased 276% to $51.0 million for the year ended January 31, 2014 from $13.5 million for the year ended January 31, 2013. The increase is primarily related to increased production in fiscal year 2014 as compared to fiscal year 2013. On a per Boe basis, our oil and natural gas amortization expense decreased by $1.32 from $27.75 for the year ended January 31, 2013 to $26.43 for the year ended January 31, 2014. This decrease was primarily due to increases in proved reserves from successful development operations, field extensions, and the acquisition of additional oil and natural gas properties.

Oilfield Services Gross Profit.  For the year ended January 31, 2014, RockPile performed hydraulic fracturing services, pressure pumping, and workover services for TUSA and six third-party customers.  Equipment utilized to perform these services consisted of two spreads.  Hydraulic fracturing services resulted in 81 total well completions: 31 for TUSA and 50 for third-parties.  Pressure pumping direct costs include the cost of chemicals and proppant, labor (wages and benefits), logistics expenses, insurance, repairs and maintenance, and safety costs.  Cost of goods sold as a percentage of revenue will vary based upon completion design and equipment utilization.

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We recognized $10.5 million and $3.0 million of gross profit from oilfield services for the years ended January31, 2014 and 2013, respectively, after elimination of $31.9 million and $11.8 million in fiscal year 2014 and fiscal year 2013, respectively, of intercompany gross profit.

The table below summarizes the RockPile contribution to our consolidated results for the years ended January31, 2014 and 2013:

	For the Year Ended January 31, 2014						For the Year Ended January 31, 2013
(in thousands)	Oilfield Services		Eliminations		Consolidated		Oilfield Services		Eliminations		Consolidated
Revenues
Oilfield services	$	193,625	$	(95,426)	$	98,199	$	57,207	$	(36,460)	$	20,747
Total revenues		193,625		(95,426)		98,199		57,207		(36,460)		20,747
Cost of sales
Oilfield services		142,339		(60,012)		82,327		39,534		(22,928)		16,606
Depreciation		8,905		(3,542)		5,363		2,857		(1,732)		1,125
Total cost of sales		151,244		(63,554)		87,690		42,391		(24,660)		17,731
Gross profit	$	42,381	$	(31,872)	$	10,509	$	14,816	$	(11,800)	$	3,016

General and Administrative Expenses.  The following table summarizes general and administrative expenses for the years ended January 31, 2014 and 2013:

	For the Year Ended January 31, 2014								For the Year Ended January 31, 2013
	Explorationand		Oilfield				Consolidated		Exploration and		Oilfield				Consolidated
(in thousands)	Production		Services		Corporate		Total		Production		Services		Corporate		Total
Salaries and benefits	$	3,541	$	6,894	$	6,864	$	17,299	$	4,367	$	8,422	$	1,959	$	14,748
Stock-based compensation		1,127		590		6,113		7,830		2,507		617		3,342		6,466
Other general and administrative		3,939		4,222		1,339		9,500		2,223		2,708		2,398		7,329
Total	$	8,607	$	11,706	$	14,316	$	34,629	$	9,097	$	11,747	$	7,699	$	28,543

Total general and administrative expenses increased $6.1 million to $34.6 million for the year ended January31, 2014 compared to $28.5 million for the year ended January 31, 2013.  The increase in corporate general and administrative expenses is primarily a result of increased compensation and benefit costs for personnel due to the growth of the business. 

Commodity Derivatives.  We have entered into commodity derivative instruments, primarily costless collars and swaps, to reduce the effect of price changes on a portion of our future oil production.  Our commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities.  During the year ended January31, 2014, we recognized a $1.1 million gain on our commodity derivative positions due to decreases in underlying crude oil prices, as compared to a loss of $3.6 million for year ended January31, 2013.  The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled, and we will likely add to our hedging program.  Therefore, we expect our net income to reflect the volatility of commodity price forward markets.  Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time.  We recorded a realized commodity derivative loss of $4.6 million in fiscal year 2014, and we had no realized commodity derivative gain or loss in fiscal year 2013.

Income from Equity Investment.  Our equity investment in Caliber consists of Class A Units and equity derivative instruments.  Due to the increase in the fair value of the equity investment derivatives during the year ended January 31, 2014, the Company recognized a gain in equity investment derivatives of $39.8 million.  During the year ended January31, 2014, the Company recognized $2.2 million for its share of Caliber’s net income for the period.  This income, however, was completely offset by $2.2 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in no recognized income.  During the year ended January 31, 2013, the Company recognized a $0.3 million loss for its share

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of Caliber’s net loss for the period.  Caliber was formed in October 2012 and began water transportation and disposal operations in January 2013.

Interest Expense.  The $7.1 million in interest expense for the year ended January 31, 2014 consists of (a)approximately $2.9 million in interest related to the TUSA credit facility, (b) approximately $6.2 million in accrued interest related to the Convertible Note and (c) approximately $1.0 million in interest expense associated with RockPile’s credit facility and notes payable, all net of approximately $3.0 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed.  Approximately $3.6 million of interest expense and capitalized interest was paid in cash.

The$2.7 million in interest expense for the year ended January 31, 2013 is primarily related to our Convertible Note with NGP.

Income Taxes.  Our fiscal year 2014 income tax provision was $7.9 million compared to zero provision in fiscal year 2013.  As of fiscal year 2013, the Company placed a full valuation allowance against deferred income taxes.  During fiscal year 2014, Triangle determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that the net U.S. deferred tax assets will be realized.  Therefore, all deferred tax benefits were recognized in fiscal year 2014 and the full valuation allowance was removed as part of the effective tax rate.

Liquidity and Capital Resources

Our liquidity is highly dependent on the prices we receive for the oil, natural gas and natural gas liquids we produce.  Commodity prices are market driven and are historically volatile.  Prices received for production heavily influence our revenue, cash flows, profitability, access to capital and future rate of growth.  In addition, commodity prices received by exploration and production companies in the Williston Basin may affect the level of drilling activity there, and therefore may affect the demand for services provided by RockPile and/or Caliber.

In fiscal year 2015, our average realized price for oil was $75.00 per barrel, a decrease of 15% over the average realized price for fiscal year 2014.  This reflected a dramatic decrease in the price of oil that occurred over the second half of fiscal year 2015 and has continued into fiscal year 2016.  Future prices for oil will likely continue to fluctuate due to supply and demand factors, seasonality and other geopolitical and economic factors.  We manage volatility in commodity prices by maintaining flexibility in our capital investment program.  In addition, we periodically hedge a portion of our oil production to mitigate our potential exposure to price declines and the corresponding negative impact on cash flows available for investment.

As of January 31, 2015, we had cash of approximately $67.9 million consisting primarily of cash held in bank accounts, as compared to approximately $81.8 million at January 31, 2014. At January 31, 2015, we also had available borrowing capacity of $315.7 million under the TUSA credit facility and $45.1 million under the RockPile credit facility.

As of January 31, 2015, we had approximately $800.1 million of long-term debt outstanding, of which $429.5 million was attributable to the TUSA 6.75% Notes, $135.9 million was attributable to our Convertible Note (which is convertible into the Company’s common stock at a conversion rate of one share per $8.00 of principal outstanding), $119.3 million was attributable to the TUSA credit facility, $104.9 million was attributable to the RockPile Credit Facility, and $10.6 million was attributable to other notes and mortgages outstanding.

Cash Flows

The following is a summary of our changes in cash and cash equivalents for the fiscal years ended January 31, 2015, 2014 and 2013:

	For the Years Ended January 31,
(inthousands)	2015		2014		2013
Net cash provided by operating activities	$	200,817	$	82,436	$	2,764
Net cash used in investing activities		(577,019)		(455,566)		(179,712)
Net cash provided by financing activities		362,323		421,763		141,250
Net increase (decrease) in cash and equivalents	$	(13,879)	$	48,633	$	(35,698)

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Net Cash Provided by Operating Activities.Cash flows provided by operating activities were $200.8 million for the year ended January 31, 2015, as compared to $82.4 million for the year ended January 31, 2014.  The increase in operating cash flows was primarily due to higher oil revenues driven by higher sales volumes and increased contributions from RockPile, partially offset by related increases in operating expenses during the period.

Cash flows provided by operating activities were $82.4 million for the year ended January 31, 2014, as compared to $2.8 million for the year ended January 31, 2013. 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.During the year ended January 31, 2015, we used $577.0 million in cash in investing activities compared to $455.6 million during the year ended January 31, 2014.  During both years, our primary uses of cash flows in investing activities were related to our oil and natural gas property expenditures.  During the years ended January 31, 2015 and 2014, we used $359.1 million and $279.5 million, respectively, on oil and natural gas property expenditures.  During the years ended January 31, 2015 and 2014, we also used $138.8 million and $121.6 million, respectively, to acquire oil and natural gas properties. During the years ended January 31, 2015 and 2014, we spent $59.6 million and $27.4 million, respectively, on purchases of oilfield services equipment. During the years ended January 31, 2015 and 2014, we also spent $26.7 million and $10.9 million, respectively, on other property and equipment, namely facility construction and improvements.

During the year ended January 31, 2014, investing activities used $455.6 million in cash compared to $179.7 million for the year ended January 31, 2013. The increase in cash flows used in investing activities in fiscal year 2014 was primarily due to our acquisition of properties during the year ended January 31, 2014 and the associated increase in capital investment. Additionally, we invested our remaining commitment of $18.0 million in Caliber.

Net Cash Provided by Financing Activities.Cash flows provided by financing activities for the year ended January31, 2015 totaled $362.3 million, as compared to $421.8 million for the year ended January 31, 2014.  Our primary source of cash from financing activities during the year ended January 31, 2015 came from the issuance of $450.0 million of our TUSA 6.75% Notes, net of repayments on our credit facilities. We also used $76.8 million of cash to repurchase shares of our common stock in the open market and $13.9 million to repurchase and retire TUSA 6.75% Notes with a face value of $20.5 million.  During the year ended January 31, 2014, in addition to net credit facility borrowings, we also had net proceeds of $245.4 million from issuances of our common stock.

Cash flows provided by financing activities for the year ended January 31, 2014 totaled $421.8 million, as compared to $141.3 million for the year ended January 31, 2013.Cash flows provided by financing activities for the year ended January 31, 2013 of $141.3 million were primarily a result of the proceeds from the $120.0 million Convertible Note.

Capital Requirements Outlook

Although our cash flows from operations have historically contributed minimally to funding our capital requirements, specifically with respect to our capital expenditure budget, our fiscal year 2015 cash flows from operations increased significantly over fiscal year 2014.  Nonetheless, our fiscal year 2015 cash flows from operations were insufficient to cover our capital requirements for the year, and we continued to rely heavily on external financing activities.  We believe that the lag time between initial investment and cash flows from such investment is typical of the oil and natural gas industry where upfront costs are significant and cash flows are delayed.  This holds true across our businesses, including drilling and completion costs for TUSA and equipment costs for RockPile. While we are not obligated to fund any further equity commitment for Caliber, the lag time between investment in operations and cash flows is exacerbated in the midstream space where initial construction costs and project timelines are substantial.  In a static oil and natural gas pricing environment, we expect that our cash flows from operations would continue to increase significantly as additional TUSA oil and natural gas wells commence production, RockPile’s oilfield services increase, and Caliber’s gathering and processing system becomes fully operational.  However, we expect that current depressed oil and natural gas prices will reduce our fiscal year 2016 cash flows from operations as compared to fiscal year 2015.

In response to the current oil and natural gas pricing environment, we have significantly reduced discretionary capital expenditures, and we may further adjust such expenditures as market dynamics warrant.  Nonetheless, we will likely remain dependent on borrowings under our credit facilities and, to a lesser extent, potential additional financings to fund the difference between cash flows from operations and our capital expenditures budget and other contractual commitments. 

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Although we expect that our operating cash flows and availability under our credit facilities will be largely sufficient for our capital requirements, any additional shortfall may be financed through additional debt or equity instruments.  There can be no assurance that we will achieve our anticipated future cash flows from operations, that credit will be available when needed, or that we would be able to complete alternative transactions in the capital markets if needed.

We may also continue to pursue significant acquisition opportunities, which may require additional financing.  Our ability to obtain additional 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 industry, and tax burdens due to new tax laws.

If our existing and potential sources of liquidity are not sufficient to allow us to satisfy our commitments and to undertake our currently planned expenditures, particularly if commodity prices remain depressed for an extended period of time, we have the flexibility to alter our development program or divest assets.  Our operatorship of much of our acreage allows us the ability to adjust our drilling and completions schedules in response to changes in commodity prices or the oilfield services environment.  Further, if we are not successful in obtaining sufficient funding on a timely basis on terms acceptable to us, we may be required to curtail our planned expenditures and/or restructure our operations (including further reducing our drilling rig count, which may result in termination fees depending on the timing and requirements of the underlying agreements), which may reduce anticipated future cash flows from operations.  If we are unable to implement our planned exploration and drilling program, we may be unable to service our debt obligations or satisfy our contractual obligations.

Sources of Capital

Cash flows from operations.  We have been able to increase our produced volumes on a quarter over quarter basis for the past three years.  This increase is directly related to the successful development of our operated properties.  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, we would expect our production rates to continue to increase over time as we continue to develop our properties. However, due to the current oil and natural gas pricing environment, we have reduced our drilling rig count, and we plan to delay the completion of certain wells subject to a number of factors, including the price of oil and natural gas at the time, oilfield services and materials costs, and the availability of third party work for RockPile.  Consequently, our production volume growth is expected to slow in fiscal year 2016, and the benefit we receive from any increased production is likely to be less than it was in fiscal year 2015 due to lower realized prices.  If oil and natural gas prices recover sufficiently in fiscal year 2016, we may increase drilling and completion expenditures, which we expect would increase production volumes and cash flows from operations.

Cash flows from our oilfield services segment increased significantly in fiscal year 2015 primarily due to the addition of two hydraulic fracturing spreads, an expansion of RockPile’s complementary oilfield services, and a considerable increase in the amount of work RockPile performed for third parties.  In an effort to remain competitive in the current oil and natural gas pricing environment, RockPile has reduced the fees that it charges to its customers.  As a result of the margin compression on fees charged for services, as well as the likelihood for lower utilization of RockPile services by customers slowing their development operations, we anticipate that RockPile’s cash flow from operations in fiscal year 2016 will be substantially lower than in fiscal year 2015.

Credit facilities. As of January 31, 2015, our maximum credit available under the TUSA credit facility was $1.0 billion, subject to a borrowing base of $435.0 million.  As of January 31, 2015, we had $315.7 million of borrowing capacity available.  The borrowing base under the TUSA credit facility is subject to redetermination on a semi-annual basis by each May 1st and November 1st.  In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year.  We anticipate limited, if any, borrowing base growth in fiscal year 2016, and our borrowing base is expected to be reduced if oil and natural gas prices do not rebound significantly in the near term.  As of January 31, 2015, our maximum credit available under the RockPile credit facility was$150.0 million.  As of January 31, 2015, we had $45.1 million of borrowing capacity available. Notwithstanding a potential borrowing base reduction under the TUSA credit facility, we expect that the substantial borrowing capacity available under our credit facilities will be sufficient to finance any difference between our cash flows from operations and our anticipated capital expenditures.

Securities Offerings. Historically, we have financed our operations, property acquisitions and other capital investments in part from the proceeds of public and private offerings of our equity and debt securities.  We may from time

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to time offer debt securities, common stock, preferred stock, warrants and other securities, or any combination of such securities, in amounts, at prices and on terms announced when and if the securities are offered.  The specifics of any future public offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus or a prospectus supplement at the time of such offering.

Asset Sales.  In the past, our acquisition activities have significantly outpaced our asset sales, which have been generally limited to small, opportunistic divestitures or exchanges of leasehold interests.  In the current depressed commodity pricing environment, we are strategically reviewing our assets to consider monetizing those that may garner attractive prices or are peripheral to our core businesses.  Such assets include, but are not limited to, non-operated acreage, equity investments, equipment, and other real property interests.  If commodity prices remain depressed for an extended period of time and we are unable to fund our operations from other sources of capital, we may be forced to sell portions of our operated Core Acreage or other assets at distressed prices.

Commodity Derivative Instruments

We utilize various derivative instruments in connection with anticipated crude oil sales to reduce the impact of product price fluctuations.  Currently, we utilize costless collars and swaps.  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 they would be 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.

Working Capital

As part of our cash management strategy, we periodically use available funds to reduce amounts borrowed under our credit facilities.  However, due to certain restrictive covenants contained in our credit facilities regarding our ability to dividend or otherwise transfer funds from the borrower to Triangle, we seek to maintain sufficient liquidity at Triangle to manage foreseeable and unforeseeable consolidated cash requirements.  Since our principal source of operating cash flows (proved reserves to be produced in later periods) is not considered working capital, we often have low or negative working capital.  Our working capital was approximately $37.7 million as of January 31, 2015, as compared to approximately $35.5 million at January 31, 2014.

Off-Balance Sheet Arrangements

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

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Contractual Obligations as of January 31, 2015

The following table lists information with respect to our known contractual obligations as of January 31, 2015:

(in thousands)	Payments Due by Period
			Less than						More than
Contractual Obligations	Total		1 year		1 - 3 years		3 - 5 years		5 years
Office leases (a)	$	10,411	$	1,806	$	3,864	$	4,741	$	—
Drilling rigs (b)		10,167		10,167		—		—		—
TUSA credit facilities (c)		119,272		—		—		119,272		—
TUSA 6.75% notes		429,500								429,500
Convertible note principal (d)		120,000		—		—		—		120,000
Convertible note interest (d)		15,877		—		—		—		15,877
Oilfield services (e)		2,296		1,001		1,242		53		—
RockPile credit facilities (f)		104,887		—		—		104,887		—
Other notes payable (g)		10,605		503		3,044		1,258		5,800
Midstream services (h)		359,202		38,131		80,625		61,979		178,467
Asset retirement obligations (i)		8,578		5,391		—		—		3,187
	$	1,190,795	$	56,999	$	88,775	$	292,190	$	752,831

(a) The Company leases office facilities in Denver, Colorado under operating lease agreements that expire in April 2020.  

(b) As of January 31, 2015, the Company was subject to commitments on four drilling rig contracts.  Two of the drilling rig contracts expire in the first quarter of fiscal year 2016, and the remaining contracts expire in the second and fourth quarters of fiscal year 2016.  In the event of early termination of the contracts, the Company would be obligated to pay an aggregate amount of approximately $10.2 million as of January 31, 2015 as required under the terms of the contracts.

(c) Calculated based on our January 31, 2015 outstanding borrowings under the TUSA credit facility of $119.3 million and assumes no principal repayment until the maturity date of October 2018. 

(d) Calculated based on our January 31, 2015 outstanding aggregate principal amount of the 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. 

(e) As of January 31, 2015, RockPile had various commitments for future expenditures relating to equipment for transportation, transloading and storage of bulk commodities and light vehicles, (ii) transloading services and track rental and (iii) transportation equipment management, logistics and maintenance.

(f) Calculated based on outstanding principal borrowings of $104.9 million under RockPile’s credit facility and assumes no principal repayment until the maturity date of March 2019. 

(g) Includes RockPile obligations relating to (i) seller financed notes payable associated with the acquisition of Team Well Service and (ii) three notes payable associated with the redemption of B-1 Units. 

(h) Amounts relate to agreements between TUSA and Caliber North Dakota described in Item 1.“Business - Delivery Commitments.”

(i) Amounts represent our estimate of future asset retirement obligations.  Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. 

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.

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Impact of Inflation and Pricing

Triangle’s transactions are denominated in U.S. dollars. Inflation in the context of oilfield services and goods has historically been significant in the Williston Basin, the primary area in which Triangle operates.  As prices for oil and natural gas increased, associated costs rose. However, in the second half of fiscal year 2015, prices for oil and natural gas decreased dramatically, and associated costs declined as a result. Future higher prices for oil and natural gas may result in increases in the costs of materials, services and personnel. Changes in prices impact Triangle’s revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold.  Price changes also have the potential to affect Triangle’s ability to raise capital, borrow money, and retain personnel.

Critical Accounting Policies

Use of Estimates.  The preparation of financial statements in conformity with GAAP requires us to make appropriate accounting estimates and to make estimates and assumptions that affect the reported amounts of assets and liabilities, revenues and expenses and the disclosure of contingent assets and liabilities.  We consider our critical accounting policies and related estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments.  Changes in facts and circumstances may result in revised estimates and may differ materially from those estimates. 

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.

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.

Companies that follow the full cost method of accounting 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.

At January 31, 2015, the calculated value of the ceiling limitation approximated the carrying value of our oil and natural gas properties subject to the test and no impairment was necessary.  However, Triangle will likely be required to recognize an impairment of oil and natural gas properties in future periods if oil and natural gas prices remain at current prices or continue to decline, or if there is a negative impact on one or more of the other components of the calculation, and such an impairment would likely be material.

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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 4-10(c)(6)(iv)(C) is to be broadly applied such that 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 Rule4-10(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 $0.5 million (after elimination of consolidated intercompany profit), then Triangle cannot recognize the first $0.5 million 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.Amortization of the capitalized costs of oil and natural gas properties, including estimated future development and abandonment costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves.  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, 2015, 39% of our total proved reserves were categorized as proved undeveloped.  All of these proved undeveloped reserves are located in the Bakken Shale formation or Three Forks formation in North Dakota or Montana.  We review and update our reserve estimates at least quarterly.

Commodity Derivatives.  The Company has entered into commodity derivative instruments, primarily utilizing swaps 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

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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 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. 

Equity Investment.  Triangle accounts for its investment in Caliber using the equity method of accounting.  The equity method of accounting requires the investor to recognize its share of the earnings and losses of the investee in the periods in which they are reflected in the accounts of the investee.

The Company holds Class A (Series 1 through Series 4) Warrants in Caliber.  Our equity investment derivatives are measured at fair value and are included on the consolidated balance sheets as derivative assets.  Net gains and losses on equity investment derivatives are recorded based on the changes in the fair values of the derivative instruments and included in our consolidated statements of operations.

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  consolidated 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).

Share-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. 

RevenueRecognition.  All revenue is recognized when persuasive evidence of an arrangement exists, the service is complete, or 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 and risk of ownership have transferred and collectability is reasonably assured.

Oilfield Services Revenue.  The Company enters into arrangements with its customers to provide hydraulic fracturing and other 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 upon the completion of each job. 

Intercompany revenues are eliminated in the consolidated financial statements, and under certain circumstances, service revenue is reduced when service income cannot be recognized under full cost accounting as discussed above.

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Recently Issued Accounting Pronouncements.  In April 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.  ASU 2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures.  The guidance is effective for annual and interim reporting periods beginning after December 15, 2014.  Adoption of this amendment will not have a material effect on our financial position or results of operations.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, issued as a new Topic, Accounting Standards Codification Topic 606.  The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized.  The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  This ASU is effective for the Company beginning in fiscal year 2017 and can be adopted by the Company either retrospectively or as a cumulative-effect adjustment as of the date of adoption.  We are currently evaluating the effect that adopting this new accounting guidance will have on our consolidated results of operations, cash flows and financial position.

In August 2014, the FASB issued ASU No. 2014-15, which requires management of public and private companies to evaluate whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued (or available to be issued when applicable) and, if so, to disclose that fact.  Management will be required to make this evaluation for both annual and interim reporting periods, if applicable.  ASU No. 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods within annual periods beginning after December 15, 2016.  The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

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ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk.  Our primary market risk is related to changes in oil prices.  The market price of oil has been highly volatile and is 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 utilize swaps 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.  For accounting purposes, we mark our derivatives to fair value and recognize the changes in fair value under the gain (loss) from derivative activities line on the consolidated statements of operations.

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 on a monthly basis.  When the settlement price (the market price for oil or natural gas during the settlement period) 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.

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 three counterparties.  The Company has a netting arrangement with each 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 a 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 prices and to manage its exposure to commodity price risk.  While the use of these derivative instruments reduces 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 forecasted 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 January 31, 2015 are summarized below:

	Contract		Quantity	Weighted Average	Weighted Average
Term End Date	Type	Basis (1)	(Bbl/d)	Put Strike	Call Strike
Fiscal Year 2016	Collar	NYMEX	4,356	$ 86.85	$ 98.63

(1) NYMEX refers to West Texas Intermediate crude oil prices at Cushing, Oklahoma as quoted on the New York Mercantile Exchange.

Subsequent to January 31, 2015, the Company entered into crude oil swaps for 1,500 Bbl/d at a weighted average price of $60.07 per barrel, effective for the period from October 1, 2015 through December 31, 2016, and crude oil swaps for 500 Bbl/d at a weighted average price of $60.30 per barrel, effective for the period from January 1, 2016 through December 31, 2016.

We determine the estimated 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.  The Company also performs an internal valuation to ensure the reasonableness of third‑party quotes.  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 believes that it has substantial credit quality and the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

Changes in commodity futures price strips during fiscal year 2015 had an overall net positive impact on the fair value of our derivative contracts.  For fiscal year 2015, we reported a gain on our derivative contracts of $64.1 million.  The fair value of our derivative instruments at January 31, 2015 was a net asset of $62.2 million.  This mark-to-market net

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asset relates to derivative instruments with various terms that are scheduled to be realized over the period from January 31,2015 through December31, 2015.  Over this period, actual realized derivative settlements may differ significantly, either positively or negatively, from the unrealized mark-to-market valuation at January31, 2015.  An assumed increase of 10% in the forward commodity prices used in the fiscal year-end valuation of our derivative instruments would result in a net derivative asset of approximately $54.8 million at January31, 2015.  Conversely, an assumed decrease of 10% in forward commodity prices would result in a net derivative asset of approximately $69.8 million at January31, 2015. 

Interest Rate Risk.  As of January 31, 2015, we had $435.0 million of borrowing availability under the TUSA credit facility, of which $119.3 million was drawn at fiscal year-end.  The credit facility bears interest at variable rates.  Assuming we had the maximum amount outstanding at January 31, 2015 under the TUSA credit facility of $435.0 million, a 1.0% increase in interest rates would result in additional annualized interest expense of $4.4 million.

The Convertible Note and the TUSA 6.75% Notes bear interest at fixed rates.

As of January 31, 2015, RockPile had an aggregate of $150.0 million available for borrowing under its credit facility of which approximately $104.9 million of principal was outstanding as of such date.  The credit facility bears interest at variable rates.  Assuming RockPile had the maximum amount outstanding at January 31, 2015 under the credit facility of $150.0 million, a 1.0% interest rate increase would result in additional annualized interest expense of approximately $1.5 million. 

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ITEM 8.  CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Reports of Independent Registered Public Accounting Firm	61
Consolidated Balance Sheets as of January 31, 2015 and 2014	62
Consolidated Statements of Operations for the years ended January31, 2015, 2014, and 2013	64
Consolidated Statements of Cash Flows for the years ended January31, 2015, 2014, and 2013	65
Consolidated Statement of Stockholders’ Equity for the years ended January31, 2015, 2014, and 2013	66
Notes to Consolidated Financial Statements	67

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

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Triangle Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Triangle Petroleum Corporation and subsidiaries (the Company) as of January 31, 2015 and 2014, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended January 31, 2015. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Triangle Petroleum Corporation and subsidiaries as of January 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three‑year period ended January 31, 2015, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Triangle Petroleum Corporation’s internal control over financial reporting as of January 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated April 13, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

(signed) KPMG LLP

Denver, Colorado
April 13, 2015

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Triangle Petroleum Corporation

Consolidated Balance Sheets

(In thousands, except share data)

	January 31, 2015		January 31, 2014
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	67,871	$	81,750
Accounts receivable		164,438		106,463
Commodity derivatives		62,248		955
Other current assets		14,952		5,652
Total current assets		309,509		194,820
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and natural gas properties, full cost method of accounting
Proved properties		1,153,584		629,051
Unproved properties and properties under development, not being amortized		142,896		121,393
Total oil and natural gas properties		1,296,480		750,444
Accumulated amortization		(170,390)		(67,657)
Net oil and natural gas properties		1,126,090		682,787
Oilfield services equipment, net		87,549		46,585
Other property and equipment, net		47,367		24,507
Net property, plant and equipment		1,261,006		753,879
OTHER ASSETS
Deferred loan costs		14,038		3,207
Equity investment		64,411		68,536
Commodity derivatives		—		1,192
Other		5,906		5,888
Total other assets		84,355		78,823
Total assets	$	1,654,870	$	1,027,522

See notes to consolidated financial statements.

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Triangle Petroleum Corporation

Consolidated Balance Sheets

(In thousands, except share data)

	January 31, 2015		January 31, 2014
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued capital expenditures	$	176,182	$	109,599
Other accrued liabilities		73,440		40,588
Current portion of long-term debt		503		8,851
Interest payable		2,250		268
Deferred income taxes		19,467		—
Total current liabilities		271,842		159,306
LONG-TERM LIABILITIES
5% convertible note		135,877		129,290
Borrowings on credit facilities		224,159		196,065
TUSA 6.75% notes		429,500		—
Other notes and mortgages payable		10,102		9,002
Deferred income taxes		33,974		8,262
Other		4,398		2,435
Total liabilities		1,109,852		504,360
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Common stock, $0.00001 par value, 140,000,000 shares authorized; 75,174,442 and 85,735,827 shares issued and outstanding at January 31, 2015 and January 31, 2014, respectively		1		1
Additional paid-in capital		545,017		571,701
Retained earnings (accumulated deficit)		—		(48,540)
Total stockholders' equity		545,018		523,162
Total liabilities and stockholders’ equity	$	1,654,870	$	1,027,522

See notes to consolidated financial statements.

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Triangle Petroleum Corporation

Consolidated Statements of Operations

(In thousands, except per share data)

	For the Years Ended January31,
	2015		2014		2013
REVENUES:
Oil, natural gas and natural gas liquids sales	$	284,502	$	160,548	$	39,614
Oilfield services		288,453		98,199		20,747
Total revenues		572,955		258,747		60,361
EXPENSES:
Lease operating expenses		25,703		14,454		3,566
Gathering, transportation and processing		18,520		4,302		150
Production taxes		29,774		18,006		4,492
Depreciation and amortization		124,055		58,011		15,081
Accretion of asset retirement obligations		167		56		184
Oilfield services		216,596		82,327		16,606
General and administrative, net of amounts capitalized		62,757		34,629		28,543
Total operating expenses		477,572		211,785		68,622
INCOME (LOSS) FROM OPERATIONS		95,383		46,962		(8,261)
OTHER INCOME (EXPENSE):
Interest expense, net		(25,100)		(7,132)		(2,672)
Amortization of deferred loan costs		(3,149)		(554)		(146)
Gain on extinguishment of debt		6,610		—		—
Commodity derivatives gains (losses)		64,050		1,082		(3,570)
Equity investment income (loss)		81		—		(283)
Gain on equity investment derivatives		553		39,785		—
Other income		469		1,278		448
Total other income (expense)		43,514		34,459		(6,223)
INCOME (LOSS) BEFORE INCOME TAXES		138,897		81,421		(14,484)
Income tax provision		45,500		7,941		—
NET INCOME (LOSS)		93,397		73,480		(14,484)
Less: net loss attributable to noncontrolling interest in subsidiary		—		—		724
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	93,397	$	73,480	$	(13,760)
Earnings (loss) per common share outstanding:
Basic	$	1.12	$	1.07	$	(0.31)
Diluted	$	0.97	$	0.91	$	(0.31)
Weighted average common shares outstanding:
Basic		83,611		68,579		44,475
Diluted		101,032		84,558		44,475

See notes to consolidated financial statements.

64

Triangle Petroleum Corporation

Consolidated Statements of Cash Flows

(In thousands)

	For the Years Ended January 31,
	2015		2014		2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	93,397	$	73,480	$	(14,484)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		124,055		58,011		15,081
Share-based compensation		7,919		7,830		6,637
Interest expense not paid in cash		6,587		6,267		3,023
Amortization of deferred loan costs		3,149		554		146
Gain on extinguishment of debt		(6,610)		—		—
Accretion of asset retirement obligations		167		56		184
Commodity derivatives (gains) losses		(64,050)		(1,082)		3,570
Settlements of commodity derivative instruments		11,422		(4,643)		—
Equity investment (income) loss		(81)		—		283
Gain on equity investment derivatives		(553)		(39,785)		—
Gain on securities held for investment		—		(1,040)		(204)
Deferred income taxes		45,500		7,941		—
Changes in related current assets and current liabilities:
Accounts receivable		(65,448)		(65,929)		(30,295)
Other current assets		(9,926)		(3,579)		(2,694)
Accounts payable and accrued liabilities		57,233		44,840		21,762
Asset retirement expenditures		(2,206)		(484)		(253)
Other		262		(1)		8
Cash provided by operating activities		200,817		82,436		2,764
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property expenditures		(359,102)		(279,531)		(114,625)
Acquisitions of oil and natural gas properties		(138,778)		(121,578)		(21,193)
Purchases of oilfield services equipment		(59,624)		(27,414)		(16,535)
Purchases of other property and equipment		(26,739)		(10,928)		(14,684)
Sale of oil and natural gas properties		1,500		—		3,265
Acquisition of oilfield services companies		—		(7,715)		—
Equity investment in Caliber Midstream Partners, L.P.		—		(18,000)		(12,001)
Purchase of equity investment derivative contracts		—		—		(3,889)
Equity investment cash distribution		6,080		3,150		—
Sale of marketable securities		—		6,105		—
Other		(356)		345		(50)
Cash used in investing activities		(577,019)		(455,566)		(179,712)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities		504,159		211,820		41,700
Repayments of credit facilities		(484,515)		(32,306)		(16,700)
Proceeds from notes payable		450,527		14,430		120,000
Repayments of other notes and mortgages payable		(416)		(5,876)		—
Early extinguishment of repurchased debt		(13,890)		—		—
Debt issuance costs		(13,980)		(2,670)		(1,270)
Proceeds from issuance of common stock		—		245,369		—
Stock offering costs		—		(7,072)		—
Payments to settle tax on vested restricted stock units		(2,854)		(2,058)		(1,884)
Issuance of common stock on exercise of options		135		162		13
Common stock repurchased and retired		(76,843)		—		—
Purchase of minority interest in RockPile		—		—		(609)
Other		—		(36)		—
Cash provided by financing activities		362,323		421,763		141,250
NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS		(13,879)		48,633		(35,698)
CASH AND EQUIVALENTS, BEGINNING OF PERIOD		81,750		33,117		68,815
CASH AND EQUIVALENTS, END OF PERIOD	$	67,871	$	81,750	$	33,117

See notes to consolidated financial statements.

65

Triangle Petroleum Corporation

Consolidated Statement of Stockholders’ Equity

For the Fiscal Years Ended January 31, 2015, 2014, and 2013

(in thousands, except share data)

						Retained
	Shares of	Common		Additional		Earnings		Noncontrolling
	Common	Stock at		Paid-in		(Accumulated		Interest in		Total
	Stock	Par Value		Capital		Deficit)		Subsidiary		Equity
Balance - January 31, 2012	43,515,958	$	1	$	314,199	$	(108,260)	$	3,855	$	209,795
Common stock issued for the purchase of oil and natural gas properties	225,000		—		1,204		—		—		1,204
Shares issued for consulting services	10,000		—		73		—		—		73
Exercise of stock options	4,167		—		13		—		—		13
Common stock issued pursuant to termination agreement (net of shares surrendered for taxes)	17,230		—		99		—		—		99
Vesting of restricted stock units (net of shares surrendered for taxes)	774,941		—		(1,884)		—		—		(1,884)
Acquire minority interest in subsidiary	2,185,715		—		2,522		—		(3,131)		(609)
Share-based compensation	—		—		7,415		—		—		7,415
Net loss for the period	—		—		—		(13,760)		(724)		(14,484)
Balance - January 31, 2013	46,733,011	$	1	$	323,641	$	(122,020)	$	—	$	201,622
Shares issued	37,905,000		—		245,369		—		—		245,369
Stock offering costs	—		—		(7,072)		—		—		(7,072)
Shares issued for the purchase of oil and natural gas properties	325,000		—		2,438		—		—		2,438
Vesting of restricted stock units (net of shares surrendered for taxes)	664,483		—		(2,058)		—		—		(2,058)
Exercise of stock options	108,333		—		162		—		—		162
Share-based compensation	—		—		9,221		—		—		9,221
Net income for the period	—		—		—		73,480		—		73,480
Balance - January 31, 2014	85,735,827	$	1	$	571,701	$	(48,540)	$	—	$	523,162
Vesting of restricted stock units (net of shares surrendered for taxes)	762,026		—		(2,854)		—		—		(2,854)
Redeemed RockPile B-Units	—		—		(1,041)		—		—		(1,041)
Shares repurchased and retired	(11,431,744)		—		(31,986)		(44,857)		—		(76,843)
Exercise of stock options	108,333		—		135		—		—		135
Share-based compensation	—		—		9,062		—		—		9,062
Net income for the period	—		—		—		93,397		—		93,397
Balance - January 31, 2015	75,174,442	$	1	$	545,017	$	—	$	—	$	545,018

See notes to consolidated financial statements.

66

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  DESCRIPTION OF BUSINESS

Triangle Petroleum Corporation (“Triangle,” the “Company,” “we,” “us,” “our,” or “ours”) is an independent energy holding company with three principal lines of business: oil and natural gas exploration, development, and production; oilfield services; and midstream services.

We hold leasehold interests and conduct our operations in the Williston Basin of North Dakota and Montana.  Our core focus area is in McKenzie and Williams Counties, North Dakota, and eastern Roosevelt and Sheridan Counties, Montana.  We conduct our exploration and production operations through our wholly-owned subsidiary, Triangle USA Petroleum Corporation (“TUSA”).

In June 2011, we formed RockPile Energy Services, LLC (“RockPile”), a wholly-owned subsidiary, which provides oilfield and complementary well completion services to oil and natural gas exploration and production companies predominantly in the Williston Basin.  RockPile began operations in July 2012.

In September 2012, through our wholly-owned subsidiary, Triangle Caliber Holdings, LLC, we formed Caliber Midstream Partners, L.P. (“Caliber”), an unconsolidated joint venture with First Reserve Energy Infrastructure Fund (“FREIF”).  Caliber was formed for the purpose of providing oil, natural gas and water transportation and related services to oil and natural gas exploration and production companies in the Williston Basin.

The Company, through its wholly-owned subsidiary, Elmworth Energy Corporation (“Elmworth”), previously conducted insignificant exploration and production activities in Canada.  Elmworth has since sold all leasehold interests except for acreage in the Maritimes Basin of Nova Scotia.  Elmworth has ceased all exploration and production activities in Canada except for reclaiming five wells, the drilling site and brine ponds on its Nova Scotia acreage.  Elmworth has no proved reserves and its oil and natural gas properties were fully impaired as of January 31, 2012.

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation.  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 (i) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the Securities and Exchange Commission (“SEC”), and (ii) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and other disclosed amounts. 

No consolidated statement of comprehensive income (loss) is presented because the Company had no comprehensive income or loss activity in the periods presented.

Use of Estimates.  In the course of preparing its consolidated financial statements, management makes various assumptions, judgments, and estimates to determine the reported amount of assets, liabilities, revenue, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include (i) oil and natural gas reserves; (ii) cash flow estimates used in ceiling tests of oil and natural gas properties; (iii) depreciation and amortization; (iv) impairment of undeveloped properties and other assets; (v) assigning fair value and allocating purchase price in connection with business combinations; (vi) accrued revenue and related receivables; (vii) valuation of commodity derivative instruments and equity derivative instruments; (viii) accrued liabilities; (ix) valuation of share-based payments and (x) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these financial statements.

Principles of Consolidation.  The accounts of Triangle and its wholly-owned subsidiaries are presented in the accompanying consolidated financial statements.  All intercompany transactions and balances are eliminated in

67

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

consolidation.  Triangle generally uses the equity method of accounting for investments in entities in which Triangle has an ownership between 20% and 50% and exercises significant influence. 

These consolidated financial statements include the accounts of the Company’s wholly-owned subsidiaries: (i) TUSA, incorporated in the State of Colorado, and its wholly-owned subsidiaries, (ii) RockPile, organized in the State of Delaware, and its wholly-owned subsidiaries, (iii) Elmworth, incorporated in the Province of Alberta, Canada, (iv) Triangle Real Estate Properties, LLC, organized in the State of Colorado, and its wholly-owned subsidiaries, (v) Integrated Operating Solutions, LLC, organized in the State of Colorado, (vi) Ranger Fabrication, LLC, organized in the State of Delaware, and its wholly-owned subsidiaries, and (vii) Triangle Caliber Holdings, LLC, organized in the State of Delaware, and its wholly-owned subsidiaries. Additionally, Triangle Caliber Holdings, LLC is a joint venture partner in Caliber.  The investment in Caliber is accounted for utilizing the equity method of accounting.

Cash and Cash Equivalents.  Cash and cash equivalents, including cash in banks in the United States and Canada,  consist of highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased. 

Accounts Receivable and Credit Policies.  The components of accounts receivable include the following (in thousands):

	For the Years Ended January 31,
		2015		2014
Oil and natural gas sales	$	21,445	$	25,866
Joint interest billings		72,235		43,660
Oilfield services revenue		59,408		29,109
Other		11,350		7,828
Total accounts receivable	$	164,438	$	106,463

The Company’s accounts receivable result primarily from (i) oil and natural gas purchasers, (ii) billings to joint working interest partners in properties operated by the Company and (iii) trade receivables for oilfield services revenue. The Company’s trade and accrued revenue receivables are dispersed among various customers and purchasers and most of the Company’s significant purchasers are large companies with strong credit ratings. If customers are considered a credit risk, letters of credit or parental guarantees are the primary security obtained to support the extension of credit. For most joint working interest partners, the Company may have the right of offset against related oil and natural gas revenues.

The following table provides the percentage of revenue derived from oil and natural gas sales to customers and oilfield services customers who comprise 10% or more of the Company’s consolidated annual revenue (the customers in each year are not necessarily the same from year to year): 

	Fiscal Years Ended January 31,
	2015		2014		2013
Oil & Gas Customer A		13%		22%		N/A
Oil & Gas Customer B		12%		15%		N/A
Oil & Gas Customer C		12%		N/A		N/A
Oilfield Services Customer A		15%		N/A		N/A
Oilfield Services Customer B		12%		13%		N/A

Although a substantial portion of our oil and natural gas sales and our oilfield services revenues may be to a few large customers, we do not believe the loss of any one customer would have a material adverse effect on our exploration and production business as we believe that other purchasers would be available.  While we believe that there are numerous operators in the Williston Basin in need of pressure pumping and related oilfield services, a severe and sustained downturn in commodities pricing could result in the loss of a significant customer.  However, we do not believe that the loss of a significant customer would have a material adverse impact on the Company.

Inventories.  Inventories, included in other current assets, consist of well equipment, sand, chemicals 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 utilized in evaluating net realizable value.

68

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Oil and Natural Gas Properties.  We use the full cost method of accounting for our oil and natural gas operations.  All costs associated with property acquisition, exploration, and development activities in the United States and Canada are capitalized into a United States full cost pool and a Canadian full cost pool, respectively.  The cost pools are amortized on a unit-of-production basis using proved oil and natural gas reserves.  Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and natural gas reserves.  Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized.  Expenditures for maintenance and repairs are charged to production expense in the period incurred.  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. 

The capitalized costs of unevaluated properties, including those of wells in progress, are excluded from the costs being amortized.  We do not have major development projects that are excluded from costs being amortized.  On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments.  To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. 

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

Amortization of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves by country-wide cost pool. 

Companies that follow the full cost method of accounting are required to make quarterly “ceiling test” calculations for each full cost pool.  This test ensures that the country-wide cost pool’s total capitalized costs for oil and natural gas properties (net of accumulated amortization and deferred income taxes) do not exceed the sum of (i) the present value discounted at 10% of estimated future net cash flows from the Company’s proved oil and natural gas reserves in that country, (ii) the pool’s 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.  If the cost pool’s net capitalized costs exceed this “ceiling,” the excess is charged to expense.  Any recorded ceiling-test impairment of oil and natural gas properties is not reversible at a later date. 

At January 31, 2015, the calculated value of the ceiling limitation approximated the carrying value of our oil and natural gas properties subject to the test and no impairment was necessary.  However, Triangle will likely be required to recognize an impairment of oil and natural gas properties in future periods if oil and natural gas prices remain at current prices or continue to decline or if there is a negative impact on one or more of the other components of the calculation and such an impairment will likely be material.

Oil and Natural Gas Reserves.Amortization of the capitalized costs of oil and natural gas properties, including estimated future development and abandonment costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves.  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

69

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

Oilfield Services Equipment and Other Property and Equipment.  Oilfield services equipment and other property and equipment as of January 31, 2014 and 2013 consisted of the following:

	For the Years Ended January 31,
(in thousands)	2015		2014
Land	$	7,888	$	2,512
Building and leasehold improvements		33,625		18,388
Oilfield service equipment		116,354		56,355
Vehicles		4,811		2,288
Software, computers and office equipment		5,327		3,016
Capital leases		853		—
Total depreciable assets		168,858		82,559
Accumulated depreciation		(35,189)		(12,800)
Depreciable assets, net		133,669		69,759
Assets not placed in service		1,247		1,333
Total oilfield service equipment and other property & equipment, net	$	134,916	$	71,092

Expenditures for replacements, renewals, and betterments are capitalized.  Maintenance and repairs are charged to operations as incurred.  Oilfield services equipment and other property and equipment are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable.  We have not found or recognized any impairment losses on such 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 ranging from 3-20 years.

Deferred Loan Costs.  Deferred financing costs include origination, legal, engineering, and other fees incurred to issue debt.  Deferred financing costs are amortized to interest expense using the effective interest method over the respective borrowing term.

Equity Investment.  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 after elimination of intra-company profits and losses.  The Company records losses of the unconsolidated entities only to the extent of the Company’s investment.

We evaluate our equity method investment for impairment when there are indicators of impairment.  If indicators suggest impairment, we will perform an impairment test to assess whether an adjustment is necessary.  The impairment test considers whether the fair value of our equity method investment has declined and if any such decline is other than temporary.  If a decline in fair value is determined to be other than temporary, the investment’s carrying value is written down to fair value. 

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.

Derivative Instruments.  The Company enters into derivative contracts, primarily costless collars and swaps, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative instruments are recorded on the balance sheet at fair value. The Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark-to-market gains and losses in earnings

70

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges.

The Company holds equity investment derivatives (Class A Warrants (Series 1 through Series 4)) in Caliber.  Our equity investment derivatives are measured at fair value and are included in equity investment on the consolidated balance sheet.  Net gains and losses on equity investment derivatives are recorded based on the changes in the fair values of the derivative instruments and included in our consolidated statements of operations.

Income Taxes.  Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The Company’s policy is to recognize interest and/or penalties related to uncertain tax positions in interest expense.

Oil, Natural Gas and Natural Gas Liquids Revenue.  The Company recognizes revenues from the sale of crude oil, natural gas and natural gas liquids when the product is delivered at a fixed or determinable price, title has transferred, and/or collectability is reasonably assured and evidenced by a contract.  There were no oil or natural gas sales imbalances at January 31, 2015, 2014, or 2013.

Oilfield Services Revenue.  The Company enters into arrangements with its customers to provide hydraulic fracturing services and other oilfield 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 collectability is reasonably assured.  Revenue is recognized and customers are invoiced upon the completion of each job, which generally consists of numerous fracturing stages and complementary completion services.  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.

Share-Based Compensation.  Share-based compensation is measured at the estimated grant date fair value of the awards and is recognized over the requisite service period (usually the vesting period). The Company estimates forfeitures in calculating the cost related to stock-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered.

Earnings per Share.  Basic earnings per common 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 reflects increases in average shares outstanding from the potential dilution, under the treasury stock method, that could occur upon (i) exercise of stock options, (ii) vesting of restricted stock units, and (iii) conversion of convertible debt. The treasury stock method assumes exercise, vesting or conversion at the beginning of a period for securities outstanding at the end of a period. Also, the treasury stock method for calculating dilution assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company at the quarter’s average stock price using assumed proceeds from (a) the exercise cost of the options and (b) the

71

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

foregone future compensation expense of hypothetical early vesting of the outstanding restricted stock units.  The assumed proceeds are adjusted for income tax effects.  In the event of a net loss, no potential common shares are included in the calculation of shares outstanding, as their inclusion would be anti-dilutive.

The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and unvested restricted stock, for the periods presented (in thousands):

	For the Years Ended January 31,
	2015		2014		2013
Dilutive		17,421		15,979		—
Anti-dilutive shares		6,905		5,250		4,500

The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the years ended January 31, 2015, 2014, and 2013:

	For the Years Ended January 31,
(in thousands, except per share data)	2015		2014		2013
Net income (loss) attributable to common stockholders	$	93,397	$	73,480	$	(13,760)
Effect of 5% convertible note conversion		4,135		3,392		—
Net income (loss) attributable to common stockholders after effect of debt conversion	$	97,532	$	76,872	$	(13,760)
Basic weighted average common shares outstanding		83,611		68,579		44,475
Effect of dilutive securities		17,421		15,979		—
Diluted weighted average common shares outstanding		101,032		84,558		44,475
Basic net income (loss) per share	$	1.12	$	1.07	$	(0.31)
Diluted net income (loss) per share	$	0.97	$	0.91	$	(0.31)

New Pronouncements Issued But Not Yet Adopted.  In April 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.  ASU 2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures.  The guidance is effective for annual and interim reporting periods beginning after December 15, 2014.  Adoption of this amendment will not have a material effect on our financial position or results of operations.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, issued as a new Topic, Accounting Standards Codification Topic 606.  The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized.  The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  This ASU is effective for the Company beginning in fiscal year 2017 and can be adopted by the Company either retrospectively or as a cumulative-effect adjustment as of the date of adoption.  We are currently evaluating the effect that adopting this new accounting guidance will have on our consolidated results of operations, cash flows and financial position.

In August 2014, the FASB issued ASU No. 2014-15, which requires management of public and private companies to evaluate whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued (or available to be issued when applicable) and, if so, to disclose that fact.  Management will be required to make this evaluation for both annual and interim reporting periods, if applicable.  ASU No. 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods within annual periods beginning after December 15, 2016.  The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

Accounting standard-setting organizations frequently issue new or revised accounting rules.  We regularly review new pronouncements to determine their impact, if any, on our consolidated financial statements.  Other than the standards

72

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

discussed above, there are no significant accounting standards applicable to Triangle which have not been adopted. 

Reclassifications.  Certain amounts in the consolidated balance sheet as of January 31, 2014, and in our consolidated statement of operations for the years ended January 31, 2014 and 2013, have been reclassified to conform to the financial statement presentation for the period ended January 31, 2015.  The balance sheet reclassifications relate to changes in the captions presented in the balance sheet.  The statement of operations reclassifications relate to the break out of amortization of deferred loan costs from interest expense and amounts related to revisions in the Elmworth abandonment obligation were reclassified from accretion of asset retirement obligations to depreciation and amortization expense. Such reclassifications had no impact on consolidated total assets, stockholders’ equity or net income previously reported.

3.  SEGMENT REPORTING

We conduct our operations within two reportable operating segments.  We identified each segment based on management’s responsibility and the nature of their products, services, and costs.  There are no major distinctions in geographical areas served as nearly all operations are in the Williston Basin of the United States.  The Exploration and Production operating segment, consisting of TUSA and several insignificant oil and natural gas subsidiaries, is responsible for finding and producing oil and natural gas.  The Oilfield Services segment, consisting of RockPile, is responsible for a variety of oilfield and complementary services for both Triangle-operated wells and wells operated by third-parties.  Corporate and Other includes our corporate office and several subsidiaries that management does not consider to be part of the Exploration and Production or Oilfield Services segments.  Also included in Corporate and Other are our results from our investment in Caliber, including any changes in the fair value of our equity investment derivatives. 

Management evaluates the performance of our segments based upon net income (loss) before income taxes.  The following tables present selected financial information for our operating segments for the years ended January 31, 2015, 2014, and 2013.

73

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	For the Year Ended January 31, 2015
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	284,502	$	—	$	—	$	—	$	284,502
Oilfield services for third parties		—		294,526		—		(6,073)		288,453
Intersegment revenues		—		123,577		—		(123,577)		—
Total revenues		284,502		418,103		—		(129,650)		572,955
Expenses:
Lease operating and production taxes		55,477		—		—		—		55,477
Gathering, transportation and processing		18,520		—		—		—		18,520
Depreciation and amortization		116,633		22,008		921		(15,507)		124,055
Accretion of asset retirement obligations		167		—		—		—		167
Cost of oilfield services		—		301,142		308		(84,854)		216,596
General and administrative, net of amounts capitalized:
Salaries and benefits		6,028		14,620		11,559		—		32,207
Stock-based compensation		1,155		509		6,255		—		7,919
Other general and administrative		9,042		10,598		2,991		—		22,631
Total operating expenses		207,022		348,877		22,034		(100,361)		477,572
Income (loss) from operations		77,480		69,226		(22,034)		(29,289)		95,383
Other income (expense), net		51,216		(3,024)		(2,356)		(2,322)		43,514
Net income (loss) before income taxes	$	128,696	$	66,202	$	(24,390)	$	(31,611)	$	138,897
As of January 31, 2015:
Net oil and natural gas properties	$	1,200,872	$	—	$	—	$	(74,782)	$	1,126,090
Oilfield services equipment - net	$	—	$	87,549	$	—	$	—	$	87,549
Other property and equipment - net	$	9,679	$	22,246	$	15,442	$	—	$	47,367
Total assets	$	1,408,768	$	202,649	$	131,649	$	(88,196)	$	1,654,870
Total liabilities	$	754,925	$	163,987	$	204,354	$	(13,414)	$	1,109,852

74

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	For the Year Ended January 31, 2014
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	160,548	$	—	$	—	$	—	$	160,548
Oilfield services for third parties		—		102,606		—		(4,407)		98,199
Intersegment revenues		—		91,019		—		(91,019)		—
Total revenues		160,548		193,625		—		(95,426)		258,747
Expenses:
Lease operating and production taxes		32,460		—		—		—		32,460
Gathering, transportation and processing		4,302		—		—		—		4,302
Depreciation and amortization		56,788		8,905		620		(8,302)		58,011
Accretion of asset retirement obligations		56		—		—		—		56
Cost of oilfield services		—		142,339		—		(60,012)		82,327
General and administrative, net of amounts capitalized:
Salaries and benefits		3,541		6,894		6,864		—		17,299
Stock-based compensation		1,127		590		6,113		—		7,830
Other general and administrative		3,939		4,222		1,339		—		9,500
Total operating expenses		102,213		162,950		14,936		(68,314)		211,785
Income (loss) from operations		58,335		30,675		(14,936)		(27,112)		46,962
Other income (expense), net		(172)		(991)		38,998		(3,376)		34,459
Net income (loss) before income taxes	$	58,163	$	29,684	$	24,062	$	(30,488)	$	81,421
As of January 31, 2014:
Net oil and natural gas properties	$	725,958	$	—	$	—	$	(43,171)	$	682,787
Oilfield services equipment - net	$	—	$	46,585	$	—	$	—	$	46,585
Other property and equipment - net	$	1,594	$	18,912	$	4,001	$	—	$	24,507
Total assets	$	816,282	$	126,114	$	148,438	$	(63,312)	$	1,027,522
Total liabilities	$	318,875	$	64,017	$	141,609	$	(20,141)	$	504,360

75

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	For the Year Ended January 31, 2013
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	39,614	$	—	$	—	$	—	$	39,614
Oilfield services for third parties		—		22,535		—		(1,788)		20,747
Intersegment revenues		—		34,672		—		(34,672)		—
Total revenues		39,614		57,207		—		(36,460)		60,361
Expenses:
Lease operating and production taxes		8,058		—		—		—		8,058
Gathering, transportation and processing		150		—		—		—		150
Depreciation and amortization		13,578		2,857		378		(1,732)		15,081
Accretion of asset retirement obligations		184		—		—		—		184
Cost of oilfield services		—		39,534		—		(22,928)		16,606
General and administrative, net of amounts capitalized:
Salaries and benefits		4,367		8,422		1,959		—		14,748
Stock-based compensation		2,507		617		3,342		—		6,466
Other general and administrative		2,223		2,708		2,398		—		7,329
Total operating expenses		31,067		54,138		8,077		(24,660)		68,622
Income (loss) from operations		8,547		3,069		(8,077)		(11,800)		(8,261)
Other income (expense), net		(6,318)		4		974		(883)		(6,223)
Net income (loss) before income taxes	$	2,229	$	3,073	$	(7,103)	$	(12,683)	$	(14,484)
As of January 31, 2013:
Net oil and natural gas properties	$	310,557	$	—	$	—	$	(11,800)	$	298,757
Oilfield services equipment - net	$	—	$	18,878	$	—	$	—	$	18,878
Other property and equipment - net	$	1,597	$	12,443	$	1,739	$	—	$	15,779
Total assets	$	362,878	$	38,668	$	40,220	$	(13,445)	$	428,321
Total liabilities	$	91,134	$	11,845	$	125,364	$	(1,645)	$	226,698

Certain income statement reclassifications were made as previously noted and to reflect the Exploration and Production depreciation and amortization expense gross rather than net of consolidating eliminations.

Eliminations and Other.  For consolidation, intercompany revenues and expenses are eliminated with a corresponding reduction in Triangle’s capitalized well costs.

Under the full cost method of accounting, we deferred recognition of approximately an additional $123.6 million, $91.0 million and $34.7 million in oilfield services income for the years ended January 31, 2015, 2014, and 2013, respectively, and approximately $6.1 million, $4.4 million, and $1.8 million in oilfield services income for the years ended January 31, 2015, 2014, and 2013, respectively, associated with our non-operating partners’ share of costs charged by RockPile for well completion activities on properties we operate, by charging such oilfield services income against oilfield services revenue and crediting proved oil and natural gas properties. 

In addition, we deferred approximately $1.3 million and $2.2 million of Caliber gross profit from our share of its income for the years ended January 31, 2015 and 2014, respectively, associated with services it provided which were capitalized by TUSA, by charging such gross profit against income from equity investment and crediting proved oil and natural gas properties.

The above deferred income is indirectly recognized in future periods through a lower amortization rate as proved reserves are produced.

76

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4.  LONG-TERM DEBT

As of January 31, 2015 and 2014, respectively, the Company’s long-term debt consisted of the following:

	For the Years Ended January 31,
	2015		2014
5% convertible note	$	135,877	$	129,290
TUSA credit facility due October 2018		119,272		183,000
RockPile credit facility due March 2019		104,887		21,515
TUSA 6.75% notes due July 2022		429,500		—
Other notes and mortgages payable		10,605		9,403
Total debt		800,141		343,208
Less current portion of debt:
RockPile credit facility		—		(8,450)
Other notes and mortgages payable		(503)		(401)
Total long-term debt	$	799,638	$	334,357

Convertible Note.On July 31, 2012, the Company sold to NGP Triangle Holdings, LLC a 5% convertible note with an initial principal amount of $120.0 million (the “Convertible Note”) that became convertible after November 16, 2012 into the Company’s common stock at a conversion rate of one share per $8.00 of note principal.

The Convertible Note accrues interest at a rate of 5.0% per annum, compounded quarterly, 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 is paid-in-kind by adding to the principal balance of the Convertible Note, provided that, after October 31, 2017, the Company has the option to make such interest payments in cash.  As of January 31, 2015, $15.9 million of accrued interest has been added to the principal balance of the Convertible Note.

TUSA Credit Facility.  On April 11, 2013, TUSA entered into an Amended and Restated Credit Agreement, which was subsequently amended on various dates.  On November 25, 2014, TUSA entered into a Second Amended and Restated Credit Agreement, which provides for a $1.0 billion senior secured revolving credit facility, with a sublimit for the issuance of letters of credit equal to $15.0 million.  As of November 25, 2014, the borrowing base was set by the lenders at $435.0 million. The TUSA credit facility has a maturity date of October 16, 2018.

Borrowings under the TUSA 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 0.50%, or (C) the one month eurodollar rate (as defined in the agreement) plus 1%), plus an applicable margin that ranges between 0.50% and 1.50%, depending on TUSA’s utilization percentage of the then effective borrowing base, or (ii) the eurodollar rate plus an applicable margin that ranges between 1.50% and 2.50%, depending on TUSA’s utilization percentage of the then effective borrowing base.

The lenders will redetermine the borrowing base under the TUSA credit facility on a semi-annual basis by the beginning of each May 1st and November 1st.  In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year.  If at any time the borrowing base is less than the amount of outstanding credit exposure under the TUSA credit facility, TUSA will be required to (i) prepay the principal amount of the loans in an amount sufficient to eliminate the excess, (ii) pledge additional collateral, (iii) prepay the excess in three equal monthly installments, or (iv)any combination of options (i) through (iii).  TUSA will pay a per annum fee on all letters of credit issued under the TUSA credit facility, which fee will equal the applicable margin for loans accruing interest based on the eurodollar rate and a fronting fee to the issuing lender equal to the greater of 0.125% of the letter of credit amount and $500 per letter of credit. TUSA will pay a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the TUSA credit facility. The TUSA credit facility is collateralized by certain of TUSA’s assets, including (1) at least 80% of the adjusted engineered value of TUSA’s oil and natural gas interests evaluated in determining the borrowing base for the facility, and (2) all of the personal property of TUSA and its subsidiaries.  The obligations under the TUSA credit facility are guaranteed by TUSA’s domestic subsidiaries, but Triangle is not a guarantor.

The TUSA credit facility contains various covenants and restrictive provisions that may, among other things, limit TUSA’s ability to sell assets, incur additional indebtedness, pay dividends, make investments or loans and create liens.  In

77

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

addition, the facility contains financial covenants requiring TUSA to maintain specified ratios of consolidated current assets to consolidated current liabilities and consolidated debt to consolidated EBITDAX.  As of January 31, 2015, TUSA was in compliance with all covenants under the TUSA credit facility.

RockPile Credit Facility.  On March 25, 2014, RockPile entered into a Credit Agreement to provide a $100.0 million senior secured revolving credit facility.  On November 13, 2014, RockPile entered into Amendment No. 1 to Credit Agreement and Incremental Commitment Agreement, which amended the credit facility to increase the borrowing capacity under the facility from $100.0 million to $150.0 million.  The RockPile credit facility has a maturity date of March 25, 2019.

Borrowings under the RockPile credit facility bear interest, at RockPile’s option, at either (i) the alternative base rate (the highest of (a) the administrative agent’s prime rate, (b) the federal funds rate plus 0.5%, or (c) the one-month adjusted Eurodollar rate (as defined in the agreement) plus 1.0%), plus an applicable margin that ranges between 1.5% and 2.25%, depending on RockPile’s leverage ratio as of the last day of RockPile’s most recently completed fiscal quarter, or (ii) the Eurodollar rate plus an applicable margin that ranges between 2.50% and 3.25%, depending on RockPile’s leverage ratio as of the last day of RockPile’s most recently completed fiscal quarter.

RockPile will pay a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the RockPile credit facility.  RockPile will also pay a per annum fee on all letters of credit issued under the RockPile credit facility, which will equal the applicable margin for loans accruing interest based on the Eurodollar rate and a fronting fee to the issuing lender equal to 0.125% of the letter of credit amount.  Triangle is not a guarantor under the RockPile credit facility. 

The RockPile credit facility contains financial covenants requiring RockPile to maintain specified ratios of consolidated debt to EBITDA and Adjusted EBITDA to Fixed Charges.  Amendment No. 1 also modified covenants in the RockPile credit facility related to certain restrictions on the payment of dividends and distributions and increased the amount of permitted capital expenditures.  As of January 31, 2015, RockPile was in compliance with all financial covenants under the RockPile credit facility.

TUSA 6.75% Notes.  On July 18, 2014, TUSA entered into an Indenture (the “Indenture”) among TUSA, a TUSA wholly-owned subsidiary as guarantor, and Wells Fargo Bank, National Association, as trustee, governing the terms of TUSA’s $450.0 million aggregate principal amount of TUSA 6.75% Notes due 2022 (the ”TUSA 6.75% Notes”).

The TUSA 6.75% Notes were issued in a private offering exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), to qualified institutional buyers in accordance with Rule 144A and to persons outside of the United States pursuant to Regulation S under the Securities Act.  The TUSA 6.75% Notes are senior unsecured obligations of TUSA and are guaranteed on a senior unsecured basis by the initial guarantor and another TUSA wholly-owned subsidiary that became a guarantor of the TUSA 6.75% Notes in early December 2014.  The TUSA 6.75% Notes have not been registered under the Securities Act and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements.

The TUSA 6.75% Notes bear interest at a rate of 6.75% per year, accruing from July 18, 2014.  Interest on the TUSA 6.75% Notes is payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2015.  The TUSA 6.75% Notes will mature on July 15, 2022, subject to earlier repurchase or redemption in accordance with the terms of the Indenture.  The Company incurred $10.5 million of offering costs which have been deferred and are being recognized on the effective interest method over the life of the notes.

TUSA may redeem some or all of the TUSA 6.75% Notes at any time prior to July 15, 2017 at a price equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest, if any, to the redemption date and a make-whole premium set forth in the Indenture.  On or after July 15, 2017, TUSA may redeem some or all of the TUSA 6.75% Notes at any time at redemption prices set forth in the Indenture, plus accrued and unpaid interest, if any, to the redemption date.  In addition, at any time prior to July 15, 2017, TUSA may redeem up to 35% of the aggregate principal amount of the TUSA 6.75% Notes at a specified redemption price set forth in the Indenture plus accrued and unpaid interest, if any, to the redemption date, with the net cash proceeds of certain equity offerings.  If TUSA experiences certain change of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

control events, TUSA must offer to repurchase the TUSA 6.75% Notes at 101% of their principal amount, plus accrued and unpaid interest, if any, to the redemption date.

The Indenture permits TUSA to purchase TUSA 6.75% Notes in the open market.  In fiscal year 2015, TUSA repurchased TUSA 6.75% Notes with a face value of $20.5 million for $13.9 million.  TUSA immediately retired the repurchased notes and recognized a gain on extinguishment of debt of $6.6 million.

The Indenture contains covenants that, among other things, restrict TUSA’s ability and the ability of any guarantor subsidiary to sell certain assets; make certain dividends, distributions, investments and other restricted payments; incur certain additional indebtedness and issue preferred stock; create certain liens; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries, and consolidate, merge or sell substantially all of TUSA’s assets.  These covenants are subject to a number of important exceptions and qualifications.  As of January 31, 2015, TUSA was in compliance with all covenants under the TUSA 6.75% Notes.

Second Lien Credit Facility.  On June 27, 2014, TUSA entered into a Second Lien Credit Agreement, which provided for a $60.0 million second priority secured credit facility, which was funded at signing. All borrowings under the second lien credit facility were scheduled to mature on October 16, 2019 (nine months after the maturity of the TUSA credit facility).  Borrowings under the second lien credit facility bore interest, at our option, at either (i) LIBOR (subject to a floor) plus a margin of 7.0% or (ii) a base rate (subject to a floor) plus a margin of 6.0%.  The second lien credit facility also provided that no prepayment fees would be payable for prepayments made during the first twelve months.

Upon issuance of the TUSA 6.75% Notes on July 18, 2014, TUSA terminated the second lien credit facility and repaid all amounts owing thereunder.

Future Maturities of Outstanding Debt.Scheduled annual maturities of long-term debt outstanding as of January 31, 2015 were as follows:

For the Years Ending January 31, (in thousands):
2016	$	503
2017		1,450
2018		1,594
2019		119,852
2020		105,565
Thereafter		571,177
	$	800,141

5.  HEDGING AND COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

Through TUSA, the Company has entered into commodity derivative instruments utilizing costless collars and swaps 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 three counterparties.  The Company has netting arrangements with each 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Company’s commodity derivative instruments are measured at fair value.  The Company has not designated any of its derivative contracts as fair value or cash flow hedges.  Therefore, the Company does not apply hedge accounting to its commodity derivative instruments.  Net gains and losses on derivative activities are recorded based on the changes in the fair values of the derivative instruments.  Net gains and losses on derivative activities are recorded in the commodity derivatives gains (losses) caption on the consolidated statements of operations.  The Company’s cash flows are only impacted when the actual settlements under the commodity derivative contracts result in a payment to or from the counterparty.  These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows. 

The components of commodity derivative gains (losses) in the consolidated statements of operations are as follows (in thousands):

	For the Years Ended January 31,
	2015		2014		2013
Realized commodity derivative gains (losses)	$	11,422	$	(4,643)	$	-
Unrealized commodity derivative gains (losses)		52,628		5,725		(3,570)
Commodity derivative gains (losses), net	$	64,050	$	1,082	$	(3,570)

The Company’s commodity derivative contracts as of January 31, 2015 are summarized below:

	Contract		Quantity	Weighted Average	Weighted Average
Term End Date	Type	Basis (1)	(Bbl/d)	Put Strike	Call Strike
Fiscal Year 2016	Collar	NYMEX	4,356	$ 86.85	$ 98.63

(1) “NYMEX” refers to West Texas Intermediate crude oil prices at Cushing, Oklahoma as quoted on the New York Mercantile Exchange.

Subsequent to January 31, 2015, the Company entered into crude oil swaps for 1,500 Bbl/d at a weighted average price of $60.07 per barrel effective for the period from October 1, 2015 through December 31, 2016, and crude oil swaps for 500 Bbl/d at a weighted average price of $60.30 per barrel, effective for the period from January 1, 2016 through December 31, 2016.

The estimated fair values of commodity derivatives included in the consolidated balance sheets at January 31, 2015 and 2014 are summarized below. The net fair value of the Company’s commodity derivatives changed by $60.1 million from a net asset of $2.1 million at January 31, 2014 to a net asset of $62.2 million at January 31, 2015, primarily due to (i) changes in the futures prices for oil, which are used in the calculation of the fair value of commodity derivatives, (ii) settlement of commodity derivative positions during the current period and (iii) changes to the Company’s commodity derivative portfolio in fiscal year 2015. The Company does not offset asset and liability positions with the same counterparties within the consolidated financial statements; rather, all contracts are presented at their gross estimated fair value. As of the dates indicated, the Company’s derivative assets and liabilities are presented below (in thousands). These balances represent the estimated fair value of the contracts. The Company has not designated any of its derivative contracts as cash-flow hedging instruments for accounting purposes. The main headings represent the balance sheet captions for the contracts presented (in thousands).

	For the Years Ended January 31,
	2015		2014
Current Assets:
Crude oil derivative contracts	$	62,248	$	955
Other Long-Term Assets:
Crude oil derivative contracts		—		1,192
Total derivative asset	$	62,248	$	2,147

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6.  OIL AND NATURAL GAS PROPERTIES

The following table sets forth the capitalized costs incurred in our oil and natural gas production, exploration, and development activities in the United States for years ended January 31, 2015, 2014, and 2013:

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Costs incurred during the period
Acquisition of properties:
Proved	$	90,920	$	80,201	$	623
Unproved		47,858		41,377		20,570
Exploration		180,174		96,731		55,583
Development		226,765		216,046		91,666
Oil and natural gas expenditures		545,717		434,355		168,442
Asset retirement obligations, net		1,818		676		370
	$	547,535	$	435,031	$	168,812

During fiscal years 2015, 2014, and 2013, we acquired oil and natural gas properties, and participated in the drilling and/or completion of wells, for total consideration of approximately $545.7 million, $434.4 million, and $168.4 million, including $138.8 million, $121.6 million, and $21.2 million, respectively, for the acquisition of oil and natural gas properties.  Total consideration paid includes common stock of $2.4 million and $1.2 million for fiscal years 2014 and 2013, respectively.  During fiscal years 2015, 2014, and 2013, we capitalized $4.8 million, $3.7 million, and $2.0 million, respectively, of internal land, geology, and operations 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 properties.

The following table summarizes oil and natural gas property costs not being amortized at January 31, 2015, by year that the costs were incurred:

			Fiscal Year Costs Incurred
									2012
(in thousands)	Total		2015		2014		2013		and prior
Acquisition	$	113,606	$	46,982	$	25,785	$	10,220	$	30,619
Exploration		22,305		20,830		1,475		—		—
Capitalized interest		6,985		4,899		2,086		—		—
Total	$	142,896	$	72,711	$	29,346	$	10,220	$	30,619

The $142.9 million of costs not being amortized includes $17.1 million in costs for unevaluated wells in progress expected to be completed prior to January 31, 2016.  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, 2015 will be reclassified to proved properties over the next five years.

Depreciation and amortization expense of oil and natural gas properties in the U.S. for fiscal years 2015, 2014, and 2013 was $106.9 million, $51.0 million and $13.5 million, respectively.

7.  ACQUISITIONS

Kodiak Oil & Gas Property Acquisition.  In August 2013, TUSA acquired interests in approximately 5,600 net acres of leaseholds and related producing properties along with various other related rights, permits, contracts, equipment and other assets, all located in McKenzie County, North Dakota, from Kodiak Oil & Gas Corporation (“Kodiak”).  We

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

paid approximately $83.8 million in cash.  In addition, the Company and Kodiak also agreed to exchange certain of Triangle’s oil and natural gas leasehold interests in Kodiak’s operated units for approximately 600 net acres of leasehold interests held by Kodiak in units then operated by the Company.  The effective date for the acquisition and the exchange was July 1, 2013.

Marathon Oil & Gas Property Acquisition.  In June 2014, we acquired from Marathon Oil Company (“Marathon”) certain oil and natural gas leaseholds and related producing properties located in Williams County, North Dakota, Sheridan County, Montana, and Roosevelt County, Montana comprising approximately 41,100 net acres and various other related rights, permits, contracts, equipment and other assets for approximately $90.4 million in cash, net of certain closing adjustments of $9.6 million.  Transaction costs related to the acquisition incurred during the year ended January 31, 2015 of approximately $1.3 million are recorded in general and administrative expenses.

The acquisitions were accounted for using the acquisition method under ASC-805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at fair value as of the acquisition date of June 30, 2014.  The following table summarizes the purchase price and the estimated values of assets acquired and liabilities assumed:

Purchase price (in thousands):
Cash	$	90,352
Total consideration given	$	90,352
Fair value allocation of purchase price:
Oil and natural gas properties:
Proved properties	$	71,044
Unproved properties		20,262
Total oil and natural gas properties		91,306
Accounts payable		(469)
Asset retirement obligations assumed		(485)
Fair value of net assets acquired	$	90,352

Pro Forma Financial Information.  The following unaudited pro forma financial information represents the combined results for the Company and the properties acquired from Kodiak, in August of 2013, and Marathon, in June of 2014, as if the acquisitions had occurred on February 1, 2012. 

	For the Years Ended January 31,
(in thousands, except per share data)	2015		2014		2013
Operating revenues	$	584,696	$	312,081	$	92,933
Net income (loss)	$	96,438	$	91,579	$	(2,407)
Earnings (loss) per common share
Basic	$	1.15	$	1.22	$	(0.04)
Diluted	$	1.00	$	1.04	$	(0.04)
Weighted average common shares outstanding:
Basic		83,611		75,047		55,794
Diluted		101,032		91,026		55,794

For purposes of the pro forma information it was assumed that the net proceeds generated from the issuance of the Company’s common stock were utilized to fund the August 28, 2013 acquisition and that such issuance occurred on February 1, 2012.  The pro forma information includes the effects of adjustments for depreciation, amortization and accretion expense of $3.4 million, $16.5 million and $12.6 million for fiscal years 2015, 2014 and 2013, respectively.  The pro forma results do not include any cost savings that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired.  The pro forma results are not necessarily indicative of what actually would have occurred if the transactions had been completed, or the common stock had been issued, as of the beginning of the period, nor are they necessarily indicative of future results.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Acquisition of Team Well Service, Inc.In October 2013, RockPile completed its acquisition of Team Well Service, Inc. (“Team Well”), an operator of well service rigs in North Dakota, in exchange for (i) $6.8 million in cash; (ii) unsecured seller notes of $0.8 million; and, (iii) contingent consideration of $1.5 million.  The final purchase price allocation resulted in identifiable intangible assets and goodwill of approximately $3.9 million and $1.7 million, respectively.  Transaction and other costs associated with the acquisition of net assets are expensed as incurred.  Pro forma information has not been provided for the Team Well acquisition as the impact is immaterial to our consolidated financial statements.

8.  ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations (“ARO”) represent the estimated present value of the amounts expected to be incurred to plug, abandon, and remediate producing and shut-in properties at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its ARO when incurred by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.

The following tables reflect the change in ARO for the years ended January 31, 2015 and 2014:

	For the Years Ended January 31,
(in thousands)	2015		2014
Balance at the beginning of the period	$	4,629	$	3,422
Liabilities incurred		1,821		944
Revision of estimates		2,737		774
Sale of assets		(29)		(83)
Liabilities settled		(747)		(484)
Accretion		167		56
Balance at the end of the period		8,578		4,629
Less current portion of obligations		(5,391)		(3,333)
Long-term ARO	$	3,187	$	1,296

The current portion of ARO is classified with other accrued liabilities and the long-term ARO is classified in other long-term liabilities in the accompanying consolidated balance sheets.

A significant portion of the current obligations relates to the reclamation of man-made ponds holding produced formation water and the plugging and abandonment of well bores in the Maritimes Basin of Canada of $4.8 million and $2.0 million as of January 31, 2015 and January 31, 2014, respectively.  Internal engineering re-assessment of Canadian ARO resulted in revisions $2.7 million and $1.0 million to the ARO during fiscal years 2015 and 2014.  Since our Canadian oil and natural gas properties were fully impaired, the ARO revisions were expensed and included in depreciation and amortization expenses in the accompanying consolidated statements of operations for the years ended January 31, 2015 and 2014, respectively.

9.   EQUITY INVESTMENT AND EQUITY INVESTMENT DERIVATIVES

Equity Investment.   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 FREIF. The joint venture entity, Caliber, was formed to provide crude oil, natural gas and water transportation and related services to the Company and third parties primarily within the Williston Basin of North Dakota and Montana.

Pursuant to the terms of the October 1, 2012 Contribution Agreement (the “Contribution Agreement”), Triangle Caliber Holdings agreed to contribute $30.0 million to Caliber in exchange for 3,000,000 Class A Units; 4,000,000 Class A Trigger Units with certain performance conditions; 4,000,000 Series 1 Warrants and 1,600,000 Class A Trigger Unit Warrants with an exercise price of $14.69;2,400,000 Series 2 Warrants with an exercise price of $24.00; and FREIF

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Caliber Holdings agreed to contribute $70.0 million to Caliber in exchange for 7,000,000 Class A Units, with the general partner of Caliber being owned and controlled equally by Triangle Caliber Holdings and FREIF Caliber Holdings. 

On September 12, 2013, Triangle Caliber Holdings and FREIF Caliber Holdings entered into an Amended and Restated Contribution Agreement (“A&R Contribution Agreement”), which amended and restated the Contribution Agreement. Pursuant to the terms of the A&R Contribution Agreement, FREIF Caliber Holdings agreed to contribute an additional $80.0 million to Caliber in exchange for an additional 8,000,000 Class A Units, to be issued no later than June 30, 2014, and 5,000,000 Series 5 Warrants with an exercise price of $32.00. Also pursuant to the terms of the A&R Contribution Agreement, Triangle Caliber Holdings received 3,000,000 Series 3 Warrants with an exercise price of $24.00;2,000,000 Series 4 Warrants with an exercise price of $30.00;  and the performance conditions associated with the 4,000,000 Class A Trigger Units granted in connection with the Contribution Agreement were removed and replaced with a provision to convert the 4,000,000 Class A Trigger Units into 4,000,000 Class A Units at the earlier of the commissioning of the Alexander gas processing facility or June 30, 2014. The conversion of the Class A Trigger Units on June 30, 2014 did not require any additional contribution of capital from Triangle Caliber Holdings. Additionally, the 1,600,000 Class A Trigger Unit Warrants granted in connection with the Contribution Agreement converted to 1,600,000 Series 1 Warrants on June 30, 2014 with an exercise price of $14.69.

Following the issuance of the additional 8,000,000 Class A Units to FREIF Caliber Holdings and the conversion by Triangle Caliber Holdings of its 4,000,000 Class A Trigger Units into 4,000,000 Class A Units, FREIF Caliber Holdings owned 15,000,000 Class A Units, representing an approximate sixty-eight percent (68%) limited partner interest in Caliber, and Triangle Caliber Holdings owned 7,000,000 Class A Units, representing an approximate thirty-two percent (32%) limited partner interest in Caliber.

The following summarizes the Company’s equity investment holdings in Caliber as of January 31, 2015 and 2014 and the strike prices for exercising warrants as of January 31, 2015:

	Expiration		Strike Price at		As of January 31,
	Date		January 31, 2015		2015	2014
Class A Units		—		—	7,000,000	3,000,000
Class A Trigger Units		—		—	—	4,000,000
Class A Trigger Unit Warrants		—		—	—	1,600,000
Series 1 Warrants		October 1, 2024	$	12.78	5,600,000	4,000,000
Series 2 Warrants		October 1, 2024	$	22.09	2,400,000	2,400,000
Series 3 Warrants		September 12, 2025	$	22.09	3,000,000	3,000,000
Series 4 Warrants		September 12, 2025	$	28.09	2,000,000	2,000,000

The Company’s investment interest in Caliber is considered to be variable, and Caliber is considered to be a variable interest entity because the power to direct the activities that most significantly impact Caliber’s economic performance does not reside with the holders of equity investment at risk.  The Company is not considered the primary beneficiary of Caliber since it does not have the power to direct the activities of Caliber that are considered most significant to its economic performance.  Under the equity method, our investment will be adjusted each period for contributions made, distributions received, the change in the fair value of our holdings of equity investment derivatives of Caliber, our share of Caliber’s net income and accretion of any basis differences.  Our maximum exposure to loss related to Caliber is limited to our equity investment.  We evaluate our equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following summarizes the activities related to the Company’s equity investment in Caliber for the years ended January 31, 2015 and 2014:

	For the Years Ended January 31,
(in thousands)	2015		2014
Balance at beginning of year	$	68,536	$	11,768
Capital contributions		—		18,000
Distributions		(6,080)		(3,150)
Equity investment share of net income before intra-company profit eliminations		1,402		2,184
Change in fair value of:
Class A Trigger Units (1)		1,745		38,091
Class A Trigger Unit Warrants (2)		532		234
Series 1 Warrants		(1,241)		926
Series 2 Warrants		(254)		254
Series 3 Warrants		(207)		207
Series 4 Warrants		(22)		22
Total changes in fair value		553		39,734
Balance at end of year	$	64,411	$	68,536
Fair value of trigger unit warrants and warrants at end of year	$	504	$	39,734

(1) The change in value was prior to the vesting of the Class A Trigger Units into Class A Units on June 30, 2014.

(2) On June 30, 2014, the 1,600,000 Class A Trigger Unit Warrants then outstanding automatically converted into Series 1 Warrants upon the Company’s vesting of the Class A Trigger Units, resulting in an aggregate of 5,600,000 Series 1 Warrants outstanding.

Equity Investment Derivatives.At January 31, 2015 and 2014, the Company held Class A (Series 1 through Series 4) Warrants to acquire additional ownership in Caliber.  These instruments are considered to be equity investment derivatives and are valued using the following valuation techniques, which are generally less observable from objective sources. 

At each period end, the fair value of the Class A (Series 1 through Series 4) Warrants were estimated using a Monte Carlo Simulation (“MCS”) model.  An MCS model provides a numeric approach to stochastic stock movement to forecast the future price of the underlying Class A Units, as opposed to an analytic solution provided by Black-Scholes.  For each MCS, the value of the Class A Units was forecasted at the end of each quarter based on a predetermined yield, and the strike price for the warrant is adjusted accordingly.  The fair value of the underlying Class A Units was estimated employing primarily a discounted cash flows analysis.  The resulting value represented a marketable minority value of Caliber.  As the Class A Units represent a non-marketable equity interest in a private enterprise, an adjustment to our preliminary value estimates was made to account for the lack of liquidity. 

The MCS model assumed that the Class A Warrants would be exercised at the earlier of (a) the contractual life of 12 years, and (b) the point at which the exercise price would be reduced to $5.00 per warrant (at which point it would be advantageous for Triangle to exercise early to capture future distributions on the Class A Units).  The key inputs to the MCS model are the same as the Black-Scholes model previously used including 10-year historical volatilities for publicly-traded comparable companies, risk-free interest rates over the expected warrant term and dividend yields based on expected distributions.  The change in fair value during the years ended January 31, 2015 and 2014 resulted in a $0.6 million and $39.8 million increase, respectively, in our equity investment account and as a gain on equity investment derivatives.  Also included in the gain on equity investment derivatives during the year ended January 31, 2015 was a gain of $1.7 million associated with the change in fair value of the 4,000,000 million Class A Trigger Units which vested on June 30, 2014.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

On January 31, 2015, Triangle Caliber Holdings entered into a series of agreements modifying its joint venture with FREIF.  In connection with the modifications, Triangle Caliber Holdings entered into a Second Amended and Restated Contribution Agreement, dated January 31, 2015 (the “2nd A&R Contribution Agreement”), with FREIF, and the general partner of Caliber, owned and controlled equally between Triangle Caliber Holdings and FREIF.  Pursuant to the terms of the 2nd A&R Contribution Agreement, FREIF agreed to contribute an additional $34.0 million to Caliber in exchange for 2,720,000 Class A Units.  FREIF funded the $34.0 million contribution, and the additional 2,720,000 Class A Units were issued, on February 2, 2015.  Triangle made no capital contribution to Caliber in connection with the 2nd A&R Contribution Agreement or the issuance of the 2,720,000 Class A Units.  Following the issuance, FREIF holds 17,720,000 Class A Units, representing an approximate 71.7% Class A Units ownership interest in Caliber, and Triangle Caliber Holdings holds 7,000,000 Class A Units, representing an approximate 28.3% Class A Units ownership interest in Caliber.  Triangle will recognize a gain in the first quarter of fiscal year 2016 of $4.2 million related to Caliber’s issuance of these 2,720,000 Class A Units to FREIF. 

Also pursuant to the terms of the 2nd A&R Contribution Agreement, Triangle Caliber Holdings received warrants for the purchase of an additional 3,626,667 Class A Units, and FREIF received warrants for the purchase of an additional 906,667 Class A Units.   The warrants received by Triangle Caliber Holdings on February 2, 2015 included 2,357,334 Series 1 through 4 warrants at strike prices and expiration dates noted above and 1,269,333 Series 6 warrants with a strike price of $12.50 and an expiration date of February 2, 2018.  Triangle will also recognize a gain of $0.2 million in the first quarter of fiscal year 2016 related to the fair value of the warrants issued, which will be amortized over the lives of the related warrants. 

10.  CAPITAL STOCK

The Company had 106.4 million shares of common stock issued or reserved for issuance at January 31, 2015. At January 31, 2015, the Company had 75.2 million shares of common stock issued and outstanding.  The Company also had 3.6 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2011 Omnibus Incentive Plan and its 2014 Equity Incentive Plan (the “2014 Plan”).  The Company also had 4.6 million shares of common stock reserved that remained available for issuance under the 2014 Plan, as well as 6.0 million shares of common stock reserved for issuance under the CEO Stand-Alone Stock Option Agreement.  Lastly, the Company had 17.0 million shares of common stock reserved for issuance pursuant to the Convertible Note at January 31, 2015.

The Company’s Board of Directors (the “Board”) approved a program authorizing the repurchase of outstanding shares of the Company’s common stock in amounts equal to the aggregate of (i) $25.0 million of the Company’s common stock (“Tranche 1”), (ii) up to the number of shares of common stock authorized for issuance under the Company’s 2014 Equity Incentive Plan and its CEO Stand-Alone Stock Option Agreement (“Tranche 2”), and (iii) up to the number of shares potentially issuable, at any given time, pursuant to the paid-in-kind interest accrued on the Convertible Note (“Tranche 3”). The program stipulates that shares of common stock may be repurchased from time to time, in amounts and at prices that the Company deems appropriate, subject to market and business conditions and other considerations. The repurchase program has no expiration date and may be suspended or discontinued at any time without prior notice. During fiscal year 2015, the Company repurchased an aggregate of 11.4 million shares of the Company’s common stock under the program at a total cost of $76.8 million.  The repurchased shares of common stock were immediately retired and charged to available retained earnings with the balance charged to additional paid-in capital.  As of January 31, 2015, the number of shares of common stock remaining available for repurchase under the Board approved program is 4,949,393 shares.

11.  SHARE-BASED COMPENSATION

The Company has granted equity awards to officers, directors, and certain employees of the Company including restricted stock units and stock options.  In addition, RockPile has granted Series B Units which represent interests in future RockPile profits.  The Company measures its awards based on the award’s grant date fair value which is recognized ratably over the applicable vesting period.

On May 27, 2014, the Board approved the 2014 Plan, which was approved by the Company’s stockholders on July 17, 2014.  No additional awards may be granted under prior plans but all outstanding awards under prior plans shall continue in accordance with their applicable terms and conditions.  The 2014 Plan authorizes the Company to issue stock options,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

SARs, restricted stock, restricted stock units, cash awards, and other awards to any employees, officers, directors, and consultants of the Company and its subsidiaries.  The maximum number of shares of common stock reserved for issuance under the 2014 Plan is 6.0 million shares, subject to adjustment for certain transactions.

For the years ended January 31, 2015, 2014, and 2013, the Company recorded share-based compensation related to restricted stock units, stock options and RockPile Series B Units as follows:

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Restricted stock units	$	6,254	$	7,496	$	6,639
Stock options		2,299		1,135		60
Stock issued pursuant to termination agreements		—		—		99
RockPile Series B Units		509		590		617
		9,062		9,221		7,415
Less amounts capitalized to oil and natural gas properties		(1,143)		(1,391)		(949)
Compensation expense	$	7,919	$	7,830	$	6,466

Restricted Stock Units.  During the year ended January 31, 2015, the Company granted 1,523,700 restricted stock units as compensation to employees, officers, and directors.  Restricted stock units vest over one to five years.  As of January 31, 2015, there was approximately $19.8 million of total unrecognized compensation expense related to unvested restricted stock units.  This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 4.0 years on a weighted average basis.  When restricted stock units vest, the holder has the right to receive one share of the Company’s common stock per vesting unit. 

The following table summarizes the status of restricted stock units outstanding:  

		Weighted-
	Number of	Average Award
	Shares	Date Fair Value
Restricted stock units outstanding - January 31, 2012	2,488,342	$	7.02
Units granted	1,041,400	$	6.37
Units forfeited	(5,600)	$	7.59
Units vested	(1,000,057)	$	6.90
Restricted stock units outstanding - January 31, 2013	2,524,085	$	6.68
Units granted	1,440,133	$	6.95
Units forfeited	(141,909)	$	6.58
Units vested	(946,681)	$	6.71
Restricted stock units outstanding - January 31, 2014	2,875,628	$	6.62
Units granted	1,523,700	$	9.42
Units forfeited	(394,921)	$	7.21
Units vested	(1,090,362)	$	7.04
Restricted stock units outstanding - January 31, 2015	2,914,045	$	7.92

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Stock Options.The following table summarizes the status of stock options outstanding:

		Weighted
	Numberof	Average
	Shares	ExercisePrice
Options outstanding - January 31, 2012 (142,500 exercisable)	235,833	$	1.50
Options exercised	(4,167)	$	3.00
Options outstanding - January 31, 2013 (231,666 exercisable)	231,666	$	1.48
Options forfeited	(15,000)	$	3.00
Options exercised	(108,333)	$	1.25
Options granted	6,000,000	$	11.25
Options outstanding - January 31, 2014 (108,333 exercisable)	6,108,333	$	11.07
Options forfeited	—	$	—
Options exercised	(108,333)	$	1.25
Options granted	700,000	$	14.00
Options outstanding - January 31, 2015 (600,000 exercisable)	6,700,000	$	11.54

The following table presents additional information related to the stock options outstanding at January 31, 2015:

		Remaining
Exercise Price		Contractual Life	Number of Shares
per Share		(years)	Outstanding		Exercisable
$	7.50	8.43		750,000		75,000
$	8.50	8.43		750,000		75,000
$	10.00	8.43		1,500,000		150,000
$	12.00	8.43		1,500,000		150,000
$	15.00	8.43		1,500,000		150,000
$	12.00	6.61		233,333		—
$	14.00	6.61		233,333		—
$	16.00	9.61		233,334		—
				6,700,000		600,000
Weighted average exercise price per share			$	11.54	$	11.25
Weighted average remaining contractual life				8.34		8.43

Compensation expense related to stock options is calculated using the Black-Scholes valuation model.  Expected volatility is generally based on the historical volatility of Triangle’s common stock.  The expected term of the options is estimated based on factors such as vesting periods, contractual expiration dates, historical trends in the Company’s common stock price and historical exercise behavior.  The risk-free rate for the expected term (from service inception to option exercise) of the options is based on the yields of U.S. Treasury instruments with lives comparable to the estimated expected option term or life.

The following assumptions were used for the Black-Scholes model to calculate the share-based compensation expense for the options granted in fiscal year 2015:

Risk free rate	1.06	%
Dividend yield	—
Expected volatility	54	%
Weighted average expected stock option life (years)	3.0

As of January 31, 2015, there was approximately $18.6 million of total unrecognized compensation expense related to stock options.  This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 3.3 years. 

RockPile Share-Based Compensation.  RockPile currently has two classes of equity; Series A Units which have an 8% preference and Series B Units, which are used for equity awards. RockPile approved a plan that includes provisions

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

allowing RockPile to make equity grants in the form of restricted units (Series B Units) pursuant to Restricted Unit Agreements. The plan authorizes RockPile to issue an aggregate of up to 6.0 million Series B Units in multiple series designated by a sequential number with the right to reissue forfeited or redeemed Series B Units.

The Series B Units are intended to constitute “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 zero.  RockPile may designate a “Liquidation Value” applicable to each tranche of a Series B Unit grant so as to constitute a net profits interest. The Liquidation Value shall equal the dollar amount per unit that would, in the reasonable determination of RockPile, be distributed with respect to the initial Series B Unit tranche if, immediately prior to the issuance of a new Series B Unit tranche, the assets of RockPile were sold for their fair market value and the proceeds (net of any liabilities) were distributed.

The Series A Units are entitled to a return of contributed capital and an 8% preferred return 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 $40.0 million. As of January 31, 2015, the $40.0 million cumulative distribution threshold has been met. Therefore, 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 will be distributed on a pro rata basis. Subsequently issued 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.  RockPile’s limited liability company agreement was amended on January 31, 2015 to permit distributions to holders of vested Series B Units as prepayment for future amounts payable to them upon a RockPile liquidity event.  In the event a holder of vested Series B Units receives such a pre-liquidity event distribution, their capital account will be adjusted to reflect the prepayment.

Series B Units currently have a 7 to 52 month vesting schedule. 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. 

A summary of the activity for RockPile’s Series B Units is as follows:

	Series	Series	Series	Series
	B-1units	B-2 units	B-3 units	B-4 units	Total
Units outstanding - January 31, 2012	—	—	—	—	—
Units granted	3,100,000	60,000	—	—	3,160,000
Units outstanding - January 31, 2013	3,100,000	60,000	—	—	3,160,000
Units granted	—	—	910,000	—	910,000
Units outstanding - January 31, 2014	3,100,000	60,000	910,000	—	4,070,000
Units redeemed	(180,000)	—	—	—	(180,000)
Units granted	—	—	—	1,412,000	1,412,000
Units outstanding - January 31, 2015	2,920,000	60,000	910,000	1,412,000	5,302,000
Vested	2,920,000	30,000	188,000	—	3,138,000
Unvested	—	30,000	722,000	1,412,000	2,164,000

As of January 31, 2015, there was approximately $2.6 million of unrecognized compensation expense related to unvested Series B Units.  We expect to recognize such expense on a pro-rata basis on the Series B Units’ vesting schedule during the next five fiscal years.

12.  FAIR VALUE MEASUREMENTS

The FASB’s ASC 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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; and

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

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.

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, 2015 and January 31, 2014, by level within the fair value hierarchy:

	As of January 31, 2015
(in thousands)	Level1		Level 2		Level 3		Total
Assets:
Equity investment derivative assets	$	—	$	—	$	504	$	504
Commodity derivative assets	$	—	$	62,248	$	—	$	62,248
Liabilities:
RockPile earn-out liability	$	—	$	(1,825)	$	—	$	(1,825)

	As of January 31, 2014
(in thousands)	Level 1		Level 2		Level3		Total
Assets:
Equity investment derivative assets	$	—	$	—	$	39,734	$	39,734
Commodity derivative assets	$	—	$	2,147	$	—	$	2,147
Liabilities:
RockPile earn-out liability	$	—	$	(1,739)	$	—	$	(1,739)

Commodity Derivative Instruments.The Company determines its estimate of the fair value of commodity 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 considering 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.  The Company believes that each of its counterparties is creditworthy and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.  At January 31, 2015, commodity derivative instruments utilized by the Company consist of costless collars and swaps.  The Company’s commodity derivative instruments are valued using public indices and are traded with third-party counterparties, but are not openly traded on an exchange.  As such, the Company has classified these commodity derivative instruments as Level 2.

Caliber Class A (Series 1 through Series 4) Warrants.  The Company determines its estimate of the fair value of Caliber Class A Warrants using a MCS model.  For each MCS, the value of the Class A Units was forecasted at the end of each quarter based on a predetermined yield, and the strike price for the warrant is adjusted accordingly.  The fair value of the underlying Class A Units was estimated employing primarily a discounted cash flows analysis.  At January 31, 2015, the Company’s Caliber Class A Warrants are valued using valuation models that are generally less observable from objective sources.  As such, the Company has classified these instruments as Level 3.

Earn-out Liability.  The Company determined the estimated fair value of the earn-out liability relating to RockPile’s acquisition of Team Well using a market approach based on information derived from an analysis performed for RockPile by an independent third-party. This analysis used publicly available information from market participants in the same

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

industry, generally accepted methods for estimating an investor’s return requirements, and quoted market prices in active markets. As such, the earn-out liability has been classified as Level 2.

Summary of Level 3 Financial Assets and Liabilities.  The following table presents the rollforward of the fair values of the Company’s Level 3 financial assets and liabilities:

	Class A
	Trigger
(in thousands)	Units		Warrants
Balance at January 31, 2013	$	—	$	—
Initial recognition of equity investment derivative assets		38,091		1,696
Balance at January 31, 2014		38,091		1,696
Interest paid in-kind		—		—
Net unrecognized loss		—		—
Net unrealized gain		1,745		(1,192)
Conversion to Class A Units		(39,836)		—
Balance at January 31, 2015	$	—	$	504

Fair Value of Financial Instruments.  The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable and payable, derivatives and Caliber Class A Warrants (discussed above) and long-term debt. The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short-term maturities. The Convertible Note’s estimated fair value is based on discounted cash flows analysis and option pricing.  The carrying amount of the Company’s revolving credit facilities approximated fair value because the interest rate of the facilities is variable. The fair value of other notes and mortgages payable is not significantly different than their carry values.  The fair value of the TUSA 6.75% Notes is derived from quoted market prices. This disclosure does not impact our financial position, results of operations or cash flows.

	January 31, 2015				January 31, 2014
	Carrying		Estimated		Carrying		Estimated
(in thousands)	Value		FairValue		Value		Fair Value
5% convertible note	$	135,877	$	137,790	$	129,290	$	169,170
Revolving credit facilities		224,159		224,159		204,515		204,515
TUSA 6.75% notes		429,500		303,871		—		—
Other notes and mortgages payable		10,605		10,605		9,403		9,403

13.  INCOME TAXES

The Company’s income tax provision (benefit) is composed of the following:

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Current tax expense (benefit)	$	—	$	—	$	—
Deferred tax expense (benefit)
Federal		42,400		7,324		(2,137)
State		3,100		617		(223)
Foreign		—		—		(83)
Valuation allowance - United States and Canada		—		—		2,443
Total income tax provision (benefit)	$	45,500	$	7,941	$	—
Income (loss) before income taxes	$	138,897	$	81,421	$	(14,484)
Effective income tax rate		33%		10%		0%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

A reconciliation of the income tax provision (benefit) computed by applying the federal statutory rate of 35.0% to the Company’s income tax provision (benefit) is as follows:

	For the Years Ended January 31,
(in thousands)		2015		2014		2013
Federal statutory tax expense (benefit)	$	48,613	$	28,498	$	(5,069)
State income tax expense / (benefit), net of federal income tax benefit		3,618		2,324		(361)
Permanent differences		3,196		3,221		2,280
Difference in foreign tax rates		539		164		28
Effect of tax rate change		(147)		(258)		(71)
Credits		(338)		(100)		—
State NOL adjustment		1,061		—		—
Bad debt deduction for receivables from Elmworth		(14,517)		—		—
Attribute reduction - cancellation of debt exclusion - Elmworth		8,466		—		—
Changes in valuation allowance		(7,464)		(26,364)		2,443
Other		2,473		456		750
Provision for income taxes	$	45,500	$	7,941	$	—

The difference in foreign tax rate of $0.5 million in fiscal year 2015 is a result of adjusting the U.S. blended statutory tax rate of 37.6% down to the Canadian statutory tax rate of 25.0%. 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The components of Triangle’s net deferred income tax assets and liabilities are as follows for fiscal years 2015 and 2014:

	For the Years Ended January 31,
(in thousands)	2015		2014
Current:
Assets:
Asset retirement obligations	$	1,394	$	1,071
Accruals		1,138		103
Total current assets		2,532		1,174
Valuation allowance		(1,193)		(492)
Total current assets after valuation allowance		1,339		682
Liabilities:
Hedging liabilities		(20,806)		(361)
Total current liabilities		(20,806)		(361)
Net current deferred income tax asset (liability)	$	(19,467)	$	321
Non-Current:
Assets:
Canadian oil and natural gas properties	$	—	$	6,080
United States net losses carried forward		48,443		33,129
Canadian net losses carried forward		—		1,905
Asset retirement obligations		1,198		416
Stock-based compensation		3,182		3,105
Property and equipment		—		157
Other		2,395		1,864
Total non-current assets		55,218		46,656
Valuation allowance		—		(8,165)
Total non-current assets after valuation allowance		55,218		38,491
Liabilities:
United States oil and natural gas properties		(56,531)		(29,536)
Investment in Caliber		(32,661)		(16,766)
Hedging liabilities		—		(451)
Total deferred non-current income tax liability		(89,192)		(46,753)
Net non-current deferred income tax liability	$	(33,974)	$	(8,262)
Total net deferred income tax liability	$	(53,441)	$	(7,941)

As of fiscal year 2013 the Company placed a full valuation allowance against deferred income taxes.  During the year ended January 31, 2014, Triangle had determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that the net U.S. deferred tax assets will be realized. Therefore, all deferred tax benefits were recognized in fiscal year 2014 and the full valuation allowance removed as part of the effective tax rate.

Triangle has also determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that the net Canadian deferred tax assets will not be realized. Therefore, all remaining Canadian deferred tax assets will have a full valuation allowance placed against them.  As a result of the cancellation of indebtedness related to the Elmworth intercompany, certain deferred tax assets and the related valuation allowance were reduced.  The key negative evidence relating to the Canadian deferred tax assets considered in this determination includes the following: (i) a history of both book and tax losses; (ii) cumulative losses in recent years; (iii) an expectation of tax losses during the next four to five years. Therefore, the combination of historical/cumulative losses as well as an expectation of book and taxable losses in the foreseeable future is the basis for the placement of a full valuation allowance against all of the Canadian deferred tax assets. 

The Company has net operating loss carryovers as of January 31, 2015 of $136.9 million for federal income tax purposes and $131.1 million for financial reporting purposes. The difference of $5.8 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

deductions reduce taxes payable.  The United States NOL carryforwards begin expiring in 2024.  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, 2015 and 2014, 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 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.

The tax years for fiscal years ending 2012 to 2015 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 2012 to 2015, except for Colorado which is open for the fiscal years 2011 to 2015.  We also file with various Canadian taxing authorities which remain open for fiscal years 2011 to 2015.

14. RELATED PARTY TRANSACTIONS

TUSA and an affiliate of Caliber have entered into certain midstream services agreements for (i) crude oil gathering, stabilization, treating and redelivery; (ii) natural gas compression, gathering, dehydration, processing and redelivery; (iii) produced water transportation and disposal services; and (iv) fresh water transportation for TUSA’s oil and natural gas drilling and production operations.  The agreements also include an acreage dedication from TUSA and a firm volume commitment by the Caliber affiliate for each service line.  TUSA has agreed to deliver minimum monthly revenues derived from the fees paid by TUSA to the Caliber affiliate for volumes of oil, natural gas, produced water, and fresh water for a primary term of 15 years beginning on the 2014 in-service dates for the Caliber facilities.  The aggregate minimum revenue commitment over the term of the agreements is $405.0 million, of which $359.2 million was outstanding at January 31, 2015.

TUSA and an affiliate of Caliber have also entered into a gathering services agreement, pursuant to which the Caliber affiliate will provide certain gathering-related measurement services to TUSA, and a fresh water sales agreement, that will make available certain volumes of fresh water for purchase by TUSA at a set per barrel fee for a primary term of five years from the in-service date anticipated to be in the first half of fiscal year 2016.  The fresh water sales agreement obligates TUSA to purchase all of the fresh water it requires for its drilling and operating activities exclusively from the Caliber affiliate, subject to availability, but it does not require TUSA to purchase a minimum volume of fresh water.

For the years ended January 31, 2015 and 2014, Caliber had $43.0 million and $15.6 million of revenue, respectively, of which $36.6 million and $15.0 million, respectively, were from TUSA.  Also, TUSA sold one salt water disposal well to an affiliate of Caliber for $1.5 million in fiscal year 2015. 

For the year ended January 31, 2015, Triangle received $0.9 million from Caliber for certain administrative services supplemental to those provided by Caliber employees.  The administrative services were provided pursuant to the October 1, 2012 Services Agreement between Triangle and Caliber.

15.  COMMITMENTS AND CONTINGENCIES

Triangle has entered into non-cancelable operating leases for office facilities and Rockpile has entered into various non-cancelable operating leases relating to (i) equipment for transportation, transloading and storage bulk commodities and light vehicles, (ii) transloading services and track rental and (iii) transportation equipment management, logistics and maintenance.  Rent expense incurred under the non-cancelable operating leases was $1.8 million, $0.8 million, and $0.5 million for the fiscal years ended January 31, 2015, 2014, and 2013, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of January 31, 2015, the future minimum lease payments under operating leases that have initial or remaining non-cancelable terms in excess of one year are:

Fiscal Years Ending January 31,	Annual Rental Amount (in thousands)
2016	$	2,807
2017	$	2,749
2018	$	2,357
2019	$	2,108
2020 and thereafter	$	2,686

As of January 31, 2015 the Company was subject to commitments on four drilling rig contracts.  Two of the drilling rig contracts expire in first quarter of fiscal year 2016, and the remaining contracts expire in the second and fourth quarters of fiscal year 2016.  In the event of early termination of the contracts, the Company would be obligated to pay an aggregate amount of approximately $10.2 million as of January 31, 2015 as required under the terms of the contracts. 

CEO Transaction Bonus ProgramPursuant to the Third Amended and Restated Employment Agreement, dated July 4, 2014 (the “Employment Agreement”), between the Company and Jonathan Samuels, our President and Chief Executive Officer, Mr. Samuels is entitled to a cash bonus payable upon a liquidity event involving RockPile or Caliber based on the percentage gain realized by the Company relative to its initial investment in the relevant entity (“Transaction Bonus”). The amount of this Transaction Bonus would be equivalent to 5% of that gain in Caliber for a Caliber liquidity event, and 3.5% of that gain in RockPile for a RockPile liquidity event. The right to the Transaction Bonus vests and becomes non-forfeitable in thirds on the first three anniversaries of the execution date of the Employment Agreement, with acceleration or forfeiture of the unvested portions of such right upon the occurrence of certain events. 

On January 31, 2015, Triangle and Mr. Samuels entered into a First Amendment to Third Amended and Restated Employment Agreement (the “First Amendment”) that modified the Employment Agreement to permit Triangle’s Board to authorize distributions to Mr. Samuels pursuant to his Transaction Bonus program in advance of defined liquidity events.  Any Board authorized distribution to Mr. Samuels related to the Transaction Bonus program would reduce any future award payable to Mr. Samuels following a liquidity event.  There are no clawback provisions in the First Amendment that would require Mr. Samuels to repay Triangle for any excess distributions or payments received.

In connection with the First Amendment, the Board authorized the payment of a Transaction Bonus to Mr. Samuels of $1.9 million which has been recorded as a liability as of January 31, 2015.  The payment of the Board authorized distribution will occur on the earlier of December 31, 2015 or when the WTI (NYMEX) price of oil exceeds $65 for 5 days over a consecutive 30 day period, subject to Mr. Samuel’s continuous employment with the Company through the applicable distribution date.  Because consummation of a liquidity event involving RockPile or Caliber is contingent on many unknown factors, the Company has determined that the contingent liability associated with such a bonus is not probable at January 31, 2015, and, therefore, no amounts have been recorded in the accompanying consolidated balance sheets other than the Board authorized distribution.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16.  SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Cash paid during the period for:
Interest expense	$	19,713	$	1,419	$	75
Income taxes	$	600	$	—	$	—
Non-cash investing activities:
Additions (reductions) to oil and natural gas properties through:
Increased accounts payable and accrued liabilities	$	47,838	$	30,785	$	36,654
Issuance of common stock	$	—	$	2,438	$	1,204
Capitalized stock based compensation	$	1,143	$	1,391	$	949
Change in asset retirement obligations	$	1,818	$	673	$	1,869
Capitalized interest	$	4,899	$	809	$	—
Acquisition of oilfield services equipment through notes payable and liabilities	$	—	$	1,990	$	—
Purchase of minority interest in RockPile	$	—	$	—	$	12,349
Non-cash financing activities:
Notes payable issued for redemption of RockPile B Units	$	1,041	$	—	$	—

17.  QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The Company’s quarterly financial information for fiscal years 2015 and 2014 is as follows:

	For the Year Ended January 31, 2015 (1)
	First		Second		Third		Fourth
(in thousands)	Quarter		Quarter		Quarter		Quarter
Total revenue	$	99,782	$	141,989	$	174,196	$	156,988
Income from operations (2)	$	22,347	$	38,489	$	33,345	$	1,202
Net income	$	14,542	$	14,552	$	25,398	$	38,905
Net income attributable to common stockholders	$	14,542	$	14,552	$	25,398	$	38,905
Net income per common share - basic	$	0.17	$	0.17	$	0.30	$	0.50
Net income per common share - diluted	$	0.15	$	0.15	$	0.26	$	0.42
	For the Year Ended January 31, 2014 (1)
	First		Second		Third		Fourth
(in thousands)	Quarter		Quarter		Quarter		Quarter
Total revenue	$	34,294	$	50,394	$	88,549	$	85,510
Income from operations (2)	$	4,328	$	12,973	$	17,160	$	12,501
Net income	$	5,211	$	6,799	$	47,221	$	14,249
Net income attributable to common stockholders	$	5,211	$	6,799	$	47,221	$	14,249
Net income per common share - basic	$	0.10	$	0.12	$	0.60	$	0.17
Net income per common share - diluted	$	0.10	$	0.12	$	0.50	$	0.15

(1) Amounts reported for the quarter period.

(2) There were immaterial reclassifications for the periods presented between operating expenses and other income (expense).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18.  SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

Oil and Natural Gas Reserve Information.  The following information concerning the Company’s oil and natural gas operations is provided pursuant to the FASB guidance regarding Oil and Gas Reserve Estimation and Disclosures.

At January 31, 2015, the Company’s oil and natural gas producing activities were conducted in the Williston Basin in the continental United States.  All of our proved reserves are in the Bakken or Three Forks formations in the North Dakota counties of McKenzie, Williams, Stark, or Dunn, or in the Montana counties of Roosevelt, Sheridan, Madison or Richland.  The Company has ceased all Canadian exploration and production activities and its oil and natural gas properties were fully impaired as of January 31, 2012. 

Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids, 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.  Such prices are also adjusted for regional price differentials; gathering, transportation, and processing; and other factors to arrive at prices utilized in the calculation of a standardized measure of discounted future net cash flows related to proved oil and natural gas reserves (“Standardized Measure”)

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, 2015.  Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”) an independent petroleum engineering firm, audited our estimate as of January 31, 2015, January 31, 2014, and January 31, 2013 of proved reserves and undiscounted and discounted future cash flows (before income taxes) from those proved reserves.  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. 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The reserve estimates presented in the following tables are expressed in thousands of barrels of oil (“Mbbls”), millions of cubic feet of natural gas (“MMcf”), thousands of barrels of natural gas liquids (“Mbbls”) and thousands of barrels of oil equivalent (“Mboe”).  

	Crude Oil	Natural Gas	NGL
	(Mbbls)	(MMcf)	(Mbbls)
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	—
Revisions of previous estimates	2,727	(859)	1,762
Purchase of reserves	6,836	4,714	690
Extensions, discoveries and other additions	12,059	11,064	1,599
Sale of reserves	(491)	(374)	—
Production	(1,754)	(626)	(70)
Total proved reserves at January 31, 2014	31,916	26,504	3,981
Revisions of previous estimates	2,087	1,475	(776)
Purchase of reserves	3,655	2,928	7
Extensions, discoveries and other additions	13,946	11,710	1,129
Sale of reserves	(2)	(3)	—
Production	(3,511)	(2,429)	(260)
Total proved reserves at January 31, 2015	48,091	40,185	4,081
Proved Developed Reserves included above:
January 31, 2012	538	202	—
January 31, 2013	4,985	5,906	—
January 31, 2014	13,734	10,930	1,440
January 31, 2015	29,605	24,136	2,350
Proved Undeveloped Reserves included above:
January 31, 2012	827	472	—
January 31, 2013	7,554	6,679	—
January 31, 2014	18,182	15,574	2,541
January 31, 2015	18,486	16,049	1,731

The following average prices are reflected in the calculation of the Standardized Measure:

	For the Years Ended January 31,
	2015		2014		2013
Oil price per barrel	$	79.71	$	93.09	$	84.76
Natural gas price per Mcf	$	6.09	$	3.99	$	5.23
Natural gas liquids price per barrel	$	34.61	$	44.10	$	—

Extensions and Discoveries in Fiscal Year 2015.  The 13.9 million barrels of oil, 11.7 billion cubic feet of natural gas, and 1.1 million barrels of natural gas liquids of proved reserves added by extensions and discoveries in North Dakota in fiscal year 2015 are primarily due to our increased completion of wells, particularly operated wells, and other parties completing wells offsetting our properties.  In fiscal year 2015, we participated in 145 gross (38.6 net) productive wells completed, and we added 37 gross (14.0 net) new proved undeveloped well locations discussed later in this Note.

Revisions in Fiscal Year 2015.The 2.1 million barrels upward revision in crude oil proved reserves in fiscal year 2015 was primarily due to longer production histories that favorably supported the increase in proved oil reserves.  The

98

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

1.5 billion cubic feet upward revision in natural gas reserves and the 0.8 million barrels decrease in NGL reserves reflect agreements and arrangements at the end of fiscal year 2015 to have the majority of our proved natural gas reserves processed to extract NGLs and dry residue gas that Triangle would sell to third parties. 

Purchases of Proved Properties in Fiscal Year 2015.The Company purchased certain proved properties which added reserves of 3.7 million barrels of oil and 2.9 billion cubic feet of natural gas proved reserves in fiscal year 2015. 

Proved Undeveloped Reserves.  At January 31, 2015, we had proved undeveloped oil and natural gas reserves of 22,892 Mboe, down 427 Mboe from 23,319 Mboe at January 31, 2014.  Changes in our proved undeveloped reserves are summarized in the following table:

	(Mboe)	Gross Wells	Net Wells
Proved Undeveloped Reserves at January 31, 2012	905	17	2.6
Became developed reserves in fiscal year 2013	(363)	(9)	(1.2)
Traded for net acres in other drill spacing units	(256)	(5)	(0.7)
Revisions	66	(1)	(0.1)
Acquisition of additional interests in PUD location	172	—	0.3
Additional proved undeveloped locations	8,144	57	18.9
Proved Undeveloped Reserves at January 31, 2013	8,668	59	19.8
Became developed reserves in fiscal year 2014	(3,701)	(32)	(7.9)
Traded for net acres in other drill spacing units	(353)	(4)	(0.8)
Revisions	84	—	—
Acquisitions	5,466	13	11.8
Extensions and discoveries of proved reserves	13,155	68	29.6
Proved Undeveloped Reserves at January 31, 2014	23,319	104	52.5
Became developed reserves in fiscal year 2015	(8,461)	(30)	(18.5)
Revisions	1,676	(14)	4.7
Acquisitions	528	6	1.3
Extensions and discoveries of proved reserves	5,830	37	14.0
Proved Undeveloped Reserves at January 31, 2015	22,892	103	54.0

During fiscal year 2015, we invested approximately $151.6 million (averaging $8.2 million per net well) related to the drilling and completion of the 30 gross (18.5 net) wells that converted 8,461 Mboe of proved undeveloped reserves to proved developed reserves.

For proved undeveloped (“PUD”) locations at January 31, 2015, the following table provides further information on the timing and status of operated and non-operated locations:

	PUD	Development Wells
	Locations	Gross	Net
Proved undeveloped locations:
For which Triangle operated wells are to be drilled and completed by January 31, 2020	79	79	49.9
For which non-operated wells were in-progress at January 31, 2015 and are expected to be completed in fiscal year 2016	—	—	—
That are non-operated wells with drilling permits	6	6	0.7
That are non-operated wells to be drilled by July 31, 2017	18	18	3.4
	103	103	54.0

99

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Standardized Measure of Discounted Future Net Cash Flows

Authoritative accounting guidance by the FASB requires the Company to calculate and disclose for January 31, 2015 and 2014 (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 2015 and 2014.  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 fiscal year-end estimated future proved reserve quantities. 

· Future cash inflows are proved reserves at the prices used in determining proved reserves, i.e., for crude oil, natural gas, or natural gas liquids, the average price during the year, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

· 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 fiscal year-end cost rates and assuming continuation of existing economic conditions.

· 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. 

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 summary sets forth the Company’s Standardized Measure for January 31, 2015, 2014, and 2013:

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Future cash inflows	$	4,219,155	$	3,252,079	$	1,128,676
Future costs:
Production		(1,586,288)		(1,118,508)		(333,185)
Development		(439,749)		(505,432)		(199,173)
Future income tax expense		(394,538)		(364,340)		(87,313)
Future net cash flows		1,798,580		1,263,799		509,005
10% discount factor		(977,088)		(690,564)		(297,653)
Standardized measure of discounted future net cash flows relating to proved reserves	$	821,492	$	573,235	$	211,352

Because the estimated salvage value of equipment exceeds the related abandonment costs for well plugging and site restoration costs, future development costs at January 31, 2015 of $439.7 million does not include any net abandonment costs.

100

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Standardized measure, beginning of period	$	573,235	$	211,352	$	29,428
Extensions and discoveries, net of future production and development costs		312,185		333,140		193,107
Sales, net of production costs		(210,505)		(123,786)		(31,502)
Previously estimated development costs incurred during the period		121,282		66,724		10,368
Revision of quantity estimates		24,115		73,598		15,910
Net change in prices, net of production costs		(141,200)		19,173		2,779
Acquisition of reserves		91,327		99,683		2,119
Divestiture of reserves		(72)		(7,341)		(3,273)
Accretion of discount		67,790		22,486		2,943
Changes in future development costs		57,259		7,699		801
Change in income taxes		(56,652)		(91,161)		(13,509)
Change in production timing and other		(17,272)		(38,332)		2,181
Standardized measure, end of period	$	821,492	$	573,235	$	211,352

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 amortization 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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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 should be 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, 2015, that disclosure controls and procedures were effective in providing reasonable assurance that material information is made known to them by others within the Company.

2.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 effected 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 consolidated 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.

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, 2015.  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.  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 (2013).

Our Chief Executive Officer and Chief Financial Officer concluded that our internal control over financial reporting was effective as of January 31, 2015.

The effectiveness of our internal control over financial reporting as of January 31, 2015 has been audited by KPMG LLP, our independent registered public accounting firm, as stated in their report.

102

3.Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f)) under the Exchange Actthat occurred during the fiscal quarter ended January 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

103

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, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Triangle Petroleum Corporation’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 Item 9A.2. Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

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

In our opinion, Triangle Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of January 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Triangle Petroleum Corporation and subsidiaries as of January 31, 2015 and 2014, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended January 31, 2015, and our report dated April 13, 2015 expressed an unqualified opinion on those consolidated financial statements.

(signed) KPMG LLP

Denver, Colorado

April 13, 2015

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ITEM 9B. OTHER INFORMATION

Not applicable. 

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 2015 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than May 31, 2015.

ITEM 11.  EXECUTIVE COMPENSATION

Information required under this item is incorporated by reference from the Triangle Petroleum Corporation definitive Proxy Statement for the 2015 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than May 31, 2015.

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

Information required under this item is incorporated by reference from the Triangle Petroleum Corporation definitive Proxy Statement for the 2015 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than May 31, 2015.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR INDEPENDENCE

Information required under this item is incorporated by reference from the Triangle Petroleum Corporation definitive Proxy Statement for the 2015 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than May 31, 2015.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required under this item is incorporated by reference from the Triangle Petroleum Corporation definitive Proxy Statement for the 2015 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than May 31, 2015.

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PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Exhibit No.	Description
3.1	Certificate of Incorporation of Triangle Petroleum Corporation, effective November 30, 2012, filed as Exhibit 3.1 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 17, 2014 and incorporated herein by reference.
3.2	Certificate of Amendment to the Certificate of Incorporation of Triangle Petroleum Corporation, effective December 4, 2013, filed as Exhibit 3.2 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 17, 2014 and incorporated herein by reference.
3.3	Bylaws of Triangle Petroleum Corporation, effective November 30, 2012, 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 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 13, 2013 and incorporated herein by reference.
4.6	Rights Agreement, dated August 28, 2013, between Triangle Petroleum Corporation and ActOil Bakken, LLC, filed as Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 30, 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†	CEO Stand-Alone Stock Option Agreement, dated July 4, 2013, between Triangle Petroleum Corporation and Jonathan Samuels, filed as Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 10, 2013 and incorporated herein by reference.
10.4†	Triangle Petroleum Corporation 2014 Equity Incentive Plan, filed as Exhibit 10.1 to the Current Report onForm 8-Kfiled with the Securities and Exchange Commission on May 30, 2014 and incorporated herein by reference.
10.5†	Third Amended and Restated Employment Agreement, dated July 4, 2013, between Triangle Petroleum Corporation and Jonathan Samuels, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 10, 2013 and incorporated herein by reference.

106

Exhibit No.	Description
10.6†	First Amendment to Third Amended and Restated Employment Agreement, dated January 31, 2015, between Triangle Petroleum Corporation and Jonathan Samuels, filed as Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on February 5, 2015 and incorporated herein by reference.
10.7†	Amended and Restated Employment Agreement, dated September 9, 2014, between Triangle Petroleum Corporation and Justin Bliffen, filed as Exhibit 10.1 to the Current Report onForm 8-Kfiled with the Securities and Exchange Commission on September 11, 2014 and incorporated herein by reference.
10.8†	Employment Agreement, dated December 14, 2012, by and between RockPile Management, LLC and Robert Dacar, filed as Exhibit 10.2 to the Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on June 9, 2014 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	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.
10.11	Stock Purchase Agreement, dated August 6, 2013, between Triangle Petroleum Corporation and TIAA Oil and Gas Investments, LLC, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 30, 2013 and incorporated herein by reference.
10.12	Second Amended and Restated Contribution Agreement, dated January 31, 2015, 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 February 5, 2015 and incorporated herein by reference.
10.13	Purchase and Sale Agreement, dated May 14, 2014, by and among Marathon Oil Company, as Seller, and Triangle USA Petroleum Corporation, as Purchaser, filed as Exhibit 10.1 to the Current Report onForm 8-Kfiled with the Securities and Exchange Commission on May 19, 2014 and incorporated herein by reference.
10.14	Purchase and Sale Agreement, dated August 5, 2013, by and among Kodiak Oil & Gas (USA) Inc. and Kodiak Williston, LLC, collectively, as Seller, and Triangle USA Petroleum Corporation, as Purchaser, filed as Exhibit 10.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 30, 2013 and incorporated herein by reference.
10.15	Credit Agreement, dated March 25, 2014, between RockPile Energy Services, LLC, as Borrower, the Lenders Party Hereto, Citibank, N.A., as Administrative Agent and Collateral Agent, and Citibank, N.A. and Wells Fargo Bank, National Association, as Joint Lead Arrangers and Joint Bookrunners, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 31, 2014 and incorporated herein by reference.
10.16	Amendment No. 1 to Credit Agreement and Incremental Commitment Agreement, dated November 13, 2014, between RockPile Energy Services, LLC, as Borrower, Citibank, N.A., as Administrative Agent and Collateral Agent, and the banks and other financial institutions signatories thereto, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on November 19, 2014 and incorporated herein by reference.
10.17	Indenture, dated July 18, 2014, among Triangle USA Petroleum Corporation, the guarantor named therein and Wells Fargo Bank, National Association, as trustee, relating to the 6.75% Senior Notes due 2022, filed as Exhibit 10.1 to the Current Report onForm 8-Kfiled with the Securities and Exchange Commission on July 18, 2014 and incorporated herein by reference.

107

Exhibit No.	Description
10.18	Form of 6.75% Senior Notes due 2022, filed as Exhibit 10.2 to the Current Report onForm 8-Kfiled with the Securities and Exchange Commission on July 18, 2014 and incorporated herein by reference.
10.19	Second Amended and Restated Credit Agreement, dated November 25, 2014, among Triangle USA Petroleum Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and Issuing Lender, and the Lenders Named Therein, filed as Exhibit 10.1 to the Current Report onForm 8-Kfiled with the Securities and Exchange Commission on December 2, 2014 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.
23.1*	Consent of Cawley, Gillespie & Associates, Inc.
23.2*	Consent of KPMG LLP.
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*	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.

† Management Contract or Compensatory Plan or Arrangement.

108

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 13,  2015	By:	/s/ JONATHAN SAMUELS
	Jonathan Samuels
	President and Chief Executive Officer

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Jonathan Samuels and Justin Bliffen, 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.

6
Name	Position	Date
/s/ JONATHAN SAMUELS	President and Chief Executive Officer, Director	April 13,  2015
Jonathan Samuels	(principal executive officer)
/s/ JUSTIN BLIFFEN	Chief Financial Officer (principal financial officer)	April 13,  2015
Justin Bliffen
/s/ DOUGLAS J. GRIGGS	Chief Accounting Officer (principal accounting officer)	April 13,  2015
Douglas J. Griggs
/s/ PETER HILL	Director (Chairman of the Board)	April 13,  2015
Peter Hill
/s/ ROY ANEED	Director	April 13,  2015
Roy Aneed
/s/ GUS HALAS	Director	April 13,  2015
Gus Halas
/s/ RANDAL MATKALUK	Director	April 13,  2015
Randal Matkaluk
/s/ F. GARDNER PARKER	Director	April 13, 2015
F. Gardner Parker

109

UNITS OF MEASUREMENT AND GLOSSARY OF INDUSTRY TERMS

Units of Measurement

The following presents a list of units of measurement used throughout this annual report:

Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume.

Bbl/d – Bbl per day.

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

Boe/d – Boe per day.

Btu – One British thermal unit – a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.

Mbbls – One thousand barrels of crude oil.

Mboe – One thousand barrels of crude oil equivalent.

Mcf – One thousand cubic feet of natural gas volume.

MMboe – One million barrels of crude oil equivalent.

MMbtu – One million British thermal units.

MMcf – One million cubic feet of natural gas volume.

Glossary of Industry Terms

The following are abbreviations and definitions of some of the oil and natural gas industry terms used in this annual report:

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

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.

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 within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

DSU or 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 or dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. 

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

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.

110

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 may contain liquids.

GHGs. Gases, such as carbon dioxide and methane, that when released into the atmosphere contribute to, or are believed to contribute to, global warming.  These gases are commonly known as “greenhouse gases.”

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 or ceramic material) into the formation under high pressure.  This creates artificial fractures in the reservoir rock, which increases permeability and porosity.

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 rental, bonus and/or royalty payments.  Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.

Natural Gas Liquids or NGLs. Liquid hydrocarbons that are extracted from the natural gas stream. NGL products include ethane, propane, butane, natural gasoline and heavier 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.

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 and oversees the well operations on behalf of all the well’s working interest owners.

NYMEX. New York Mercantile Exchange.

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 thereon.

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. This term 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. 

Pooling. Pooling is a technique used by oil and natural gas development companies to organize an oil or natural gas field. 

Pressure pumping. Pumping a fluid down a well for the purpose of improving production from the well. 

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. 

Proppant. Particles that are 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 quantities of hydrocarbons.

111

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 average prices for the preceding 12-month period and costs in effect as of 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. 

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.

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 relevant well, except for state and local production taxes.

Seismic. Geophysical data that depicts the subsurface strata. 

Spacing.  The distance between wells producing from the same reservoir.  Spacing is often expressed in terms of wells per acre 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.

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 a bit that is equipped for oil or natural gas production when the well is completed.

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.

WTI. West Texas Intermediate, also known as Texas light sweet, is a grade of crude oil used as a benchmark in oil pricing. This grade is described as light because of its relatively low density, and sweet because of its low sulfur content.

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 operations are then alternated between each of the wells, (e.g. fracturing 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 fracturing between the two wells.

112

EX-21.1

 EXHIBIT 21.1

Triangle Petroleum Corporation

List of Subsidiaries

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

EX-23.1

exhibit 23.1

Consent of Independent Petroleum Engineers

Cawley, Gillespie & Associates, Inc.

PETROLEUM CONSULTANTS

13640 BRIARWICK DRIVE, SUITE 100
AUSTIN, TEXAS 78729-1707
512-249-7000 306 WEST SEVENTH STREET, SUITE 302
FORT WORTH, TEXAS 76102-4987
817- 336-2461
www.cgaus.com 1000 LOUISIANA STREET, SUITE 625
HOUSTON, TEXAS 77002-5008
713-651-9944

We hereby consent to the references to our firm, in the context in which they appear, and to the information regarding our reports on the reserves estimates of Triangle Petroleum Corporation (the “Company”) as of January 31, 2013, January 31, 2014, and January 31, 2015 included in the Company’s Annual Report on Form 10-K for the year ended January 31, 2015, as well as in the notes to the financial statements included therein (the “Annual Report”).

We also consent to the incorporation by reference in the Company’s registration statements (Nos. 333-198175, 333-198174, 333-188353, 333-175740 and 333-171959) on Form S-8 and registration statements (Nos. 333-194861, 333-188354, 333-184519, 333-173357 and 333-171958) on Form S-3 of the references to our firm, in the context in which they appear, and to the information regarding our reports on reserves estimates of the Company as of January 31, 2013, January 31, 2014, and January 31, 2015 included in the Annual Report.

	Very truly yours,
	W. Todd Brooker, P.E.
	Senior Vice President
	Cawley, Gillespie & Associates
	Texas Registered Engineering Firm F-693
April 13, 2015
Austin, TX

EX-23.2

EXHIBIT 23.2

Consent of Independent Registered Public Accounting Firm

The Board of Directors

Triangle Petroleum Corporation:

We consent to the incorporation by reference in the registration statements (Nos. 333-194861, 333-188354, 333-184519, 333-173357, and 333-171958) on Form S-3 and (Nos. 333-198175,333-198174,333-188353, 333-175740, and 333-171959) on Form S-8, of Triangle Petroleum Corporation of our reports dated April 13, 2015, with respect to the consolidated balance sheets of Triangle Petroleum Corporation and subsidiaries as of January 31, 2015 and 2014, and the related consolidated statements of operations, cash flows, and stockholders’ equity for each of the years in the three-year period ended January 31, 2015, and the effectiveness of internal control over financial reporting as of January 31, 2015, which reports appear in the January 31, 2015 annual report on Form 10-K of Triangle Petroleum Corporation.

	(signed) KPMG LLP
Denver, Colorado
April 13, 2015

EX-31.1

 EXHIBIT 31.1

CERTIFICATION

I, Jonathan Samuels, certify that:
	1.	I have reviewed this annual report on Form 10-K of Triangle Petroleum Corporation;
	2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
		(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
		(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
	5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
		(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonable likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
		(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: April 13, 2015

/s/ JONATHAN SAMUELS

Jonathan Samuels

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Justin Bliffen, certify that:
	1.	I have reviewed this annual report on Form 10-K of Triangle Petroleum Corporation;
	2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
	3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
	4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
		(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
		(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
	5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
		(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonable likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
		(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: April 13, 2015

/S/

/s/ JUSTIN BLIFFEN

Justin Bliffen

Chief Financial Officer

EX-32.1

 EXHIBIT 32.1

CERTIFICATIONS OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER

PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Jonathan Samuels, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report of Triangle Petroleum Corporation on Form 10-K for the fiscal year ended January 31, 2015 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in this Annual Report on Form 10-K fairly presents in all material respects the financial condition and results of operations of Triangle Petroleum Corporation.

	By:	/s/ JONATHAN SAMUELS
Date: April 13, 2015	Name:	Jonathan Samuels
	Title:	President and Chief Executive Officer

I, Justin Bliffen, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report of Triangle Petroleum Corporation on Form 10-K for the fiscal year ended January 31, 2015 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in this Annual Report on Form 10-K fairly presents in all material respects the financial condition and results of operations of Triangle Petroleum Corporation.

5
	By:	/s/ JUSTIN BLIFFEN
Date: April 13, 2015	Name:	Justin Bliffen
	Title:	Chief Financial Officer

EX-99.1

EXHIBIT 99.1

Cawley, Gillespie & Associates, Inc.

PETROLEUM CONSULTANTS

13640 BRIARWICK DRIVE, SUITE 100
AUSTIN, TEXAS 78729-1707
512-249-7000 306 WEST SEVENTH STREET, SUITE 302
FORT WORTH, TEXAS 76102-4987
817- 336-2461
www.cgaus.com 1000 LOUISIANA STREET, SUITE 625
HOUSTON, TEXAS 77002-5008
713-651-9944

March 5, 2015

Triangle Petroleum Corporation
1200 17th St., Suite 2600
Denver, CO 80202
	Re:     Reserves Audit
	Triangle Petroleum Corporation Interests
	Total Proved Reserves as of January 31, 2015
	Pursuant to the Guidelines of theSecurities and Exchange Commission forReporting Corporate Reserves andFuture Net Cash Flows

Gentlemen:

At the request of Triangle Petroleum Corporation  (“Company”), Cawley, Gillespie & Associates, Inc. (CG&A)has conducted areserves audit of Company estimates of proved reserves and projected future cash flows (excluding income taxes)as of January 31, 2015 (the “Effective Date”) and attributable to the Company’s oil and gas properties. The Company’s common stock is publicly traded under the symbol TPLM on the NYSE MKT stock exchange. The purpose of this report is for its inclusion in Company’s Annual Report for the year ended January 31, 2015 being filed on Form 10-K with the U.S. Securities and Exchange Commission (“SEC”).

CG&A examined 100% of the Company’sestimates of proved reserves.Approximately 99.0% of the Company’s proved reserves are for oil and gas properties in various fields in North Dakota.  The remainder is for interests in 13 Montana producing wells near the North Dakota border.

Our examination included all methods and procedures we considered necessary under the circumstances to render the opinion set forth herein.The estimatesas prepared by the Companyand audited by CG&A are summarized as follows:

					Cumulative
	Net Reserves				Cash Flow
	Oil	Natural Gas	NGL	Net	Disc. @ 10%
	(Mbbls)	(MMcf)	(Mbbls)	MBOE	(M$)
Total Proved	48,091.3	40,185.3	4,081.4	58,870.2	982,813.1
Proved Developed Producing	25,629.1	21,233.6	1,993.8	31,161.8	730,600.6
Proved Developed Non-Prod.	3,976.1	2,902.8	356.5	4,816.4	72,702.1
Proved Undeveloped	18,486.1	16,049.0	1,731.1	22,892.0	179,510.4

Triangle Petroleum Corporation

Reserves Audit

March 5, 2015

Page 2

The Company’s Reservoir Manager is the technical person primarily responsible for overseeing the preparation of the Company’s reserve estimates. The Company and the Reservoir Manager represent that he (i) has been a Petroleum Engineer since 1995, (ii) has 20 years’ experience as a petroleum engineer, (iii) is a member of the Society of Petroleum Engineers and (iv) holds an undergraduate degree in petroleum engineering.

Future revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes.  In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its cumulative discounted cash flow or “present worth”.  The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

The oil reserves include oil and condensate.  Oil volumes are expressed in barrels (42 U.S. gallons).  Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.Our audit involved proved reserves only and did not include any probable or possible reserves, nor have any values been attributed to interest in acreage beyond the location for which undeveloped reserves have been estimated.

Hydrocarbon Pricing

The base SEC oil, gas and NGL prices calculated by the Company for January 31, 2015 were $91.22 per barrel,  $4.20 per MMBTU and $50.07 per barrel, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil, gas and NGL prices are based upon WTI-Cushing (OK), Henry Hub (LA) and Conway (KS) spot prices, respectively, as published by Bloomberg for February 1, 2014 through January1, 2015.

The base prices shown above were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. After these adjustments, the net realized prices over the life of the proved properties were estimated to be $78.15 per barrel for oil, $4.067 per MCF for gas and $8.43 per barrel for NGLs.  At January 31, 2015, a portion of the Company’s sales of natural gas are before gas processing, whereby the BTU content and sales value of the gas at point of sale are very close to the base price at Henry Hub. At January 31, 2015, the Company had no derivative instruments designated as price hedges, and therefore, the potential effects of derivative instruments designated as price hedges of oil and gas volumes are not reflected in the Company's future cash flows related to proved reserves in accordance with SEC guidelines.

Commercial Parameters

Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, gas shrinkage, ad valorem taxes, severance taxes, lease operating expenses and investments were calculated and prepared by the Company and were reviewed by us for reasonableness.  

The future per-well operating expenses for proved reserves reflect economic conditions at January 31, 2015 whereby fixed and variable cost rates at that date were applied to existing and expected operations of the wells, including allowance for repairs and maintenance, based on analysis of historical

Triangle Petroleum Corporation

Reserves Audit

March 5, 2015

Page 3

monthly operating expenses in the year ended January 31, 2015 and agreements in place at January 31, 2015.These operating expenses include only those costs directly applicable to the leases or wells.  For non-operated properties, the operating expenses include the COPAS overhead costs that are allocated directly to the leases and wells under terms of joint operating agreements.

Investments applied by the Companyfor future development are based on authorizations for expenditure (AFE) for the proposed work or actual costs for similar projects. CG&A has reviewed a representative sample of the historical AFEs and the proposed drilling and completion capital costs applied in the valuation, and both the investment amounts and scheduling appear reasonable and reliable.

Severance and production taxes were applied at standard rates as published by the State of North Dakota and Montana. For North Dakota wells, severance taxes were applied at 11.5 percent of net oil revenue and at $0.0982 per MCF of net wet gas sales. For Montana production, severance taxes were applied at 9.00 percent of net revenue. North Dakota and Montana do not assess ad valorem taxes on oil and gas sales.

While it may reasonably be anticipated that the future prices received for the sale of production may increase or decrease from existing levels, such changes were omitted from consideration in making this evaluation, in accordance with SEC guidelines.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 2 and 3of the Appendix following this letter. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein.Government policies and market conditions different from those employed in this report may cause (1) the total quantity of oil or gas to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from those presented in this report.  However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

The Company’s proved undeveloped reserves are for103proved undeveloped locations, with96targeting the Middle Bakken reservoir and 7 targeting the Three Forks formation.Each of these drilling locations proposed as part of the Company’s development plans conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, the Company has indicated it has everyintent to complete this development plan within the next five years. Furthermore, the Company has demonstrated that it has the proper company staffing, financial backing and prior development success to reasonably ensure this five-year development plan will be fully executed, assuming no significant adverse future changes from oil and gas prices and operating cost rates reflected in the estimation of proved reserves at the Effective Date.

Reserve Estimation Methods

The methods employed in estimating reserves are described in page1of the Appendix following this letter. Reserves for producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy. In general, these methods relied upon extrapolations of historical production and pressure data available through January 31, 2015 in those cases where such data were considered to be reliable.

Triangle Petroleum Corporation

Reserves Audit

March 5, 2015

Page 4

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using analogy with production performance of offsetting producing well(s) and nearby producing well(s). Analogy with such producing wells provides a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves for Company properties, due to the mature nature of the Company’s properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this audit.

The estimation of economically recoverable oil and gas reserves and related future net cash flows requiresconsideration of many factors and assumptions as part of our analysis. Consideration is given to, but not limited to, the use of reservoir parameters derived from engineering and geoscience data which cannot be measured directly, forecasts of future production rates, andeconomic criteria based on current costs and SEC pricing requirements.  As per SEC guidelines  (see Appendix page 2), proved reserves are those quantities of oil and gas that can be estimated with reasonable certaintyto be economically producible from known reservoirs, under existing economic conditions, as of the effective date of the report. The Company has informed us that they have furnished us all of the engineering data, geoscience data, reports and other data required for this analysis.

General Discussion

An on-site field inspection of the properties has not been performed. The mechanical operation and condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. (“CG&A”).The Company’s estimates of abandonment costs for Bakken properties were used in this report.CG&A has not performed a detailed study of the abandonment costs or salvage values associated with the Company properties.  Possible environmental liability related to the Company properties has not been investigated nor considered.

The estimates and forecasts were based upon interpretations of data furnished by the Company and other data available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third-party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

Audit Opinion

In our opinion, the Company’s estimates of future reserves for the audited properties were prepared in accordance with generally accepted petroleum engineering and evaluation principles for the estimation of future reserves as set forth in the Society of Petroleum Engineers' Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information. Furthermore, we found no bias in the utilization and analysis of data in estimates for these properties.

In our opinion,  the overall proved reserves and future net cash flows as estimated by the Company are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forthin the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers.

Triangle Petroleum Corporation

Reserves Audit

March 5, 2015

Page 5

In general, we were in reasonable agreement with the Company's estimates of proved reserves, future production and discounted future net cash flow for the properties which we reviewed; however, in certain cases there was more than an acceptable variance between the Company's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to the Company when its reserve estimates were prepared. In these cases, the Company revised its estimates to be in alignment with our estimates. As such, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by Triangle Petroleum Corporation.

It should be understood that our audit and the development of our reserves forecasts do not constitute a complete reserve study of the oil and gas properties of the Company.  In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by the Company with respect to ownership interests, oil and gas production, historical costs of operation and developments, product prices, agreements relating to current and future operations and sales of production.Furthermore, if in the course of our examination something came to our attention which brought into question the validity or sufficiency of any of such information, we did not rely on such information until we had properly resolved our questions or independently verified such information.

Professional Qualifications and Usage

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.

This audit report was prepared exclusively for Triangle Petroleum Corporationand may not be used by other parties without prior written consent. We do not own an interest in the audited properties or Triangle Petroleum Corporation and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this audit. Our work-papers and related data utilized in the preparation of these estimates are available in our office.

Sincerely,

CAWLEY, GILLESPIE & ASSOCIATES, INC.

Texas Registered Engineering Firm (F-693)

W. Todd Brooker, P.E.

Senior Vice President

APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) productionperformance, (2) materialbalance, (3) volumetric and (4) analogy.  Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data.  However, a large variation exists in the quality, quantity and types of information available on individual properties.  Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc.  As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data.  The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance.  This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance.  The only information required is production history.  Capacity production can usually be analyzed from graphs of rates versus time or cumulative production.  This procedure is referred to as “decline curve” analysis.  Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components.  Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material balance.  This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships.  This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir.  The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids.  Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available.  Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use.  Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric.  This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place.  The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location.  The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods.  These are most commonly newly developed and/or no-pressure depleting reservoirs.  The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir.  Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy.  This method, which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The analogy method may also be applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained in this manner are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates.  These estimates are subject to continuing change as additional information becomes available.  Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

Cawley, Gillespie & Associates, Inc. Appendix Page 1

APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

“(22)Proved oil and gas reserves.  Proved oil and gas reserves are those quantities of oil and 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“(i)The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

“(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

“(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

“(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

“(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be 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.

“(6)Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

“(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“(31)Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

“(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

“(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

“(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

Cawley, Gillespie & Associates, Inc. Appendix Page 2

“(18)Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

“(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv)See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

“(17)Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi)Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K.”  This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

“(26)Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”

Cawley, Gillespie & Associates, Inc. Appendix Page 3

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Quarterly Financial Information (Tables)

12 Months Ended

Jan. 31, 2015

Quarterly Financial Information [Abstract]

Schedule Of Quarterly Financial Information

	For the Year Ended January 31, 2015 (1)
	First		Second		Third		Fourth
(in thousands)	Quarter		Quarter		Quarter		Quarter
Total revenue	$	99,782	$	141,989	$	174,196	$	156,988
Income from operations (2)	$	22,347	$	38,489	$	33,345	$	1,202
Net income	$	14,542	$	14,552	$	25,398	$	38,905
Net income attributable to common stockholders	$	14,542	$	14,552	$	25,398	$	38,905
Net income per common share - basic	$	0.17	$	0.17	$	0.30	$	0.50
Net income per common share - diluted	$	0.15	$	0.15	$	0.26	$	0.42
	For the Year Ended January 31, 2014 (1)
	First		Second		Third		Fourth
(in thousands)	Quarter		Quarter		Quarter		Quarter
Total revenue	$	34,294	$	50,394	$	88,549	$	85,510
Income from operations (2)	$	4,328	$	12,973	$	17,160	$	12,501
Net income	$	5,211	$	6,799	$	47,221	$	14,249
Net income attributable to common stockholders	$	5,211	$	6,799	$	47,221	$	14,249
Net income per common share - basic	$	0.10	$	0.12	$	0.60	$	0.17
Net income per common share - diluted	$	0.10	$	0.12	$	0.50	$	0.15

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Hedging And Commodity Derivative Financial Instruments (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Realized commodity derivative gains (losses)	$ 11,422	$ (4,643)
Commodity derivatives gains (losses)	64,050	1,082	(3,570)
Crude Oil Derivative Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Number of counterparties	3
Crude Oil Derivative Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized commodity derivative gains (losses)	11,422	(4,643)
Unrealized commodity derivative gains (losses)	52,628	5,725	(3,570)
Commodity derivatives gains (losses)	$ 64,050	$ 1,082	$ (3,570)

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Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Jan. 31, 2015	Jan. 31, 2014	Jul. 18, 2014
Debt Instrument [Line Items]
5% Convertible Note	$ 135,877	$ 129,290
Credit facility	224,159	204,515
Other notes and mortgages payable	10,605	9,403
TUSA 6.75% notes	429,500
Total debt	800,141	343,208
Less current portion of credit facility		(8,450)
Other notes and mortgages payable	(503)	(401)
Total long-term debt	799,638	334,357
TUSA Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	6.75%		6.75%
Convertible Notes [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	5.00%	5.00%
TUSA [Member]
Debt Instrument [Line Items]
Credit facility	119,272	183,000
Rockpile [Member]
Debt Instrument [Line Items]
Credit facility	$ 104,887	$ 21,515

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Capital Stock (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014
Capital Stock [Line Items]
Shares reserved for issuance	106,400,000
Common stock, shares issued	75,174,442	85,735,827
Common stock, shares outstanding	75,174,442	85,735,827
Stock Repurchase authorised (Tranche 1)	$ 25.0
Common stock repurchased (in shares)	11,400,000
Common stock repurchased	$ 76.8
Authorized shares remaining repurchase	4,949,393
2011 Omnibus Incentive Plan
Capital Stock [Line Items]
Shares reserved for issuance	3,600,000
2014 Plan
Capital Stock [Line Items]
Shares reserved for issuance	4,600,000
CEO Stand-Alone Stock Option Agreement
Capital Stock [Line Items]
Shares reserved for issuance	6,000,000
Convertible Notes Payable [Member]
Capital Stock [Line Items]
Shares reserved for issuance	17,000,000

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Hedging And Commodity Derivative Financial Instruments (Details 2)	12 Months Ended
	Jan. 31, 2015	Feb. 28, 2015
Fiscal 2016 Collar [Member]
Derivative [Line Items]
End date	Fiscal Year 2016
Contract type	Collar
Basis	NYMEX
Quantity, (bbls)	4,356
Put strike price	86.85
Call strike price	98.63
Notional Disclosures [Abstract]
Notional amount per day (in Bbl)	4,356
October 2015 Through December 2016 Member | Crude Oil Derivative Contract [Member] | Subsequent Event [Member]
Notional Disclosures [Abstract]
Derivative, Swap Type, Average Fixed Price		60.07
January 2016 Through December 2016 Member | Crude Oil Derivative Contract [Member] | Subsequent Event [Member]
Notional Disclosures [Abstract]
Derivative, Swap Type, Average Fixed Price		60.30

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Fair Value Measurements (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014
Crude Oil Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	$ 62,248	$ 2,147
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Earn-out liability	(1,825)	(1,739)
Fair Value, Measurements, Recurring [Member] | Equity Investment Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	504	39,734
Fair Value, Measurements, Recurring [Member] | Crude Oil Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	62,248	2,147
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Earn-out liability	(1,825)	(1,739)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Crude Oil Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	62,248	2,147
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Investment Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	$ 504	$ 39,734

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Segment Reporting (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Jan. 31, 2015 segment	Jan. 31, 2014	Jan. 31, 2013
Segment Reporting [Abstract]
Number of reportable segments	2
Deferred Revenue	$ 123.6	$ 91.0	$ 34.7
Deferred gross profit	$ 1.3	$ 2.2

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Equity Investment And Equity Investment Derivatives (Tables)

12 Months Ended

Jan. 31, 2015

Equity Investment [Abstract]

Schedule Of Equity Investment In Caliber

	Expiration		Strike Price at		As of January 31,
	Date		January 31, 2015		2015	2014
Class A Units		—		—	7,000,000	3,000,000
Class A Trigger Units		—		—	—	4,000,000
Class A Trigger Unit Warrants		—		—	—	1,600,000
Series 1 Warrants		October 1, 2024	$	12.78	5,600,000	4,000,000
Series 2 Warrants		October 1, 2024	$	22.09	2,400,000	2,400,000
Series 3 Warrants		September 12, 2025	$	22.09	3,000,000	3,000,000
Series 4 Warrants		September 12, 2025	$	28.09	2,000,000	2,000,000

Summary of activities related to company's equity investment

	For the Years Ended January 31,
(in thousands)	2015		2014
Balance at beginning of year	$	68,536	$	11,768
Capital contributions		—		18,000
Distributions		(6,080)		(3,150)
Equity investment share of net income before intra-company profit eliminations		1,402		2,184
Change in fair value of:
Class A Trigger Units (1)		1,745		38,091
Class A Trigger Unit Warrants (2)		532		234
Series 1 Warrants		(1,241)		926
Series 2 Warrants		(254)		254
Series 3 Warrants		(207)		207
Series 4 Warrants		(22)		22
Total changes in fair value		553		39,734
Balance at end of year	$	64,411	$	68,536
Fair value of trigger unit warrants and warrants at end of year	$	504	$	39,734

(1) The change in value was prior to the vesting of the Class A Trigger Units into Class A Units on June 30, 2014.

(2) On June 30, 2014, the 1,600,000 Class A Trigger Unit Warrants then outstanding automatically converted into Series 1 Warrants upon the Company’s vesting of the Class A Trigger Units, resulting in an aggregate of 5,600,000 Series 1 Warrants outstanding.

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Fair Value Measurements (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014
Class A Triggering Units [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Beginning balance	$ 38,091
Initial recognition of equity investment derivative assets		38,091
Net unrealized gain	1,745
Conversion to Class A units	(39,836)
Ending balance		38,091
Warrants [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Beginning balance	1,696
Initial recognition of equity investment derivative assets		1,696
Net unrealized gain	(1,192)
Ending balance	$ 504	$ 1,696

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Share-Based Compensation (Details 3) (Restricted Stock Units (RSUs) [Member], USD $)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding, Unvested Beginning Balance	2,875,628	2,524,085	2,488,342
Outstanding, Weighted-Average Award Date Fair Value, Beginning Balance	$ 6.62	$ 6.68	$ 7.02
Units granted, number of units	1,523,700	1,440,133	1,041,400
Units granted, Weighted Average Award Date Fair Value	$ 9.42	$ 6.95	$ 6.37
Units forfeited, Number of Shares	(394,921)	(141,909)	(5,600)
Units forfeited, Weighted Average Award Date Fair Value	$ 7.21	$ 6.58	$ 7.59
Units that vested, Number of Shares	(1,090,362)	(946,681)	(1,000,057)
Units that vested, Weighted Average Award Date Fair Value	$ 7.04	$ 6.71	$ 6.90
Outstanding, Unvested Ending Balance	2,914,045	2,875,628	2,524,085
Outstanding, Weighted-Average Grant Date Fair Value, Ending Balance	$ 7.92	$ 6.62	$ 6.68

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Quarterly Financial Information (Unaudited) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Jan. 31, 2015	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Oct. 31, 2013	Jul. 31, 2013	Apr. 30, 2013	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Quarterly Financial Information [Abstract]
Total revenue	$ 156,988	$ 174,196	$ 141,989	$ 99,782	$ 85,510	$ 88,549	$ 50,394	$ 34,294	$ 572,955	$ 258,747	$ 60,361
Income (loss) from operations	1,202	33,345	38,489	22,347	12,501	17,160	12,973	4,328	95,383	46,962	(8,261)
Net income (loss)	38,905	25,398	14,552	14,542	14,249	47,221	6,799	5,211	93,397	73,480	(14,484)
Net income (loss) attributable to common stockholders	$ 38,905	$ 25,398	$ 14,552	$ 14,542	$ 14,249	$ 47,221	$ 6,799	$ 5,211	$ 93,397	$ 73,480	$ (13,760)
Net income (loss) per common share - basic	$ 0.50	$ 0.30	$ 0.17	$ 0.17	$ 0.17	$ 0.60	$ 0.12	$ 0.10	$ 1.12	$ 1.07	$ (0.31)
Net income (loss) per common share - diluted	$ 0.42	$ 0.26	$ 0.15	$ 0.15	$ 0.15	$ 0.50	$ 0.12	$ 0.10	$ 0.97	$ 0.91	$ (0.31)

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Oil And Natural Gas Properties (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Property And Equipment [Abstract]
Proved	$ 90,920	$ 80,201	$ 623
Unproved	47,858	41,377	20,570
Exploration	180,174	96,731	55,583
Development	226,765	216,046	91,666
Oil and natural gas expenditures	545,717	434,355	168,442
Asset retirement obligation, net	1,818	676	370
Total costs incurred	$ 547,535	$ 435,031	$ 168,812

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Share-Based Compensation (Details 6)	12 Months Ended
	Jan. 31, 2015
Share-Based Compensation [Abstract]
Risk free rate	1.06%
Expected volatility	54.00%
Weighted average expected stock option life (years)	3 years

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Long-term Purchase Commitment [Line Items]
Lease operating expense	$ 1.8	$ 0.8	$ 0.5
Early contract termination fee	10.2
Chief Executive Officer [Member]
Long-term Purchase Commitment [Line Items]
Contingent liability for bonus payout to CEO	$ 1.9
Threshold WTI price of oil for payment of a Transaction Bonus	65
Number of days over specified period during which oil price should exceed specified value	5
Period during which oil price should exceed specified value over specified number of days	30 days
Caliber Midstream Partners, L.P. [Member] | Chief Executive Officer [Member]
Long-term Purchase Commitment [Line Items]
Percentage bonus payout of gain on sale of subisdiary	5.00%
Rockpile [Member] | Chief Executive Officer [Member]
Long-term Purchase Commitment [Line Items]
Percentage bonus payout of gain on sale of subisdiary	3.50%

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Income Taxes (Details) (USD $)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Federal statutory rate	35.00%
Difference in foreign tax rates	$ 539,000	$ 164,000	$ 28,000
US effective tax rate	37.60%
Canadian effective tax rate	25.00%
Unrecognized Tax Benefits	0	0
Provision for uncertain tax positions	0	0
Domestic Tax Authority [Member]
Net operating loss carryforward	136,900,000
Operating loss carryovers for financial reporting purposes	131,100,000
Net operating loss carryforwards that do not benefit financial statements	$ 5,800,000
Minimum [Member] | Foreign Tax Authority [Member]
Duration of expected taxable income (loss) for deferred tax asset	4 years
Maximum [Member] | Foreign Tax Authority [Member]
Duration of expected taxable income (loss) for deferred tax asset	5 years

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Commitments And Contingencies (Details 2) (USD $) In Thousands, unless otherwise specified	Jan. 31, 2015
Commitments And Contingencies [Abstract]
2016	$ 2,807
2017	2,749
2018	2,357
2019	2,108
2020 and thereafter	$ 2,686

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Share-Based Compensation (Details 7)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance	4,070,000	3,160,000
Grants, Number of Units	1,412,000	910,000	3,160,000
Units redeemed	(180,000)
Outstanding, Number of Units, Ending Balance	5,302,000	4,070,000	3,160,000
Grants, Number of Vested Units	3,138,000
Grants, Number of Unvested Units	2,164,000
Series B Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining vesting period	5 years
Series B-1 Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance	3,100,000
Grants, Number of Units			3,100,000
Units redeemed	(180,000)
Outstanding, Number of Units, Ending Balance	2,920,000		3,100,000
Grants, Number of Vested Units	2,920,000
Series B-2 Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance	60,000
Grants, Number of Units			60,000
Outstanding, Number of Units, Ending Balance	60,000		60,000
Grants, Number of Vested Units	30,000
Grants, Number of Unvested Units	30,000
Series B-3 Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance	910,000
Grants, Number of Units		910,000
Outstanding, Number of Units, Ending Balance	910,000	910,000
Grants, Number of Vested Units	188,000
Grants, Number of Unvested Units	722,000
Series B-4 Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants, Number of Units	1,412,000
Outstanding, Number of Units, Ending Balance	1,412,000
Grants, Number of Unvested Units	1,412,000

XML

Share-Based Compensation (Details) (USD $)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation, net	$ 7,919,000	$ 7,830,000	$ 6,466,000
Proceeds from issuance of common stock		245,369,000
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation	19,800,000
Unrecognized compensation, recognition period	4 years
Number of shares per vesting unit	1
Units granted, number of units	1,523,700	1,440,133	1,041,400
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation, recognition period	3 years 3 months 18 days
Unrecognized compensation cost related to awards	18,600,000
Rockpile Series A Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred return on investment	8.00%
Series B Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares reserved under Plan	6,000,000
Share-based awards vesting period	5 years
Unrecognized compensation	2,600,000
Maxiumum amount of distributions	$ 40,000,000
2014 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares reserved under Plan	6,000,000
Minimum [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based awards vesting period	1 year
Minimum [Member] | Series B Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based awards vesting period	7 months
Maximum [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based awards vesting period	5 years
Maximum [Member] | Series B Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based awards vesting period	52 months

XML

Summary Of Significant Accounting Policies (Policies)

12 Months Ended

Jan. 31, 2015

Summary Of Significant Accounting Policies [Abstract]

Use of Estimates

Use of Estimates.  In the course of preparing its consolidated financial statements, management makes various assumptions, judgments, and estimates to determine the reported amount of assets, liabilities, revenue, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include (i) oil and natural gas reserves; (ii) cash flow estimates used in ceiling tests of oil and natural gas properties; (iii) depreciation and amortization; (iv) impairment of undeveloped properties and other assets; (v) assigning fair value and allocating purchase price in connection with business combinations; (vi) accrued revenue and related receivables; (vii) valuation of commodity derivative instruments and equity derivative instruments; (viii) accrued liabilities; (ix) valuation of share-based payments and (x) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these financial statements.

Principles of Consolidation

Principles of Consolidation.  The accounts of Triangle and its wholly-owned subsidiaries are presented in the accompanying consolidated financial statements.  All intercompany transactions and balances are eliminated in consolidation.  Triangle generally uses the equity method of accounting for investments in entities in which Triangle has an ownership between 20% and 50% and exercises significant influence. 

These consolidated financial statements include the accounts of the Company’s wholly-owned subsidiaries: (i) TUSA, incorporated in the State of Colorado, and its wholly-owned subsidiaries, (ii) RockPile, organized in the State of Delaware, and its wholly-owned subsidiaries, (iii) Elmworth, incorporated in the Province of Alberta, Canada, (iv) Triangle Real Estate Properties, LLC, organized in the State of Colorado, and its wholly-owned subsidiaries, (v) Integrated Operating Solutions, LLC, organized in the State of Colorado, (vi) Ranger Fabrication, LLC, organized in the State of Delaware, and its wholly-owned subsidiaries, and (vii) Triangle Caliber Holdings, LLC, organized in the State of Delaware, and its wholly-owned subsidiaries. Additionally, Triangle Caliber Holdings, LLC is a joint venture partner in Caliber.  The investment in Caliber is accounted for utilizing the equity method of accounting.

Cash And Cash Equivalents

Cash and Cash Equivalents.  Cash and cash equivalents, including cash in banks in the United States and Canada,  consist of highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased. 

Accounts Receivable And Credit Policies

Accounts Receivable and Credit Policies.  The components of accounts receivable include the following (in thousands):

	For the Years Ended January 31,
		2015		2014
Oil and natural gas sales	$	21,445	$	25,866
Joint interest billings		72,235		43,660
Oilfield services revenue		59,408		29,109
Other		11,350		7,828
Total accounts receivable	$	164,438	$	106,463

The Company’s accounts receivable result primarily from (i) oil and natural gas purchasers, (ii) billings to joint working interest partners in properties operated by the Company and (iii) trade receivables for oilfield services revenue. The Company’s trade and accrued revenue receivables are dispersed among various customers and purchasers and most of the Company’s significant purchasers are large companies with strong credit ratings. If customers are considered a credit risk, letters of credit or parental guarantees are the primary security obtained to support the extension of credit. For most joint working interest partners, the Company may have the right of offset against related oil and natural gas revenues.

The following table provides the percentage of revenue derived from oil and natural gas sales to customers and oilfield services customers who comprise 10% or more of the Company’s consolidated annual revenue (the customers in each year are not necessarily the same from year to year): 

	Fiscal Years Ended January 31,
	2015		2014		2013
Oil & Gas Customer A		13%		22%		N/A
Oil & Gas Customer B		12%		15%		N/A
Oil & Gas Customer C		12%		N/A		N/A
Oilfield Services Customer A		15%		N/A		N/A
Oilfield Services Customer B		12%		13%		N/A

Although a substantial portion of our oil and natural gas sales and our oilfield services revenues may be to a few large customers, we do not believe the loss of any one customer would have a material adverse effect on our exploration and production business as we believe that other purchasers would be available.  While we believe that there are numerous operators in the Williston Basin in need of pressure pumping and related oilfield services, a severe and sustained downturn in commodities pricing could result in the loss of a significant customer.  However, we do not believe that the loss of a significant customer would have a material adverse impact on the Company.

Inventories

Inventories.  Inventories, included in other current assets, consist of well equipment, sand, chemicals 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 utilized in evaluating net realizable value.

Oil And Natural Gas Properties

Oil and Natural Gas Properties.  We use the full cost method of accounting for our oil and natural gas operations.  All costs associated with property acquisition, exploration, and development activities in the United States and Canada are capitalized into a United States full cost pool and a Canadian full cost pool, respectively.  The cost pools are amortized on a unit-of-production basis using proved oil and natural gas reserves.  Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and natural gas reserves.  Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized.  Expenditures for maintenance and repairs are charged to production expense in the period incurred.  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. 

The capitalized costs of unevaluated properties, including those of wells in progress, are excluded from the costs being amortized.  We do not have major development projects that are excluded from costs being amortized.  On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments.  To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. 

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

Amortization of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves by country-wide cost pool. 

Companies that follow the full cost method of accounting are required to make quarterly “ceiling test” calculations for each full cost pool.  This test ensures that the country-wide cost pool’s total capitalized costs for oil and natural gas properties (net of accumulated amortization and deferred income taxes) do not exceed the sum of (i) the present value discounted at 10% of estimated future net cash flows from the Company’s proved oil and natural gas reserves in that country, (ii) the pool’s 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.  If the cost pool’s net capitalized costs exceed this “ceiling,” the excess is charged to expense.  Any recorded ceiling-test impairment of oil and natural gas properties is not reversible at a later date. 

At January 31, 2015, the calculated value of the ceiling limitation approximated the carrying value of our oil and natural gas properties subject to the test and no impairment was necessary.  However, Triangle will likely be required to recognize an impairment of oil and natural gas properties in future periods if oil and natural gas prices remain at current prices or continue to decline or if there is a negative impact on one or more of the other components of the calculation and such an impairment will likely be material.

Oil And Natural Gas Reserves

Oil and Natural Gas Reserves.Amortization of the capitalized costs of oil and natural gas properties, including estimated future development and abandonment costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves.  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.

Oilfield Services Equipment and Other Property And Equipment

Oilfield Services Equipment and Other Property and Equipment.  Oilfield services equipment and other property and equipment as of January 31, 2014 and 2013 consisted of the following:

	For the Years Ended January 31,
(in thousands)	2015		2014
Land	$	7,888	$	2,512
Building and leasehold improvements		33,625		18,388
Oilfield service equipment		116,354		56,355
Vehicles		4,811		2,288
Software, computers and office equipment		5,327		3,016
Capital leases		853		—
Total depreciable assets		168,858		82,559
Accumulated depreciation		(35,189)		(12,800)
Depreciable assets, net		133,669		69,759
Assets not placed in service		1,247		1,333
Total oilfield service equipment and other property & equipment, net	$	134,916	$	71,092

Expenditures for replacements, renewals, and betterments are capitalized.  Maintenance and repairs are charged to operations as incurred.  Oilfield services equipment and other property and equipment are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable.  We have not found or recognized any impairment losses on such 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 ranging from 3-20 years.

Deferred Financing Costs

Deferred Loan Costs.  Deferred financing costs include origination, legal, engineering, and other fees incurred to issue debt.  Deferred financing costs are amortized to interest expense using the effective interest method over the respective borrowing term.

Investment In Unconsolidated Entities

Equity Investment.  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 after elimination of intra-company profits and losses.  The Company records losses of the unconsolidated entities only to the extent of the Company’s investment.

We evaluate our equity method investment for impairment when there are indicators of impairment.  If indicators suggest impairment, we will perform an impairment test to assess whether an adjustment is necessary.  The impairment test considers whether the fair value of our equity method investment has declined and if any such decline is other than temporary.  If a decline in fair value is determined to be other than temporary, the investment’s carrying value is written down to fair value.

Asset Retirement Obligations

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.

Derivatives Instruments

Derivative Instruments.  The Company enters into derivative contracts, primarily costless collars and swaps, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative instruments are recorded on the balance sheet at fair value. The Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges.

The Company holds equity investment derivatives (Class A Warrants (Series 1 through Series 4)) in Caliber.  Our equity investment derivatives are measured at fair value and are included in equity investment on the consolidated balance sheet.  Net gains and losses on equity investment derivatives are recorded based on the changes in the fair values of the derivative instruments and included in our consolidated statements of operations.

Income Taxes

Income Taxes.  Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The Company’s policy is to recognize interest and/or penalties related to uncertain tax positions in interest expense.

Revenue Recognition

Oil, Natural Gas and Natural Gas Liquids Revenue.  The Company recognizes revenues from the sale of crude oil, natural gas and natural gas liquids when the product is delivered at a fixed or determinable price, title has transferred, and/or collectability is reasonably assured and evidenced by a contract.  There were no oil or natural gas sales imbalances at January 31, 2015, 2014, or 2013.

Oilfield Services Revenue.  The Company enters into arrangements with its customers to provide hydraulic fracturing services and other oilfield 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 collectability is reasonably assured.  Revenue is recognized and customers are invoiced upon the completion of each job, which generally consists of numerous fracturing stages and complementary completion services.  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.

Share-Based Compensation

Share-Based Compensation.  Share-based compensation is measured at the estimated grant date fair value of the awards and is recognized over the requisite service period (usually the vesting period). The Company estimates forfeitures in calculating the cost related to stock-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered.

Earnings Per Share

Earnings per Share.  Basic earnings per common 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 reflects increases in average shares outstanding from the potential dilution, under the treasury stock method, that could occur upon (i) exercise of stock options, (ii) vesting of restricted stock units, and (iii) conversion of convertible debt. The treasury stock method assumes exercise, vesting or conversion at the beginning of a period for securities outstanding at the end of a period. Also, the treasury stock method for calculating dilution assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company at the quarter’s average stock price using assumed proceeds from (a) the exercise cost of the options and (b) the foregone future compensation expense of hypothetical early vesting of the outstanding restricted stock units.  The assumed proceeds are adjusted for income tax effects.  In the event of a net loss, no potential common shares are included in the calculation of shares outstanding, as their inclusion would be anti-dilutive.

The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and unvested restricted stock, for the periods presented (in thousands):

	For the Years Ended January 31,
	2015		2014		2013
Dilutive		17,421		15,979		—
Anti-dilutive shares		6,905		5,250		4,500

The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the years ended January 31, 2015, 2014, and 2013:

	For the Years Ended January 31,
(in thousands, except per share data)	2015		2014		2013
Net income (loss) attributable to common stockholders	$	93,397	$	73,480	$	(13,760)
Effect of 5% convertible note conversion		4,135		3,392		—
Net income (loss) attributable to common stockholders after effect of debt conversion	$	97,532	$	76,872	$	(13,760)
Basic weighted average common shares outstanding		83,611		68,579		44,475
Effect of dilutive securities		17,421		15,979		—
Diluted weighted average common shares outstanding		101,032		84,558		44,475
Basic net income (loss) per share	$	1.12	$	1.07	$	(0.31)
Diluted net income (loss) per share	$	0.97	$	0.91	$	(0.31)

Recent Accounting Developments

New Pronouncements Issued But Not Yet Adopted.  In April 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.  ASU 2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures.  The guidance is effective for annual and interim reporting periods beginning after December 15, 2014.  Adoption of this amendment will not have a material effect on our financial position or results of operations.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, issued as a new Topic, Accounting Standards Codification Topic 606.  The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized.  The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  This ASU is effective for the Company beginning in fiscal year 2017 and can be adopted by the Company either retrospectively or as a cumulative-effect adjustment as of the date of adoption.  We are currently evaluating the effect that adopting this new accounting guidance will have on our consolidated results of operations, cash flows and financial position.

In August 2014, the FASB issued ASU No. 2014-15, which requires management of public and private companies to evaluate whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued (or available to be issued when applicable) and, if so, to disclose that fact.  Management will be required to make this evaluation for both annual and interim reporting periods, if applicable.  ASU No. 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods within annual periods beginning after December 15, 2016.  The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

Accounting standard-setting organizations frequently issue new or revised accounting rules.  We regularly review new pronouncements to determine their impact, if any, on our consolidated financial statements.  Other than the standards discussed above, there are no significant accounting standards applicable to Triangle which have not been adopted. 

Reclassifications

Reclassifications.  Certain amounts in the consolidated balance sheet as of January 31, 2014, and in our consolidated statement of operations for the years ended January 31, 2014 and 2013, have been reclassified to conform to the financial statement presentation for the period ended January 31, 2015.  The balance sheet reclassifications relate to changes in the captions presented in the balance sheet.  The statement of operations reclassifications relate to the break out of amortization of deferred loan costs from interest expense and amounts related to revisions in the Elmworth abandonment obligation were reclassified from accretion of asset retirement obligations to depreciation and amortization expense. Such reclassifications had no impact on consolidated total assets, stockholders’ equity or net income previously reported.

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Long-term Debt (Details 3) (USD $)	0 Months Ended	12 Months Ended
	Nov. 25, 2014	Jan. 31, 2015	Jul. 18, 2014
TUSA Senior Notes [Member]
Line of Credit Facility [Line Items]
Debt instrument, interest rate		6.75%	6.75%
TUSA [Member]
Line of Credit Facility [Line Items]
Credit facility, maximum borrowing capacity	$ 1,000,000,000
Letter of credit sublimit	15,000,000
Credit agreement borrowing base	435,000,000
Percentage of Oil and Gas Interests Used For Collateral	80.00%
TUSA [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Credit facility, fronting fee percentage	0.125%
Credit facility, fronting fee amount	$ 500
Minimum [Member] | TUSA [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Credit facility, commitment fee percentage	0.375%
Maximum [Member] | TUSA [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Credit facility, commitment fee percentage	0.50%
Federal Funds Rate [Member] | TUSA [Member]
Line of Credit Facility [Line Items]
Credit facility, basis spread on interest rate		0.50%
Eurodollar Rate Plus 1% [Member] | TUSA [Member]
Line of Credit Facility [Line Items]
Credit facility, margin on dollar amount based on usage		1.00%
Eurodollar Rate Plus 1% [Member] | Minimum [Member] | TUSA [Member]
Line of Credit Facility [Line Items]
Credit facility, margin on dollar amount based on usage		0.50%
Eurodollar Rate Plus 1% [Member] | Maximum [Member] | TUSA [Member]
Line of Credit Facility [Line Items]
Credit facility, margin on dollar amount based on usage		1.50%
Eurodollar [Member] | Minimum [Member] | TUSA [Member]
Line of Credit Facility [Line Items]
Credit facility, margin on dollar amount based on usage		1.50%
Eurodollar [Member] | Maximum [Member] | TUSA [Member]
Line of Credit Facility [Line Items]
Credit facility, margin on dollar amount based on usage		2.50%

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Summary Of Significant Accounting Policies (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014
Accounting Policies [Line Items]
Accounts receivable	164,438	106,463
Gain (loss) recognized on disposition	0
Oil and gas imbalance	0
Oil & Gas Customer A [Member]
Accounting Policies [Line Items]
Customer concentration risk percentage	13.00%	22.00%
Oil & Gas Customer B [Member]
Accounting Policies [Line Items]
Customer concentration risk percentage	12.00%	15.00%
Oil & Gas Customer C [Member]
Accounting Policies [Line Items]
Customer concentration risk percentage	12.00%
Oilfield Services Customer A [Member]
Accounting Policies [Line Items]
Customer concentration risk percentage	15.00%
Oilfield Services Customer B [Member]
Accounting Policies [Line Items]
Customer concentration risk percentage	12.00%	13.00%
Oil And Gas Property [Member]
Accounting Policies [Line Items]
Accounts receivable	21,445	25,866
Joint interest billings [Member]
Accounting Policies [Line Items]
Accounts receivable	72,235	43,660
Oilfield Services [Member]
Accounting Policies [Line Items]
Accounts receivable	59,408	29,109
Other [Member]
Accounting Policies [Line Items]
Accounts receivable	11,350	7,828
Maximum [Member]
Accounting Policies [Line Items]
Equity method ownership percentage	50.00%
Minimum [Member]
Accounting Policies [Line Items]
Equity method ownership percentage	20.00%

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Share-Based Compensation (Details 5) (Employee Stock Option [Member], USD $)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013	Jan. 31, 2012
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Outstanding options	6,700,000	6,108,333	231,666	235,833
Number of shares exercise	600,000
Weighted average exercise price per share	$ 11.54	$ 11.07	$ 1.48	$ 1.50
Weighted average remaining contractual life (years)	8 years 4 months 2 days
Weighted average exercise price per share (exercisable)	$ 11.25
Weighted average remaining contractual life (years) (exercisable)	8 years 5 months 5 days
$7.50 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price per share	$ 7.50
Remaining contractual life	8 years 5 months 5 days
Outstanding options	750,000
Number of shares exercise	75,000
$8.50 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price per share	$ 8.50
Remaining contractual life	8 years 5 months 5 days
Outstanding options	750,000
Number of shares exercise	75,000
$10.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price per share	$ 10.00
Remaining contractual life	8 years 5 months 5 days
Outstanding options	1,500,000
Number of shares exercise	150,000
$12.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price per share	$ 12.00
Remaining contractual life	8 years 5 months 5 days
Outstanding options	1,500,000
Number of shares exercise	150,000
$15.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price per share	$ 15.00
Remaining contractual life	8 years 5 months 5 days
Outstanding options	1,500,000
Number of shares exercise	150,000
$12.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price per share	$ 12.00
Remaining contractual life	6 years 7 months 10 days
Outstanding options	233,333
$14.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price per share	$ 14.00
Remaining contractual life	6 years 7 months 10 days
Outstanding options	233,333
$16.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price per share	$ 16.00
Remaining contractual life	9 years 7 months 10 days
Outstanding options	233,334

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Commitments And Contingencies (Tables)

12 Months Ended

Jan. 31, 2015

Commitments And Contingencies [Abstract]

Schedule Of Annual Rentals per Year

Fiscal Years Ending January 31,	Annual Rental Amount (in thousands)
2016	$	2,807
2017	$	2,749
2018	$	2,357
2019	$	2,108
2020 and thereafter	$	2,686

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Long-term Debt (Details 5) (USD $)	12 Months Ended
	Jan. 31, 2015	Jul. 18, 2014
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt	$ 6,610,000
TUSA Senior Notes [Member]
Debt Instrument [Line Items]
Debt instrument, face amount		450,000,000
Debt instrument, interest rate	6.75%	6.75%
Offering costs	10,500,000
Face value of notes repurchased	20,500,000
Repurchased amount	13,900,000
Gain (loss) on extinguishment of debt	$ 6,600,000
TUSA Senior Notes [Member] | Redemption prior to July 15, 2017 [Member]
Debt Instrument [Line Items]
Redemption price, percentage	100.00%
Redemption price, percentage of principal amount redeemed	35.00%
TUSA Senior Notes [Member] | Redemption Due to Change in Control Events [Member]
Debt Instrument [Line Items]
Redemption price, percentage	101.00%

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Equity Investment And Equity Investment Derivatives (Details 3) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended		0 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jun. 30, 2014	Jan. 31, 2015
Schedule of Equity Method Investments [Line Items]
Equity investment, Beginning balance	$ 68,536
Distributions	(6,080)	(3,150)
Equity investment, Ending balance	64,411	68,536		64,411
Class A Triggering Units [Member]
Schedule of Equity Method Investments [Line Items]
Number of units converted			1,600,000
Caliber Midstream Partners, L.P. [Member]
Schedule of Equity Method Investments [Line Items]
Equity investment, Beginning balance	68,536	11,768
Capital contributions		18,000
Distributions	(6,080)	(3,150)
Equity investment share of net income for the year	1,402	2,184
Increase in equity method investment	553	39,734
Equity investment, Ending balance	64,411	68,536		64,411
Fair value of trigger unit warrants and warrants at end of year	504	39,734		504
Caliber Midstream Partners, L.P. [Member] | Triangle Caliber Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Capital contributions				0
Equity method investments, warrants received				3,626,667
Caliber Midstream Partners, L.P. [Member] | Class A Triggering Units [Member]
Schedule of Equity Method Investments [Line Items]
Increase in equity method investment	1,745	38,091
Caliber Midstream Partners, L.P. [Member] | Class A Trigger Unit Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Increase in equity method investment	532	234
Caliber Midstream Partners, L.P. [Member] | Series 1 Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Increase in equity method investment	(1,241)	926
Equity method investments, warrants received			5,600,000
Caliber Midstream Partners, L.P. [Member] | Series 2 Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Increase in equity method investment	(254)	254
Caliber Midstream Partners, L.P. [Member] | Series 3 Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Increase in equity method investment	(207)	207
Caliber Midstream Partners, L.P. [Member] | Series 4 Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Increase in equity method investment	$ (22)	$ 22

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Acquisitions (Details 2) (USD $) In Thousands, unless otherwise specified	0 Months Ended	1 Months Ended
	Aug. 28, 2013	Jun. 30, 2014
Kodiak Oil And Natural Gas Property [Member]
Property, Plant and Equipment [Line Items]
Cash	$ 83,800
Marathon Oil And Gas [Member]
Property, Plant and Equipment [Line Items]
Cash		90,352
Total consideration given		90,352
Proved properties		71,044
Unproved properties		20,262
Total oil and natural gas properties		91,306
Accounts payable		(469)
Asset retirement obligation assumed		(485)
Fair value of net assets acquired		$ 90,352

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Segment Reporting (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Jan. 31, 2015	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Oct. 31, 2013	Jul. 31, 2013	Apr. 30, 2013	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
REVENUES
Oil and natural gas liquids sales									$ 284,502	$ 160,548	$ 39,614
Oilfield services for third parties									288,453	98,199	20,747
Total revenues	156,988	174,196	141,989	99,782	85,510	88,549	50,394	34,294	572,955	258,747	60,361
EXPENSES:
Production taxes and other lease operating									55,477	32,460	8,058
Gathering, transportation and processing									18,520	4,302	150
Depreciation and amortization									124,055	58,011	15,081
Accretion of asset retirement obligations									167	56	184
Cost of oilfield services									216,596	82,327	16,606
Salaries and benefits									32,207	17,299	14,748
Stock-based compensation									7,919	7,830	6,466
Other general and administrative									22,631	9,500	7,329
Total operating expenses									477,572	211,785	68,622
INCOME FROM OPERATIONS	1,202	33,345	38,489	22,347	12,501	17,160	12,973	4,328	95,383	46,962	(8,261)
Other income (expense), net									43,514	34,459	(6,223)
NET INCOME (LOSS) BEFORE INCOME TAXES									138,897	81,421	(14,484)
Net oil and natural gas properties	1,126,090				682,787				1,126,090	682,787	298,757
Oilfield services equipment, net	87,549				46,585				87,549	46,585	18,878
Other property and equipment, net	47,367				24,507				47,367	24,507	15,779
Total assets	1,654,870				1,027,522				1,654,870	1,027,522	428,321
Total liabilities	1,109,852				504,360				1,109,852	504,360	226,698
Eliminations And Other [Member]
REVENUES
Oilfield services for third parties									(6,073)	(4,407)	(1,788)
Total revenues									(129,650)	(95,426)	(36,460)
EXPENSES:
Depreciation and amortization									(15,507)	(8,302)	(1,732)
Cost of oilfield services									(84,854)	(60,012)	(22,928)
Total operating expenses									(100,361)	(68,314)	(24,660)
INCOME FROM OPERATIONS									(29,289)	(27,112)	(11,800)
Other income (expense), net									(2,322)	(3,376)	(883)
NET INCOME (LOSS) BEFORE INCOME TAXES									(31,611)	(30,488)	(12,683)
Net oil and natural gas properties	(74,782)				(43,171)				(74,782)	(43,171)	(11,800)
Total assets	(88,196)				(63,312)				(88,196)	(63,312)	(13,445)
Total liabilities	(13,414)				(20,141)				(13,414)	(20,141)	(1,645)
Intersegment Revenues [Member] | Eliminations And Other [Member]
REVENUES
Total revenues									(123,577)	(91,019)	(34,672)
Exploration and Production [Member]
REVENUES
Oil and natural gas liquids sales									284,502	160,548	39,614
Total revenues									284,502	160,548	39,614
EXPENSES:
Production taxes and other lease operating									55,477	32,460	8,058
Gathering, transportation and processing									18,520	4,302	150
Depreciation and amortization									116,633	56,788	13,578
Accretion of asset retirement obligations									167	56	184
Salaries and benefits									6,028	3,541	4,367
Stock-based compensation									1,155	1,127	2,507
Other general and administrative									9,042	3,939	2,223
Total operating expenses									207,022	102,213	31,067
INCOME FROM OPERATIONS									77,480	58,335	8,547
Other income (expense), net									51,216	(172)	(6,318)
NET INCOME (LOSS) BEFORE INCOME TAXES									128,696	58,163	2,229
Net oil and natural gas properties	1,200,872				725,958				1,200,872	725,958	310,557
Other property and equipment, net	9,679				1,594				9,679	1,594	1,597
Total assets	1,408,768				816,282				1,408,768	816,282	362,878
Total liabilities	754,925				318,875				754,925	318,875	91,134
Oilfield Services [Member]
REVENUES
Oilfield services for third parties									294,526	102,606	22,535
Total revenues									418,103	193,625	57,207
EXPENSES:
Depreciation and amortization									22,008	8,905	2,857
Cost of oilfield services									301,142	142,339	39,534
Salaries and benefits									14,620	6,894	8,422
Stock-based compensation									509	590	617
Other general and administrative									10,598	4,222	2,708
Total operating expenses									348,877	162,950	54,138
INCOME FROM OPERATIONS									69,226	30,675	3,069
Other income (expense), net									(3,024)	(991)	4
NET INCOME (LOSS) BEFORE INCOME TAXES									66,202	29,684	3,073
Oilfield services equipment, net	87,549				46,585				87,549	46,585	18,878
Other property and equipment, net	22,246				18,912				22,246	18,912	12,443
Total assets	202,649				126,114				202,649	126,114	38,668
Total liabilities	163,987				64,017				163,987	64,017	11,845
Oilfield Services [Member] | Intersegment Revenues [Member]
REVENUES
Total revenues									123,577	91,019	34,672
Corporate And Other [Member]
EXPENSES:
Depreciation and amortization									921	620	378
Cost of oilfield services									308
Salaries and benefits									11,559	6,864	1,959
Stock-based compensation									6,255	6,113	3,342
Other general and administrative									2,991	1,339	2,398
Total operating expenses									22,034	14,936	8,077
INCOME FROM OPERATIONS									(22,034)	(14,936)	(8,077)
Other income (expense), net									(2,356)	38,998	974
NET INCOME (LOSS) BEFORE INCOME TAXES									(24,390)	24,062	(7,103)
Other property and equipment, net	15,442				4,001				15,442	4,001	1,739
Total assets	131,649				148,438				131,649	148,438	40,220
Total liabilities	$ 204,354				$ 141,609				$ 204,354	$ 141,609	$ 125,364

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Segment Reporting

12 Months Ended

Jan. 31, 2015

Segment Reporting [Abstract]

Segment Reporting

3.  SEGMENT REPORTING

We conduct our operations within two reportable operating segments.  We identified each segment based on management’s responsibility and the nature of their products, services, and costs.  There are no major distinctions in geographical areas served as nearly all operations are in the Williston Basin of the United States.  The Exploration and Production operating segment, consisting of TUSA and several insignificant oil and natural gas subsidiaries, is responsible for finding and producing oil and natural gas.  The Oilfield Services segment, consisting of RockPile, is responsible for a variety of oilfield and complementary services for both Triangle-operated wells and wells operated by third-parties.  Corporate and Other includes our corporate office and several subsidiaries that management does not consider to be part of the Exploration and Production or Oilfield Services segments.  Also included in Corporate and Other are our results from our investment in Caliber, including any changes in the fair value of our equity investment derivatives. 

Management evaluates the performance of our segments based upon net income (loss) before income taxes.  The following tables present selected financial information for our operating segments for the years ended January 31, 2015, 2014, and 2013.

	For the Year Ended January 31, 2015
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	284,502	$	—	$	—	$	—	$	284,502
Oilfield services for third parties		—		294,526		—		(6,073)		288,453
Intersegment revenues		—		123,577		—		(123,577)		—
Total revenues		284,502		418,103		—		(129,650)		572,955
Expenses:
Lease operating and production taxes		55,477		—		—		—		55,477
Gathering, transportation and processing		18,520		—		—		—		18,520
Depreciation and amortization		116,633		22,008		921		(15,507)		124,055
Accretion of asset retirement obligations		167		—		—		—		167
Cost of oilfield services		—		301,142		308		(84,854)		216,596
General and administrative, net of amounts capitalized:
Salaries and benefits		6,028		14,620		11,559		—		32,207
Stock-based compensation		1,155		509		6,255		—		7,919
Other general and administrative		9,042		10,598		2,991		—		22,631
Total operating expenses		207,022		348,877		22,034		(100,361)		477,572
Income (loss) from operations		77,480		69,226		(22,034)		(29,289)		95,383
Other income (expense), net		51,216		(3,024)		(2,356)		(2,322)		43,514
Net income (loss) before income taxes	$	128,696	$	66,202	$	(24,390)	$	(31,611)	$	138,897
As of January 31, 2015:
Net oil and natural gas properties	$	1,200,872	$	—	$	—	$	(74,782)	$	1,126,090
Oilfield services equipment - net	$	—	$	87,549	$	—	$	—	$	87,549
Other property and equipment - net	$	9,679	$	22,246	$	15,442	$	—	$	47,367
Total assets	$	1,408,768	$	202,649	$	131,649	$	(88,196)	$	1,654,870
Total liabilities	$	754,925	$	163,987	$	204,354	$	(13,414)	$	1,109,852

	For the Year Ended January 31, 2014
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	160,548	$	—	$	—	$	—	$	160,548
Oilfield services for third parties		—		102,606		—		(4,407)		98,199
Intersegment revenues		—		91,019		—		(91,019)		—
Total revenues		160,548		193,625		—		(95,426)		258,747
Expenses:
Lease operating and production taxes		32,460		—		—		—		32,460
Gathering, transportation and processing		4,302		—		—		—		4,302
Depreciation and amortization		56,788		8,905		620		(8,302)		58,011
Accretion of asset retirement obligations		56		—		—		—		56
Cost of oilfield services		—		142,339		—		(60,012)		82,327
General and administrative, net of amounts capitalized:
Salaries and benefits		3,541		6,894		6,864		—		17,299
Stock-based compensation		1,127		590		6,113		—		7,830
Other general and administrative		3,939		4,222		1,339		—		9,500
Total operating expenses		102,213		162,950		14,936		(68,314)		211,785
Income (loss) from operations		58,335		30,675		(14,936)		(27,112)		46,962
Other income (expense), net		(172)		(991)		38,998		(3,376)		34,459
Net income (loss) before income taxes	$	58,163	$	29,684	$	24,062	$	(30,488)	$	81,421
As of January 31, 2014:
Net oil and natural gas properties	$	725,958	$	—	$	—	$	(43,171)	$	682,787
Oilfield services equipment - net	$	—	$	46,585	$	—	$	—	$	46,585
Other property and equipment - net	$	1,594	$	18,912	$	4,001	$	—	$	24,507
Total assets	$	816,282	$	126,114	$	148,438	$	(63,312)	$	1,027,522
Total liabilities	$	318,875	$	64,017	$	141,609	$	(20,141)	$	504,360

	For the Year Ended January 31, 2013
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	39,614	$	—	$	—	$	—	$	39,614
Oilfield services for third parties		—		22,535		—		(1,788)		20,747
Intersegment revenues		—		34,672		—		(34,672)		—
Total revenues		39,614		57,207		—		(36,460)		60,361
Expenses:
Lease operating and production taxes		8,058		—		—		—		8,058
Gathering, transportation and processing		150		—		—		—		150
Depreciation and amortization		13,578		2,857		378		(1,732)		15,081
Accretion of asset retirement obligations		184		—		—		—		184
Cost of oilfield services		—		39,534		—		(22,928)		16,606
General and administrative, net of amounts capitalized:
Salaries and benefits		4,367		8,422		1,959		—		14,748
Stock-based compensation		2,507		617		3,342		—		6,466
Other general and administrative		2,223		2,708		2,398		—		7,329
Total operating expenses		31,067		54,138		8,077		(24,660)		68,622
Income (loss) from operations		8,547		3,069		(8,077)		(11,800)		(8,261)
Other income (expense), net		(6,318)		4		974		(883)		(6,223)
Net income (loss) before income taxes	$	2,229	$	3,073	$	(7,103)	$	(12,683)	$	(14,484)
As of January 31, 2013:
Net oil and natural gas properties	$	310,557	$	—	$	—	$	(11,800)	$	298,757
Oilfield services equipment - net	$	—	$	18,878	$	—	$	—	$	18,878
Other property and equipment - net	$	1,597	$	12,443	$	1,739	$	—	$	15,779
Total assets	$	362,878	$	38,668	$	40,220	$	(13,445)	$	428,321
Total liabilities	$	91,134	$	11,845	$	125,364	$	(1,645)	$	226,698

Certain income statement reclassifications were made as previously noted and to reflect the Exploration and Production depreciation and amortization expense gross rather than net of consolidating eliminations.

Eliminations and Other.  For consolidation, intercompany revenues and expenses are eliminated with a corresponding reduction in Triangle’s capitalized well costs.

Under the full cost method of accounting, we deferred recognition of approximately an additional $123.6 million, $91.0million and $34.7 million in oilfield services income for the years ended January 31, 2015, 2014, and 2013, respectively, and approximately $6.1 million, $4.4 million, and $1.8 million in oilfield services income for the years ended January 31, 2015, 2014, and 2013, respectively, associated with our non-operating partners’ share of costs charged by RockPile for well completion activities on properties we operate, by charging such oilfield services income against oilfield services revenue and crediting proved oil and natural gas properties. 

In addition, we deferred approximately $1.3 million and $2.2million of Caliber gross profit from our share of its income for the years ended January 31, 2015 and 2014, respectively, associated with services it provided which were capitalized by TUSA, by charging such gross profit against income from equity investment and crediting proved oil and natural gas properties.

The above deferred income is indirectly recognized in future periods through a lower amortization rate as proved reserves are produced.

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Acquisitions (Details 3) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Acquisitions [Abstract]
Operating revenue	$ 584,696	$ 312,081	$ 92,933
Net income (loss)	$ 96,438	$ 91,579	$ (2,407)
Earnings (loss) per common share, basic	$ 1.15	$ 1.22	$ (0.04)
Earnings (loss) per common share, diluted	$ 1.00	$ 1.04	$ (0.04)
Weighted average common shares outstanding, basic	83,611	75,047	55,794
Weighted average common shares outstanding, diluted	101,032	91,026	55,794

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Summary Of Significant Accounting Policies (Details 2) (USD $) In Thousands, unless otherwise specified	Jan. 31, 2015	Jan. 31, 2014
Property, Plant and Equipment [Line Items]
Total Depreciable Assets	$ 168,858	$ 82,559
Accumulated depreciation	(35,189)	(12,800)
Depreciable assets, net	133,669	69,759
Assets not placed in service	1,247	1,333
Total oilfield service equipment and other property and equipment, net	134,916	71,092
Land [Member]
Property, Plant and Equipment [Line Items]
Total Depreciable Assets	7,888	2,512
Building And Leasehold Improvements [Member]
Property, Plant and Equipment [Line Items]
Total Depreciable Assets	33,625	18,388
Oilfield Service Equipment [Member]
Property, Plant and Equipment [Line Items]
Total Depreciable Assets	116,354	56,355
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Total Depreciable Assets	4,811	2,288
Software, Computers And Office Equipment [Member]
Property, Plant and Equipment [Line Items]
Total Depreciable Assets	5,327	3,016
Capital Leases [Member]
Property, Plant and Equipment [Line Items]
Total Depreciable Assets	$ 853

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Hedging And Commodity Derivative Financial Instruments (Tables)

12 Months Ended

Jan. 31, 2015

Commodity Derivative Instruments [Abstract]

Schedule of components of commodity derivative gains(losses)

The components of commodity derivative gains (losses) in the consolidated statements of operations are as follows (in thousands):

	For the Years Ended January 31,
	2015		2014		2013
Realized commodity derivative gains (losses)	$	11,422	$	(4,643)	$	-
Unrealized commodity derivative gains (losses)		52,628		5,725		(3,570)
Commodity derivative gains (losses), net	$	64,050	$	1,082	$	(3,570)

Summary Of Derivative Instruments

The Company’s commodity derivative contracts as of January 31, 2015 are summarized below:

	Contract		Quantity	Weighted Average	Weighted Average
Term End Date	Type	Basis (1)	(Bbl/d)	Put Strike	Call Strike
Fiscal Year 2016	Collar	NYMEX	4,356	$ 86.85	$ 98.63

(1) “NYMEX” refers to West Texas Intermediate crude oil prices at Cushing, Oklahoma as quoted on the New York Mercantile Exchange.

Schedule Of Derivative Instruments In Statement Of Financial Position, Fair Value

The main headings represent the balance sheet captions for the contracts presented (in thousands).

	For the Years Ended January 31,
	2015		2014
Current Assets:
Crude oil derivative contracts	$	62,248	$	955
Other Long-Term Assets:
Crude oil derivative contracts		—		1,192
Total derivative asset	$	62,248	$	2,147

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Long-Term Debt (Tables)

12 Months Ended

Jan. 31, 2015

Long-Term Debt [Abstract]

Schedule Of Debt

	For the Years Ended January 31,
	2015		2014
5% convertible note	$	135,877	$	129,290
TUSA credit facility due October 2018		119,272		183,000
RockPile credit facility due March 2019		104,887		21,515
TUSA 6.75% notes due July 2022		429,500		—
Other notes and mortgages payable		10,605		9,403
Total debt		800,141		343,208
Less current portion of debt:
RockPile credit facility		—		(8,450)
Other notes and mortgages payable		(503)		(401)
Total long-term debt	$	799,638	$	334,357

Scheduled annual maturities of long-term debt outstanding

For the Years Ending January 31, (in thousands):
2016	$	503
2017		1,450
2018		1,594
2019		119,852
2020		105,565
Thereafter		571,177
	$	800,141

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Hedging And Commodity Derivative Financial Instruments (Details 3) (Crude Oil Derivative Contract [Member], USD $)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ 60,100,000
Derivative Assets	62,248,000	2,147,000
Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets	62,248,000	955,000
Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets		$ 1,192,000

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Summary Of Significant Accounting Policies (Details 3)	12 Months Ended
	Jan. 31, 2015
Minimum [Member]
Estimated useful life	3 years
Maximum [Member]
Estimated useful life	20 years

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Oil And Natural Gas Properties (Tables)

12 Months Ended

Jan. 31, 2015

Oil And Natural Gas Properties [Abstract]

Schedule Of Capitalized Costs Incurred

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Costs incurred during the period
Acquisition of properties:
Proved	$	90,920	$	80,201	$	623
Unproved		47,858		41,377		20,570
Exploration		180,174		96,731		55,583
Development		226,765		216,046		91,666
Oil and natural gas expenditures		545,717		434,355		168,442
Asset retirement obligations, net		1,818		676		370
	$	547,535	$	435,031	$	168,812

Costs Not Being Amortized

			Fiscal Year Costs Incurred
									2012
(in thousands)	Total		2015		2014		2013		and prior
Acquisition	$	113,606	$	46,982	$	25,785	$	10,220	$	30,619
Exploration		22,305		20,830		1,475		—		—
Capitalized interest		6,985		4,899		2,086		—		—
Total	$	142,896	$	72,711	$	29,346	$	10,220	$	30,619

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Acquisitions (Tables)

12 Months Ended

Jan. 31, 2015

Acquisitions [Abstract]

Summary Of Purchase Price And Preliminary Estimated Values Of Assets Acquired And Liabilities Assumed

Purchase price (in thousands):
Cash	$	90,352
Total consideration given	$	90,352
Fair value allocation of purchase price:
Oil and natural gas properties:
Proved properties	$	71,044
Unproved properties		20,262
Total oil and natural gas properties		91,306
Accounts payable		(469)
Asset retirement obligations assumed		(485)
Fair value of net assets acquired	$	90,352

Proforma Schedule For Oil And Natural Gas Acquisition

	For the Years Ended January 31,
(in thousands, except per share data)	2015		2014		2013
Operating revenues	$	584,696	$	312,081	$	92,933
Net income (loss)	$	96,438	$	91,579	$	(2,407)
Earnings (loss) per common share
Basic	$	1.15	$	1.22	$	(0.04)
Diluted	$	1.00	$	1.04	$	(0.04)
Weighted average common shares outstanding:
Basic		83,611		75,047		55,794
Diluted		101,032		91,026		55,794

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Summary Of Significant Accounting Policies

12 Months Ended

Jan. 31, 2015

Summary Of Significant Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation.  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 (i) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and by the Securities and Exchange Commission (“SEC”), and (ii) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and other disclosed amounts. 

No consolidated statement of comprehensive income (loss) is presented because the Company had no comprehensive income or loss activity in the periods presented.

Use of Estimates.  In the course of preparing its consolidated financial statements, management makes various assumptions, judgments, and estimates to determine the reported amount of assets, liabilities, revenue, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established. Significant areas requiring the use of assumptions, judgments and estimates include (i) oil and natural gas reserves; (ii) cash flow estimates used in ceiling tests of oil and natural gas properties; (iii) depreciation and amortization; (iv) impairment of undeveloped properties and other assets; (v) assigning fair value and allocating purchase price in connection with business combinations; (vi) accrued revenue and related receivables; (vii) valuation of commodity derivative instruments and equity derivative instruments; (viii) accrued liabilities; (ix) valuation of share-based payments and (x) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions for matters that may require recognition or disclosure in these financial statements.

Principles of Consolidation.  The accounts of Triangle and its wholly-owned subsidiaries are presented in the accompanying consolidated financial statements.  All intercompany transactions and balances are eliminated in consolidation.  Triangle generally uses the equity method of accounting for investments in entities in which Triangle has an ownership between 20% and 50% and exercises significant influence. 

These consolidated financial statements include the accounts of the Company’s wholly-owned subsidiaries: (i) TUSA, incorporated in the State of Colorado, and its wholly-owned subsidiaries, (ii) RockPile, organized in the State of Delaware, and its wholly-owned subsidiaries, (iii) Elmworth, incorporated in the Province of Alberta, Canada, (iv) Triangle Real Estate Properties, LLC, organized in the State of Colorado, and its wholly-owned subsidiaries, (v) Integrated Operating Solutions, LLC, organized in the State of Colorado, (vi) Ranger Fabrication, LLC, organized in the State of Delaware, and its wholly-owned subsidiaries, and (vii) Triangle Caliber Holdings, LLC, organized in the State of Delaware, and its wholly-owned subsidiaries. Additionally, Triangle Caliber Holdings, LLC is a joint venture partner in Caliber.  The investment in Caliber is accounted for utilizing the equity method of accounting.

Cash and Cash Equivalents.  Cash and cash equivalents, including cash in banks in the United States and Canada,  consist of highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased. 

Accounts Receivable and Credit Policies.  The components of accounts receivable include the following (in thousands):

	For the Years Ended January 31,
		2015		2014
Oil and natural gas sales	$	21,445	$	25,866
Joint interest billings		72,235		43,660
Oilfield services revenue		59,408		29,109
Other		11,350		7,828
Total accounts receivable	$	164,438	$	106,463

The Company’s accounts receivable result primarily from (i) oil and natural gas purchasers, (ii) billings to joint working interest partners in properties operated by the Company and (iii) trade receivables for oilfield services revenue. The Company’s trade and accrued revenue receivables are dispersed among various customers and purchasers and most of the Company’s significant purchasers are large companies with strong credit ratings. If customers are considered a credit risk, letters of credit or parental guarantees are the primary security obtained to support the extension of credit. For most joint working interest partners, the Company may have the right of offset against related oil and natural gas revenues.

The following table provides the percentage of revenue derived from oil and natural gas sales to customers and oilfield services customers who comprise 10% or more of the Company’s consolidated annual revenue (the customers in each year are not necessarily the same from year to year): 

	Fiscal Years Ended January 31,
	2015		2014		2013
Oil & Gas Customer A		13%		22%		N/A
Oil & Gas Customer B		12%		15%		N/A
Oil & Gas Customer C		12%		N/A		N/A
Oilfield Services Customer A		15%		N/A		N/A
Oilfield Services Customer B		12%		13%		N/A

Although a substantial portion of our oil and natural gas sales and our oilfield services revenues may be to a few large customers, we do not believe the loss of any one customer would have a material adverse effect on our exploration and production business as we believe that other purchasers would be available.  While we believe that there are numerous operators in the Williston Basin in need of pressure pumping and related oilfield services, a severe and sustained downturn in commodities pricing could result in the loss of a significant customer.  However, we do not believe that the loss of a significant customer would have a material adverse impact on the Company.

Inventories.  Inventories, included in other current assets, consist of well equipment, sand, chemicals 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 utilized in evaluating net realizable value.

Oil and Natural Gas Properties.  We use the full cost method of accounting for our oil and natural gas operations.  All costs associated with property acquisition, exploration, and development activities in the United States and Canada are capitalized into a United States full cost pool and a Canadian full cost pool, respectively.  The cost pools are amortized on a unit-of-production basis using proved oil and natural gas reserves.  Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and natural gas reserves.  Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized.  Expenditures for maintenance and repairs are charged to production expense in the period incurred.  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. 

The capitalized costs of unevaluated properties, including those of wells in progress, are excluded from the costs being amortized.  We do not have major development projects that are excluded from costs being amortized.  On a quarterly basis, we evaluate excluded costs for inclusion in the costs to be amortized resulting from the determination of proved reserves or impairments.  To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. 

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

Amortization of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, including future development costs and asset retirement costs, are amortized over total estimated proved reserves by country-wide cost pool. 

Companies that follow the full cost method of accounting are required to make quarterly “ceiling test” calculations for each full cost pool.  This test ensures that the country-wide cost pool’s total capitalized costs for oil and natural gas properties (net of accumulated amortization and deferred income taxes) do not exceed the sum of (i) the present value discounted at 10% of estimated future net cash flows from the Company’s proved oil and natural gas reserves in that country, (ii) the pool’s 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.  If the cost pool’s net capitalized costs exceed this “ceiling,” the excess is charged to expense.  Any recorded ceiling-test impairment of oil and natural gas properties is not reversible at a later date. 

At January 31, 2015, the calculated value of the ceiling limitation approximated the carrying value of our oil and natural gas properties subject to the test and no impairment was necessary.  However, Triangle will likely be required to recognize an impairment of oil and natural gas properties in future periods if oil and natural gas prices remain at current prices or continue to decline or if there is a negative impact on one or more of the other components of the calculation and such an impairment will likely be material.

Oil and Natural Gas Reserves.Amortization of the capitalized costs of oil and natural gas properties, including estimated future development and abandonment costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves.  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.

Oilfield Services Equipment and Other Property and Equipment.  Oilfield services equipment and other property and equipment as of January 31, 2014 and 2013 consisted of the following:

	For the Years Ended January 31,
(in thousands)	2015		2014
Land	$	7,888	$	2,512
Building and leasehold improvements		33,625		18,388
Oilfield service equipment		116,354		56,355
Vehicles		4,811		2,288
Software, computers and office equipment		5,327		3,016
Capital leases		853		—
Total depreciable assets		168,858		82,559
Accumulated depreciation		(35,189)		(12,800)
Depreciable assets, net		133,669		69,759
Assets not placed in service		1,247		1,333
Total oilfield service equipment and other property & equipment, net	$	134,916	$	71,092

Expenditures for replacements, renewals, and betterments are capitalized.  Maintenance and repairs are charged to operations as incurred.  Oilfield services equipment and other property and equipment are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable.  We have not found or recognized any impairment losses on such 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 ranging from 3-20 years.

Deferred Loan Costs.  Deferred financing costs include origination, legal, engineering, and other fees incurred to issue debt.  Deferred financing costs are amortized to interest expense using the effective interest method over the respective borrowing term.

Equity Investment.  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 after elimination of intra-company profits and losses.  The Company records losses of the unconsolidated entities only to the extent of the Company’s investment.

We evaluate our equity method investment for impairment when there are indicators of impairment.  If indicators suggest impairment, we will perform an impairment test to assess whether an adjustment is necessary.  The impairment test considers whether the fair value of our equity method investment has declined and if any such decline is other than temporary.  If a decline in fair value is determined to be other than temporary, the investment’s carrying value is written down to fair value.

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.

Derivative Instruments.  The Company enters into derivative contracts, primarily costless collars and swaps, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative instruments are recorded on the balance sheet at fair value. The Company has elected not to apply hedge accounting to any of its derivative transactions and, consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges.

The Company holds equity investment derivatives (Class A Warrants (Series 1 through Series 4)) in Caliber.  Our equity investment derivatives are measured at fair value and are included in equity investment on the consolidated balance sheet.  Net gains and losses on equity investment derivatives are recorded based on the changes in the fair values of the derivative instruments and included in our consolidated statements of operations.

Income Taxes.  Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The Company’s policy is to recognize interest and/or penalties related to uncertain tax positions in interest expense.

Oil, Natural Gas and Natural Gas Liquids Revenue.  The Company recognizes revenues from the sale of crude oil, natural gas and natural gas liquids when the product is delivered at a fixed or determinable price, title has transferred, and/or collectability is reasonably assured and evidenced by a contract.  There were no oil or natural gas sales imbalances at January 31, 2015, 2014, or 2013.

Oilfield Services Revenue.  The Company enters into arrangements with its customers to provide hydraulic fracturing services and other oilfield 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 collectability is reasonably assured.  Revenue is recognized and customers are invoiced upon the completion of each job, which generally consists of numerous fracturing stages and complementary completion services.  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.

Share-Based Compensation.  Share-based compensation is measured at the estimated grant date fair value of the awards and is recognized over the requisite service period (usually the vesting period). The Company estimates forfeitures in calculating the cost related to stock-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered.

Earnings per Share.  Basic earnings per common 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 reflects increases in average shares outstanding from the potential dilution, under the treasury stock method, that could occur upon (i) exercise of stock options, (ii) vesting of restricted stock units, and (iii) conversion of convertible debt. The treasury stock method assumes exercise, vesting or conversion at the beginning of a period for securities outstanding at the end of a period. Also, the treasury stock method for calculating dilution assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company at the quarter’s average stock price using assumed proceeds from (a) the exercise cost of the options and (b) the foregone future compensation expense of hypothetical early vesting of the outstanding restricted stock units.  The assumed proceeds are adjusted for income tax effects.  In the event of a net loss, no potential common shares are included in the calculation of shares outstanding, as their inclusion would be anti-dilutive.

The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and unvested restricted stock, for the periods presented (in thousands):

	For the Years Ended January 31,
	2015		2014		2013
Dilutive		17,421		15,979		—
Anti-dilutive shares		6,905		5,250		4,500

The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the years ended January 31, 2015, 2014, and 2013:

	For the Years Ended January 31,
(in thousands, except per share data)	2015		2014		2013
Net income (loss) attributable to common stockholders	$	93,397	$	73,480	$	(13,760)
Effect of 5% convertible note conversion		4,135		3,392		—
Net income (loss) attributable to common stockholders after effect of debt conversion	$	97,532	$	76,872	$	(13,760)
Basic weighted average common shares outstanding		83,611		68,579		44,475
Effect of dilutive securities		17,421		15,979		—
Diluted weighted average common shares outstanding		101,032		84,558		44,475
Basic net income (loss) per share	$	1.12	$	1.07	$	(0.31)
Diluted net income (loss) per share	$	0.97	$	0.91	$	(0.31)

New Pronouncements Issued But Not Yet Adopted.  In April 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.  ASU 2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures.  The guidance is effective for annual and interim reporting periods beginning after December 15, 2014.  Adoption of this amendment will not have a material effect on our financial position or results of operations.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, issued as a new Topic, Accounting Standards Codification Topic 606.  The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized.  The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  This ASU is effective for the Company beginning in fiscal year 2017 and can be adopted by the Company either retrospectively or as a cumulative-effect adjustment as of the date of adoption.  We are currently evaluating the effect that adopting this new accounting guidance will have on our consolidated results of operations, cash flows and financial position.

In August 2014, the FASB issued ASU No. 2014-15, which requires management of public and private companies to evaluate whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued (or available to be issued when applicable) and, if so, to disclose that fact.  Management will be required to make this evaluation for both annual and interim reporting periods, if applicable.  ASU No. 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods within annual periods beginning after December 15, 2016.  The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

Accounting standard-setting organizations frequently issue new or revised accounting rules.  We regularly review new pronouncements to determine their impact, if any, on our consolidated financial statements.  Other than the standards discussed above, there are no significant accounting standards applicable to Triangle which have not been adopted. 

Reclassifications.  Certain amounts in the consolidated balance sheet as of January 31, 2014, and in our consolidated statement of operations for the years ended January 31, 2014 and 2013, have been reclassified to conform to the financial statement presentation for the period ended January 31, 2015.  The balance sheet reclassifications relate to changes in the captions presented in the balance sheet.  The statement of operations reclassifications relate to the break out of amortization of deferred loan costs from interest expense and amounts related to revisions in the Elmworth abandonment obligation were reclassified from accretion of asset retirement obligations to depreciation and amortization expense. Such reclassifications had no impact on consolidated total assets, stockholders’ equity or net income previously reported.

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Asset Retirement Obligations (Tables)

12 Months Ended

Jan. 31, 2015

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

	For the Years Ended January 31,
(in thousands)	2015		2014
Balance at the beginning of the period	$	4,629	$	3,422
Liabilities incurred		1,821		944
Revision of estimates		2,737		774
Sale of assets		(29)		(83)
Liabilities settled		(747)		(484)
Accretion		167		56
Balance at the end of the period		8,578		4,629
Less current portion of obligations		(5,391)		(3,333)
Long-term ARO	$	3,187	$	1,296

The current portion of ARO is classified with other accrued liabilities and the long-term ARO is classified in other long-term liabilities in the accompanying consolidated balance sheets.

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Income Taxes (Details 3) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Income Taxes [Abstract]
Federal statutory tax expense (benefit)	$ 48,613	$ 28,498	$ (5,069)
State income tax expense / (benefit), net of federal income tax benefit	3,618	2,324	(361)
Permanent differences	3,196	3,221	2,280
Difference in foreign tax rates	539	164	28
Effect of tax rate change	(147)	(258)	(71)
Credits	(338)	(100)
State NOL adjustment	1,061
Bad debt deduction for receivables from Elmworth	(14,517)
Attribute reduction - cancellation of debt exclusion - Elmworth	8,466
Changes in valuation allowance	(7,464)	(26,364)	2,443
Other	2,473	456	750
Income tax expense (benefit)	$ 45,500	$ 7,941

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Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Tables)

12 Months Ended

Jan. 31, 2015

Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract]

Summary Of Changes In Estimated Proved Reserves

	Crude Oil	Natural Gas	NGL
	(Mbbls)	(MMcf)	(Mbbls)
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	—
Revisions of previous estimates	2,727	(859)	1,762
Purchase of reserves	6,836	4,714	690
Extensions, discoveries and other additions	12,059	11,064	1,599
Sale of reserves	(491)	(374)	—
Production	(1,754)	(626)	(70)
Total proved reserves at January 31, 2014	31,916	26,504	3,981
Revisions of previous estimates	2,087	1,475	(776)
Purchase of reserves	3,655	2,928	7
Extensions, discoveries and other additions	13,946	11,710	1,129
Sale of reserves	(2)	(3)	—
Production	(3,511)	(2,429)	(260)
Total proved reserves at January 31, 2015	48,091	40,185	4,081
Proved Developed Reserves included above:
January 31, 2012	538	202	—
January 31, 2013	4,985	5,906	—
January 31, 2014	13,734	10,930	1,440
January 31, 2015	29,605	24,136	2,350
Proved Undeveloped Reserves included above:
January 31, 2012	827	472	—
January 31, 2013	7,554	6,679	—
January 31, 2014	18,182	15,574	2,541
January 31, 2015	18,486	16,049	1,731

Summary Of Status Of Proved Undeveloped Reserves

	(Mboe)	Gross Wells	Net Wells
Proved Undeveloped Reserves at January 31, 2012	905	17	2.6
Became developed reserves in fiscal year 2013	(363)	(9)	(1.2)
Traded for net acres in other drill spacing units	(256)	(5)	(0.7)
Revisions	66	(1)	(0.1)
Acquisition of additional interests in PUD location	172	—	0.3
Additional proved undeveloped locations	8,144	57	18.9
Proved Undeveloped Reserves at January 31, 2013	8,668	59	19.8
Became developed reserves in fiscal year 2014	(3,701)	(32)	(7.9)
Traded for net acres in other drill spacing units	(353)	(4)	(0.8)
Revisions	84	—	—
Acquisitions	5,466	13	11.8
Extensions and discoveries of proved reserves	13,155	68	29.6
Proved Undeveloped Reserves at January 31, 2014	23,319	104	52.5
Became developed reserves in fiscal year 2015	(8,461)	(30)	(18.5)
Revisions	1,676	(14)	4.7
Acquisitions	528	6	1.3
Extensions and discoveries of proved reserves	5,830	37	14.0
Proved Undeveloped Reserves at January 31, 2015	22,892	103	54.0

Schedule Of Proved Undeveloped Drilling Locations

	PUD	Development Wells
	Locations	Gross	Net
Proved undeveloped locations:
For which Triangle operated wells are to be drilled and completed by January 31, 2020	79	79	49.9
For which non-operated wells were in-progress at January 31, 2015 and are expected to be completed in fiscal year 2016	—	—	—
That are non-operated wells with drilling permits	6	6	0.7
That are non-operated wells to be drilled by July 31, 2017	18	18	3.4
	103	103	54.0

Schedule Of Prices Used In Calculation Of Standardized Measure

	For the Years Ended January 31,
	2015		2014		2013
Oil price per barrel	$	79.71	$	93.09	$	84.76
Natural gas price per Mcf	$	6.09	$	3.99	$	5.23
Natural gas liquids price per barrel	$	34.61	$	44.10	$	—

Summary Of Future Net Cash Flows Relating To Proved Oil And Natural Gas Reserves

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Future cash inflows	$	4,219,155	$	3,252,079	$	1,128,676
Future costs:
Production		(1,586,288)		(1,118,508)		(333,185)
Development		(439,749)		(505,432)		(199,173)
Future income tax expense		(394,538)		(364,340)		(87,313)
Future net cash flows		1,798,580		1,263,799		509,005
10% discount factor		(977,088)		(690,564)		(297,653)
Standardized measure of discounted future net cash flows relating to proved reserves	$	821,492	$	573,235	$	211,352

Schedule Of Principle Sources Of Change In Standardized Measure

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Standardized measure, beginning of period	$	573,235	$	211,352	$	29,428
Extensions and discoveries, net of future production and development costs		312,185		333,140		193,107
Sales, net of production costs		(210,505)		(123,786)		(31,502)
Previously estimated development costs incurred during the period		121,282		66,724		10,368
Revision of quantity estimates		24,115		73,598		15,910
Net change in prices, net of production costs		(141,200)		19,173		2,779
Acquisition of reserves		91,327		99,683		2,119
Divestiture of reserves		(72)		(7,341)		(3,273)
Accretion of discount		67,790		22,486		2,943
Changes in future development costs		57,259		7,699		801
Change in income taxes		(56,652)		(91,161)		(13,509)
Change in production timing and other		(17,272)		(38,332)		2,181
Standardized measure, end of period	$	821,492	$	573,235	$	211,352

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Long-term Debt (Details 6) (USD $)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jun. 27, 2014
Long-term Debt, Fiscal Year Maturity [Abstract]
2016	503,000
2017	1,450,000
2018	1,594,000
2019	119,852,000
2020	105,565,000
Thereafter	571,177,000
Total debt	800,141,000	343,208,000
Second Lien Credit Facility [Member]
Line of Credit Facility [Line Items]
Credit facility, maximum borrowing capacity			$ 60,000,000
LIBOR [Member] | Second Lien Credit Facility [Member]
Line of Credit Facility [Line Items]
Credit facility, basis spread on interest rate	7.00%
Base Rate [Member] | Second Lien Credit Facility [Member]
Line of Credit Facility [Line Items]
Credit facility, basis spread on interest rate	6.00%

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Share-Based Compensation (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Compensation expense before capitalized amount	$ 9,062	$ 9,221	$ 7,415
Less amounts capitalized to oil and natural gas properties	(1,143)	(1,391)	(949)
Stock-based compensation, net	7,919	7,830	6,466
Restricted Stock Units (RSUs) [Member]
Compensation expense before capitalized amount	6,254	7,496	6,639
Employee Stock Option [Member]
Compensation expense before capitalized amount	2,299	1,135	60
Stock Issued Pursuant to Termination Agreements [Member]
Compensation expense before capitalized amount			99
RockPile Stock Based Compensation Related to Series [Member]
Compensation expense before capitalized amount	$ 509	$ 590	$ 617

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Jan. 31, 2015	Jan. 31, 2014
CURRENT ASSETS
Cash and equivalents	$ 67,871	$ 81,750
Accounts receivable	164,438	106,463
Commodity derivatives	62,248	955
Other current assets	14,952	5,652
Total current assets	309,509	194,820
Oil and natural gas properties, at cost, full cost method of accounting:
Proved properties	1,153,584	629,051
Unproved properties and properties under development, not being amortized	142,896	121,393
Total oil and natural gas properties	1,296,480	750,444
Accumulated amortization	(170,390)	(67,657)
Net oil and natural gas properties	1,126,090	682,787
Oilfield services equipment - net	87,549	46,585
Other property and equipment, net	47,367	24,507
Net property, plant and equipment	1,261,006	753,879
Deferred loan costs	14,038	3,207
Equity investment	64,411	68,536
Commodity derivatives		1,192
Other	5,906	5,888
Total other assets	84,355	78,823
Total assets	1,654,870	1,027,522
CURRENT LIABILITIES
Accounts payable and accrued capital expenditures	176,182	109,599
Other accrued liabilities	73,440	40,588
Current portion of long-term debt	503	8,851
Interest payable	2,250	268
Deferred income taxes	19,467
Total current liabilities	271,842	159,306
LONG-TERM LIABILITIES
5% convertible note	135,877	129,290
Borrowings on credit facilities	224,159	196,065
TUSA 6.75% notes	429,500
Other notes and mortgages payable	10,102	9,002
Deferred income taxes	33,974	8,262
Other	4,398	2,435
Total liabilities	1,109,852	504,360
COMMITMENT AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Common stock, $0.00001 par value, 140,000,000 shares authorized; 75,174,442 and 85,735,827 shares issued and outstanding at January 31, 2015 and January 31, 2014, respectively	1	1
Additional paid-in capital	545,017	571,701
Retained earnings (accumulated deficit)		(48,540)
Total stockholders' equity	545,018	523,162
Total liabilities and stockholders' equity	$ 1,654,870	$ 1,027,522

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Summary Of Significant Accounting Policies (Details 4) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Jan. 31, 2015	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Oct. 31, 2013	Jul. 31, 2013	Apr. 30, 2013	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Earnings Per Share [Abstract]
Net income	$ 38,905	$ 25,398	$ 14,552	$ 14,542	$ 14,249	$ 47,221	$ 6,799	$ 5,211	$ 93,397	$ 73,480	$ (13,760)
Effect of 5% Convertible Note conversion									4,135	3,392
Net income (loss) attributable to common shareholders after effect of debt conversion									$ 97,532	$ 76,872	$ (13,760)
Basic weighted average common shares outstanding									83,611	68,579	44,475
Effect of dilutive securities									17,421	15,979
Diluted weighted average common shares outstanding									101,032	84,558	44,475
Basic net income (loss) per share	$ 0.50	$ 0.30	$ 0.17	$ 0.17	$ 0.17	$ 0.60	$ 0.12	$ 0.10	$ 1.12	$ 1.07	$ (0.31)
Diluted net income (loss) per share	$ 0.42	$ 0.26	$ 0.15	$ 0.15	$ 0.15	$ 0.50	$ 0.12	$ 0.10	$ 0.97	$ 0.91	$ (0.31)
Anitdilutive securities excluded from calculation of diluted net income									6,905	5,250	4,500

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Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 7) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract]
Standardized measure, beginning of period	$ 573,235	$ 211,352	$ 29,428
Extensions and discoveries, net of future production and development costs	312,185	333,140	193,107
Sales, net of production costs	(210,505)	(123,786)	(31,502)
Previously estimated development costs incurred during the period	121,282	66,724	10,368
Revision of quantity estimates	24,115	73,598	15,910
Net change in prices, net of production costs	(141,200)	19,173	2,779
Acquisition of reserves	91,327	99,683	2,119
Divestitures of reserves	(72)	(7,341)	(3,273)
Accretion of discount	67,790	22,486	2,943
Changes in future development costs	57,259	7,699	801
Change in income taxes	(56,652)	(91,161)	(13,509)
Change in production timing and other	(17,272)	(38,332)	2,181
Standardized measure, end of period	$ 821,492	$ 573,235	$ 211,352

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Consolidated Statement of Stockholders' Equity (USD $)	Common Stock [Member]	Additional Paid-In Capital [Member]	Accumulated Deficit [Member]	Non-controlling Interest In Subsidiary [Member]	Total
Balance at Jan. 31, 2012	$ 1,000	$ 314,199,000	$ (108,260,000)	$ 3,855,000	$ 209,795,000
Balance, shares at Jan. 31, 2012	43,515,958
Shares issued for the purchase of oil and natural gas properties, value		1,204,000			1,204,000
Shares issued for the purchase of oil and natural gas properties, shares	225,000
Shares issued for services		73,000			73,000
Shares issued for services, shares	10,000
Exercise of stock options, value		13,000			13,000
Exercise of stock options, shares	4,167
Vesting of restricted stock units (net of shares surrendered for taxes)		(1,884,000)			(1,884,000)
Vesting of restricted stock units (net of shares surrendered for taxes), shares	774,941
Common shares issued pursuant to termination agreements (net of shares surrendered for taxes), value		99,000			99,000
Common stock issued pursuant to termination agreement (net of shares surrendered for taxes), shares	17,230
Acquire minority interest in subsidiary		2,522,000		(3,131,000)	(609,000)
Acquire minority interest in subsidiary, shares	2,185,715
Stock-based compensation		7,415,000			7,415,000
Net income (loss) for the year			(13,760,000)	(724,000)	(14,484,000)
Balance at Jan. 31, 2013	1,000	323,641,000	(122,020,000)		201,622,000
Balance, shares at Jan. 31, 2013	46,733,011
Common stock issued, value		245,369,000			245,369,000
Common stock issued, shares	37,905,000
Shares issued for the purchase of oil and natural gas properties, value		2,438,000			2,438,000
Shares issued for the purchase of oil and natural gas properties, shares	325,000
Stock offering costs		(7,072,000)			(7,072,000)
Exercise of stock options, value		162,000			162,000
Exercise of stock options, shares	108,333
Vesting of restricted stock units (net of shares surrendered for taxes)		(2,058,000)			(2,058,000)
Vesting of restricted stock units (net of shares surrendered for taxes), shares	664,483
Stock-based compensation		9,221,000			9,221,000
Net income (loss) for the year			73,480,000		73,480,000
Balance at Jan. 31, 2014	1,000	571,701,000	(48,540,000)		523,162,000
Balance, shares at Jan. 31, 2014	85,735,827				85,735,827
Exercise of stock options, value		135,000			135,000
Exercise of stock options, shares	108,333
Vesting of restricted stock units (net of shares surrendered for taxes)		(2,854,000)			(2,854,000)
Vesting of restricted stock units (net of shares surrendered for taxes), shares	762,026
Redeemed RockPile B-Units		(1,041,000)			(1,041,000)
Shares repurchased and retired		(31,986,000)	(44,857,000)		(76,843,000)
Shares repurchased and retired, shares	(11,431,744)
Stock-based compensation		9,062,000			9,062,000
Net income (loss) for the year			93,397,000		93,397,000
Balance at Jan. 31, 2015	$ 75,174,442	$ 545,017,000			$ 545,018,000
Balance, shares at Jan. 31, 2015	1,000				75,174,442

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Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 5)	12 Months Ended
	Jan. 31, 2015 item
PUD Locations [Member]
Development Wells Drilled [Line Items]
Proved undeveloped locations for operated wells to be drilled and completed by January 31, 2020	79
Proved undeveloped locations non-operated wells with drilling permits	6
Proved undeveloped locations proposed non-operated wells to be drilled by July 31, 2017	18
Proved undeveloped locations additions to proved undeveloped reserves	103
Development Wells Gross [Member]
Development Wells Drilled [Line Items]
Proved undeveloped locations for operated wells to be drilled and completed by January 31, 2020	79
Proved undeveloped locations non-operated wells with drilling permits	6
Proved undeveloped locations proposed non-operated wells to be drilled by July 31, 2017	18
Proved undeveloped locations additions to proved undeveloped reserves	103
Development Wells Net [Member]
Development Wells Drilled [Line Items]
Proved undeveloped locations for operated wells to be drilled and completed by January 31, 2020	49.9
Proved undeveloped locations non-operated wells with drilling permits	0.7
Proved undeveloped locations proposed non-operated wells to be drilled by July 31, 2017	3.4
Proved undeveloped locations additions to proved undeveloped reserves	54.0

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Oil And Natural Gas Properties (Details 3) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013	Jan. 31, 2012
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition	$ 113,606
Exploration	22,305
Capitalized Interest	6,985
Total	142,896
2015
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition	46,982
Exploration	20,830
Capitalized Interest	4,899
Total	72,711
2014
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition		25,785
Exploration		1,475
Capitalized Interest		2,086
Total		29,346
2013
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition			10,220
Total			10,220
2012 and prior
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition				30,619
Total				$ 30,619

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Fair Value Measurements (Tables)

12 Months Ended

Jan. 31, 2015

Fair Value Measurements [Abstract]

Schedule Of Fair Value, Assets And Liabilities Measured On Recurring Basis

	As of January 31, 2015
(in thousands)	Level1		Level 2		Level 3		Total
Assets:
Equity investment derivative assets	$	—	$	—	$	504	$	504
Commodity derivative assets	$	—	$	62,248	$	—	$	62,248
Liabilities:
RockPile earn-out liability	$	—	$	(1,825)	$	—	$	(1,825)

	As of January 31, 2014
(in thousands)	Level 1		Level 2		Level3		Total
Assets:
Equity investment derivative assets	$	—	$	—	$	39,734	$	39,734
Commodity derivative assets	$	—	$	2,147	$	—	$	2,147
Liabilities:
RockPile earn-out liability	$	—	$	(1,739)	$	—	$	(1,739)

Rollforward Of Level 3 Financial Liabilities

	Class A
	Trigger
(in thousands)	Units		Warrants
Balance at January 31, 2013	$	—	$	—
Initial recognition of equity investment derivative assets		38,091		1,696
Balance at January 31, 2014		38,091		1,696
Interest paid in-kind		—		—
Net unrecognized loss		—		—
Net unrealized gain		1,745		(1,192)
Conversion to Class A Units		(39,836)		—
Balance at January 31, 2015	$	—	$	504

Summary Of Fair Value Of Financial Instruments

	January 31, 2015				January 31, 2014
	Carrying		Estimated		Carrying		Estimated
(in thousands)	Value		FairValue		Value		Fair Value
5% convertible note	$	135,877	$	137,790	$	129,290	$	169,170
Revolving credit facilities		224,159		224,159		204,515		204,515
TUSA 6.75% notes		429,500		303,871		—		—
Other notes and mortgages payable		10,605		10,605		9,403		9,403

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Equity Investment And Equity Investment Derivatives (Details) (Caliber Midstream Partners, L.P. [Member], USD $)	12 Months Ended		0 Months Ended	1 Months Ended	0 Months Ended	1 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2015	Oct. 31, 2012	Sep. 12, 2013	Sep. 30, 2013	Feb. 02, 2015
Schedule of Equity Method Investments [Line Items]
Increase in equity method investment	$ 553,000	$ 39,734,000
FREIF Caliber Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Contribution to joint venture				70,000,000
Equity method investments, Class A Units received			2,720,000	7,000,000
Equity method investment, Class A units held							17,720,000
Equity method investments, warrants received			906,667
FREIF Caliber Holdings [Member] | Forecast [Member]
Schedule of Equity Method Investments [Line Items]
Contribution to joint venture					80,000,000
Equity method investments, Class A Units received					8,000,000
Equity method investment, Class A units held	15,000,000		15,000,000
Equity method ownership percentage	68.00%		68.00%
Triangle Caliber Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Contribution to joint venture				$ 30,000,000
Equity method investments, Class A Units received				3,000,000
Equity method investments, Class A Trigger Units received				4,000,000
Equity method investment, Class A units held							7,000,000
Equity method investments, warrants received			3,626,667
Triangle Caliber Holdings LLC [Member] | Forecast [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, Class A Units received					4,000,000
Equity method investments, Class A Trigger Units received					4,000,000
Equity method investment, Class A units held	7,000,000		7,000,000
Equity method ownership percentage	32.00%		32.00%
Class A Units [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, Class A units held	7,000,000	3,000,000	7,000,000
Series 1 Warrant $14.69 Strike Price [Member] | Triangle Caliber Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, warrants received				4,000,000
Equity method investments, warrant excercise price				$ 14.69
Series 1 Warrant $14.69 Strike Price [Member] | Triangle Caliber Holdings LLC [Member] | Forecast [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, warrants received	1,600,000
Equity method investments, warrant excercise price	$ 14.69
Series 2 Warrant $24.00 Strike Price [Member] | Triangle Caliber Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, warrants received				2,400,000
Equity method investments, warrant excercise price				$ 24.00
Class A Trigger Warrant $14.69 Strike Price [Member] | Triangle Caliber Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, warrants received				1,600,000
Equity method investments, warrant excercise price				$ 14.69
Class A Trigger Warrant $14.69 Strike Price [Member] | Triangle Caliber Holdings LLC [Member] | Forecast [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments Class A trigger units converted	1,600,000
Series 5 Warrant $32.00 Strike Price [Member] | FREIF Caliber Holdings [Member] | Forecast [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, warrants received					5,000,000
Equity method investments, warrant excercise price					$ 32.00
Series 3 Warrant $24.00 Strike Price [Member] | Triangle Caliber Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, warrants received						3,000,000
Equity method investments, warrant excercise price						$ 24.00
Series 4 Warrant $30.00 Strike Price [Member] | Triangle Caliber Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, warrants received						2,000,000
Equity method investments, warrant excercise price						$ 30.00

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Supplemental Disclosures Of Cash Flow Information

12 Months Ended

Jan. 31, 2015

Supplemental Disclosures of Cash Flow Information [Abstract]

Supplemental Disclosures of Cash Flow Information

16.  SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Cash paid during the period for:
Interest expense	$	19,713	$	1,419	$	75
Income taxes	$	600	$	—	$	—
Non-cash investing activities:
Additions (reductions) to oil and natural gas properties through:
Increased accounts payable and accrued liabilities	$	47,838	$	30,785	$	36,654
Issuance of common stock	$	—	$	2,438	$	1,204
Capitalized stock based compensation	$	1,143	$	1,391	$	949
Change in asset retirement obligations	$	1,818	$	673	$	1,869
Capitalized interest	$	4,899	$	809	$	—
Acquisition of oilfield services equipment through notes payable and liabilities	$	—	$	1,990	$	—
Purchase of minority interest in RockPile	$	—	$	—	$	12,349
Non-cash financing activities:
Notes payable issued for redemption of RockPile B Units	$	1,041	$	—	$	—

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Income Taxes (Tables)

12 Months Ended

Jan. 31, 2015

Income Taxes [Abstract]

Schedule Of Income Tax Expense (Benefit)

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Current tax expense (benefit)	$	—	$	—	$	—
Deferred tax expense (benefit)
Federal		42,400		7,324		(2,137)
State		3,100		617		(223)
Foreign		—		—		(83)
Valuation allowance - United States and Canada		—		—		2,443
Total income tax provision (benefit)	$	45,500	$	7,941	$	—
Income (loss) before income taxes	$	138,897	$	81,421	$	(14,484)
Effective income tax rate		33%		10%		0%

Reconciliation Of Income Tax Expense (Benefit)

	For the Years Ended January 31,
(in thousands)		2015		2014		2013
Federal statutory tax expense (benefit)	$	48,613	$	28,498	$	(5,069)
State income tax expense / (benefit), net of federal income tax benefit		3,618		2,324		(361)
Permanent differences		3,196		3,221		2,280
Difference in foreign tax rates		539		164		28
Effect of tax rate change		(147)		(258)		(71)
Credits		(338)		(100)		—
State NOL adjustment		1,061		—		—
Bad debt deduction for receivables from Elmworth		(14,517)		—		—
Attribute reduction - cancellation of debt exclusion - Elmworth		8,466		—		—
Changes in valuation allowance		(7,464)		(26,364)		2,443
Other		2,473		456		750
Provision for income taxes	$	45,500	$	7,941	$	—

Components Of Deferred Tax Assets And Liabilities

	For the Years Ended January 31,
(in thousands)	2015		2014
Current:
Assets:
Asset retirement obligations	$	1,394	$	1,071
Accruals		1,138		103
Total current assets		2,532		1,174
Valuation allowance		(1,193)		(492)
Total current assets after valuation allowance		1,339		682
Liabilities:
Hedging liabilities		(20,806)		(361)
Total current liabilities		(20,806)		(361)
Net current deferred income tax asset (liability)	$	(19,467)	$	321
Non-Current:
Assets:
Canadian oil and natural gas properties	$	—	$	6,080
United States net losses carried forward		48,443		33,129
Canadian net losses carried forward		—		1,905
Asset retirement obligations		1,198		416
Stock-based compensation		3,182		3,105
Property and equipment		—		157
Other		2,395		1,864
Total non-current assets		55,218		46,656
Valuation allowance		—		(8,165)
Total non-current assets after valuation allowance		55,218		38,491
Liabilities:
United States oil and natural gas properties		(56,531)		(29,536)
Investment in Caliber		(32,661)		(16,766)
Hedging liabilities		—		(451)
Total deferred non-current income tax liability		(89,192)		(46,753)
Net non-current deferred income tax liability	$	(33,974)	$	(8,262)
Total net deferred income tax liability	$	(53,441)	$	(7,941)

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Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited)

12 Months Ended

Jan. 31, 2015

Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract]

Unaudited Supplemental Oil And Natural Gas Disclosures

18.  SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

Oil and Natural Gas Reserve Information.  The following information concerning the Company’s oil and natural gas operations is provided pursuant to the FASB guidance regarding Oil and Gas Reserve Estimation and Disclosures.

At January 31, 2015, the Company’s oil and natural gas producing activities were conducted in the Williston Basin in the continental United States.  All of our proved reserves are in the Bakken or Three Forks formations in the North Dakota counties of McKenzie, Williams, Stark, or Dunn, or in the Montana counties of Roosevelt, Sheridan, Madison or Richland.  The Company has ceased all Canadian exploration and production activities and its oil and natural gas properties were fully impaired as of January 31, 2012. 

Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids, 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.  Such prices are also adjusted for regional price differentials; gathering, transportation, and processing; and other factors to arrive at prices utilized in the calculation of a standardized measure of discounted future net cash flows related to proved oil and natural gas reserves (“Standardized Measure”)

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, 2015.  Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”) an independent petroleum engineering firm, audited our estimate as of January 31, 2015, January 31, 2014, and January 31, 2013 of proved reserves and undiscounted and discounted future cash flows (before income taxes) from those proved reserves.  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. 

The reserve estimates presented in the following tables are expressed in thousands of barrels of oil (“Mbbls”), millions of cubic feet of natural gas (“MMcf”), thousands of barrels of natural gas liquids (“Mbbls”) and thousands of barrels of oil equivalent (“Mboe”).  

	Crude Oil	Natural Gas	NGL
	(Mbbls)	(MMcf)	(Mbbls)
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	—
Revisions of previous estimates	2,727	(859)	1,762
Purchase of reserves	6,836	4,714	690
Extensions, discoveries and other additions	12,059	11,064	1,599
Sale of reserves	(491)	(374)	—
Production	(1,754)	(626)	(70)
Total proved reserves at January 31, 2014	31,916	26,504	3,981
Revisions of previous estimates	2,087	1,475	(776)
Purchase of reserves	3,655	2,928	7
Extensions, discoveries and other additions	13,946	11,710	1,129
Sale of reserves	(2)	(3)	—
Production	(3,511)	(2,429)	(260)
Total proved reserves at January 31, 2015	48,091	40,185	4,081
Proved Developed Reserves included above:
January 31, 2012	538	202	—
January 31, 2013	4,985	5,906	—
January 31, 2014	13,734	10,930	1,440
January 31, 2015	29,605	24,136	2,350
Proved Undeveloped Reserves included above:
January 31, 2012	827	472	—
January 31, 2013	7,554	6,679	—
January 31, 2014	18,182	15,574	2,541
January 31, 2015	18,486	16,049	1,731

The following average prices are reflected in the calculation of the Standardized Measure:

	For the Years Ended January 31,
	2015		2014		2013
Oil price per barrel	$	79.71	$	93.09	$	84.76
Natural gas price per Mcf	$	6.09	$	3.99	$	5.23
Natural gas liquids price per barrel	$	34.61	$	44.10	$	—

Extensions and Discoveries in Fiscal Year 2015.  The 13.9 million barrels of oil, 11.7 billion cubic feet of natural gas, and 1.1 million barrels of natural gas liquids of proved reserves added by extensions and discoveries in North Dakota in fiscal year 2015 are primarily due to our increased completion of wells, particularly operated wells, and other parties completing wells offsetting our properties.  In fiscal year 2015, we participated in 145 gross (38.6 net) productive wells completed, and we added 37 gross (14.0 net) new proved undeveloped well locations discussed later in this Note.

Revisions in Fiscal Year 2015.The 2.1 million barrels upward revision in crude oil proved reserves in fiscal year 2015 was primarily due to longer production histories that favorably supported the increase in proved oil reserves.  The 1.5 billion cubic feet upward revision in natural gas reserves and the 0.8 million barrels decrease in NGL reserves reflect agreements and arrangements at the end of fiscal year 2015 to have the majority of our proved natural gas reserves processed to extract NGLs and dry residue gas that Triangle would sell to third parties. 

Purchases of Proved Properties in Fiscal Year 2015.The Company purchased certain proved properties which added reserves of 3.7 million barrels of oil and 2.9 billion cubic feet of natural gas proved reserves in fiscal year 2015. 

Proved Undeveloped Reserves.  At January 31, 2015, we had proved undeveloped oil and natural gas reserves of 22,892 Mboe, down 427 Mboe from 23,319 Mboe at January 31, 2014.  Changes in our proved undeveloped reserves are summarized in the following table:

	(Mboe)	Gross Wells	Net Wells
Proved Undeveloped Reserves at January 31, 2012	905	17	2.6
Became developed reserves in fiscal year 2013	(363)	(9)	(1.2)
Traded for net acres in other drill spacing units	(256)	(5)	(0.7)
Revisions	66	(1)	(0.1)
Acquisition of additional interests in PUD location	172	—	0.3
Additional proved undeveloped locations	8,144	57	18.9
Proved Undeveloped Reserves at January 31, 2013	8,668	59	19.8
Became developed reserves in fiscal year 2014	(3,701)	(32)	(7.9)
Traded for net acres in other drill spacing units	(353)	(4)	(0.8)
Revisions	84	—	—
Acquisitions	5,466	13	11.8
Extensions and discoveries of proved reserves	13,155	68	29.6
Proved Undeveloped Reserves at January 31, 2014	23,319	104	52.5
Became developed reserves in fiscal year 2015	(8,461)	(30)	(18.5)
Revisions	1,676	(14)	4.7
Acquisitions	528	6	1.3
Extensions and discoveries of proved reserves	5,830	37	14.0
Proved Undeveloped Reserves at January 31, 2015	22,892	103	54.0

During fiscal year 2015, we invested approximately $151.6 million (averaging $8.2 million per net well) related to the drilling and completion of the 30 gross (18.5 net) wells that converted 8,461 Mboe of proved undeveloped reserves to proved developed reserves.

For proved undeveloped (“PUD”) locations at January 31, 2015, the following table provides further information on the timing and status of operated and non-operated locations:

	PUD	Development Wells
	Locations	Gross	Net
Proved undeveloped locations:
For which Triangle operated wells are to be drilled and completed by January 31, 2020	79	79	49.9
For which non-operated wells were in-progress at January 31, 2015 and are expected to be completed in fiscal year 2016	—	—	—
That are non-operated wells with drilling permits	6	6	0.7
That are non-operated wells to be drilled by July 31, 2017	18	18	3.4
	103	103	54.0

Standardized Measure of Discounted Future Net Cash Flows

Authoritative accounting guidance by the FASB requires the Company to calculate and disclose for January 31, 2015 and 2014 (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 2015 and 2014.  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 fiscal year-end estimated future proved reserve quantities. 

· Future cash inflows are proved reserves at the prices used in determining proved reserves, i.e., for crude oil, natural gas, or natural gas liquids, the average price during the year, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

· 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 fiscal year-end cost rates and assuming continuation of existing economic conditions.

· 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. 

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 summary sets forth the Company’s Standardized Measure for January 31, 2015, 2014, and 2013:

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Future cash inflows	$	4,219,155	$	3,252,079	$	1,128,676
Future costs:
Production		(1,586,288)		(1,118,508)		(333,185)
Development		(439,749)		(505,432)		(199,173)
Future income tax expense		(394,538)		(364,340)		(87,313)
Future net cash flows		1,798,580		1,263,799		509,005
10% discount factor		(977,088)		(690,564)		(297,653)
Standardized measure of discounted future net cash flows relating to proved reserves	$	821,492	$	573,235	$	211,352

Because the estimated salvage value of equipment exceeds the related abandonment costs for well plugging and site restoration costs, future development costs at January 31, 2015 of $439.7 million does not include any net abandonment costs.

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

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Standardized measure, beginning of period	$	573,235	$	211,352	$	29,428
Extensions and discoveries, net of future production and development costs		312,185		333,140		193,107
Sales, net of production costs		(210,505)		(123,786)		(31,502)
Previously estimated development costs incurred during the period		121,282		66,724		10,368
Revision of quantity estimates		24,115		73,598		15,910
Net change in prices, net of production costs		(141,200)		19,173		2,779
Acquisition of reserves		91,327		99,683		2,119
Divestiture of reserves		(72)		(7,341)		(3,273)
Accretion of discount		67,790		22,486		2,943
Changes in future development costs		57,259		7,699		801
Change in income taxes		(56,652)		(91,161)		(13,509)
Change in production timing and other		(17,272)		(38,332)		2,181
Standardized measure, end of period	$	821,492	$	573,235	$	211,352

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 amortization 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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Equity Investment And Equity Investment Derivatives (Details 4) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jun. 30, 2014
Schedule of Equity Method Investments [Line Items]
Gain (loss) on equity investment derivative	$ 553	$ 39,785
Class A Triggering Units [Member]
Schedule of Equity Method Investments [Line Items]
Gain (loss) on equity investment derivative	1,700
Equity investment, number of units vested			4,000,000
Class A Trigger Unit Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Expected term of warrants	12 years
Equity Method Investments, warrant floor price	$ 5.00
Input assumption, historical volatility period	10 years
Caliber Midstream Partners, L.P. [Member]
Schedule of Equity Method Investments [Line Items]
Increase in equity method investment	553	39,734
Caliber Midstream Partners, L.P. [Member] | Class A Triggering Units [Member]
Schedule of Equity Method Investments [Line Items]
Increase in equity method investment	1,745	38,091
Caliber Midstream Partners, L.P. [Member] | Class A Trigger Unit Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Increase in equity method investment	$ 532	$ 234

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Description Of Business

12 Months Ended

Jan. 31, 2015

Description Of Business [Abstract]

Description Of Business

1.  DESCRIPTION OF BUSINESS

Triangle Petroleum Corporation (“Triangle,” the “Company,” “we,” “us,” “our,” or “ours”) is an independent energy holding company with three principal lines of business: oil and natural gas exploration, development, and production; oilfield services; and midstream services.

We hold leasehold interests and conduct our operations in the Williston Basin of North Dakota and Montana.  Our core focus area is in McKenzie and Williams Counties, North Dakota, and eastern Roosevelt and Sheridan Counties, Montana.  We conduct our exploration and production operations through our wholly-owned subsidiary, Triangle USA Petroleum Corporation (“TUSA”).

In June 2011, we formed RockPile Energy Services, LLC (“RockPile”), a wholly-owned subsidiary, which provides oilfield and complementary well completion services to oil and natural gas exploration and production companies predominantly in the Williston Basin.  RockPile began operations in July 2012.

In September 2012, through our wholly-owned subsidiary, Triangle Caliber Holdings, LLC, we formed Caliber Midstream Partners, L.P. (“Caliber”), an unconsolidated joint venture with First Reserve Energy Infrastructure Fund (“FREIF”).  Caliber was formed for the purpose of providing oil, natural gas and water transportation and related services to oil and natural gas exploration and production companies in the Williston Basin.

The Company, through its wholly-owned subsidiary, Elmworth Energy Corporation (“Elmworth”), previously conducted insignificant exploration and production activities in Canada.  Elmworth has since sold all leasehold interests except for acreage in the Maritimes Basin of Nova Scotia.  Elmworth has ceased all exploration and production activities in Canada except for reclaiming five wells, the drilling site and brine ponds on its Nova Scotia acreage.  Elmworth has no proved reserves and its oil and natural gas properties were fully impaired as of January 31, 2012.

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Consolidated Balance Sheets (Parenthetical) (USD $)	Jan. 31, 2015	Jan. 31, 2014
Common stock, par value	$ 0.00001	$ 0.00001
Common stock, shares authorized	140,000,000	140,000,000
Common stock, shares issued	75,174,442	85,735,827
Common stock, shares outstanding	75,174,442	85,735,827
Convertible Notes [Member]
Debt instrument, interest rate	5.00%	5.00%
TUSA Senior Notes [Member]
Debt instrument, interest rate	6.75%

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Share-Based Compensation

12 Months Ended

Jan. 31, 2015

Share-Based Compensation [Abstract]

Share-Based Compensation

11.  SHARE-BASED COMPENSATION

The Company has granted equity awards to officers, directors, and certain employees of the Company including restricted stock units and stock options.  In addition, RockPile has granted Series B Units which represent interests in future RockPile profits.  The Company measures its awards based on the award’s grant date fair value which is recognized ratably over the applicable vesting period.

On May 27, 2014, the Board approved the 2014 Plan, which was approved by the Company’s stockholders on July 17, 2014.  No additional awards may be granted under prior plans but all outstanding awards under prior plans shall continue in accordance with their applicable terms and conditions.  The 2014 Plan authorizes the Company to issue stock options, SARs, restricted stock, restricted stock units, cash awards, and other awards to any employees, officers, directors, and consultants of the Company and its subsidiaries.  The maximum number of shares of common stock reserved for issuance under the 2014 Plan is 6.0 million shares, subject to adjustment for certain transactions.

For the years ended January 31, 2015, 2014, and 2013, the Company recorded share-based compensation related to restricted stock units, stock options and RockPile Series B Units as follows:

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Restricted stock units	$	6,254	$	7,496	$	6,639
Stock options		2,299		1,135		60
Stock issued pursuant to termination agreements		—		—		99
RockPile Series B Units		509		590		617
		9,062		9,221		7,415
Less amounts capitalized to oil and natural gas properties		(1,143)		(1,391)		(949)
Compensation expense	$	7,919	$	7,830	$	6,466

Restricted Stock Units.  During the year ended January 31, 2015, the Company granted 1,523,700 restricted stock units as compensation to employees, officers, and directors.  Restricted stock units vest over one to five years.  As of January 31, 2015, there was approximately $19.8 million of total unrecognized compensation expense related to unvested restricted stock units.  This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 4.0 years on a weighted average basis.  When restricted stock units vest, the holder has the right to receive one share of the Company’s common stock per vesting unit. 

The following table summarizes the status of restricted stock units outstanding:  

		Weighted-
	Number of	Average Award
	Shares	Date Fair Value
Restricted stock units outstanding - January 31, 2012	2,488,342	$	7.02
Units granted	1,041,400	$	6.37
Units forfeited	(5,600)	$	7.59
Units vested	(1,000,057)	$	6.90
Restricted stock units outstanding - January 31, 2013	2,524,085	$	6.68
Units granted	1,440,133	$	6.95
Units forfeited	(141,909)	$	6.58
Units vested	(946,681)	$	6.71
Restricted stock units outstanding - January 31, 2014	2,875,628	$	6.62
Units granted	1,523,700	$	9.42
Units forfeited	(394,921)	$	7.21
Units vested	(1,090,362)	$	7.04
Restricted stock units outstanding - January 31, 2015	2,914,045	$	7.92

Stock Options.The following table summarizes the status of stock options outstanding:

		Weighted
	Numberof	Average
	Shares	ExercisePrice
Options outstanding - January 31, 2012 (142,500 exercisable)	235,833	$	1.50
Options exercised	(4,167)	$	3.00
Options outstanding - January 31, 2013 (231,666 exercisable)	231,666	$	1.48
Options forfeited	(15,000)	$	3.00
Options exercised	(108,333)	$	1.25
Options granted	6,000,000	$	11.25
Options outstanding - January 31, 2014 (108,333 exercisable)	6,108,333	$	11.07
Options forfeited	—	$	—
Options exercised	(108,333)	$	1.25
Options granted	700,000	$	14.00
Options outstanding - January 31, 2015 (600,000 exercisable)	6,700,000	$	11.54

The following table presents additional information related to the stock options outstanding at January 31, 2015:

		Remaining
Exercise Price		Contractual Life	Number of Shares
per Share		(years)	Outstanding		Exercisable
$	7.50	8.43		750,000		75,000
$	8.50	8.43		750,000		75,000
$	10.00	8.43		1,500,000		150,000
$	12.00	8.43		1,500,000		150,000
$	15.00	8.43		1,500,000		150,000
$	12.00	6.61		233,333		—
$	14.00	6.61		233,333		—
$	16.00	9.61		233,334		—
				6,700,000		600,000
Weighted average exercise price per share			$	11.54	$	11.25
Weighted average remaining contractual life				8.34		8.43

Compensation expense related to stock options is calculated using the Black-Scholes valuation model.  Expected volatility is generally based on the historical volatility of Triangle’s common stock.  The expected term of the options is estimated based on factors such as vesting periods, contractual expiration dates, historical trends in the Company’s common stock price and historical exercise behavior.  The risk-free rate for the expected term (from service inception to option exercise) of the options is based on the yields of U.S. Treasury instruments with lives comparable to the estimated expected option term or life.

The following assumptions were used for the Black-Scholes model to calculate the share-based compensation expense for the options granted in fiscal year 2015:

Risk free rate	1.06	%
Dividend yield	—
Expected volatility	54	%
Weighted average expected stock option life (years)	3.0

As of January 31, 2015, there was approximately $18.6 million of total unrecognized compensation expense related to stock options.  This compensation expense is expected to be recognized over the remaining vesting period of the related awards of approximately 3.3 years. 

RockPile Share-Based Compensation.  RockPile currently has two classes of equity; Series A Units which have an 8% preference and Series B Units, which are used for equity awards. RockPile approved a plan that includes provisions allowing RockPile to make equity grants in the form of restricted units (Series B Units) pursuant to Restricted Unit Agreements. The plan authorizes RockPile to issue an aggregate of up to 6.0 million Series B Units in multiple series designated by a sequential number with the right to reissue forfeited or redeemed Series B Units.

The Series B Units are intended to constitute “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 zero.  RockPile may designate a “Liquidation Value” applicable to each tranche of a Series B Unit grant so as to constitute a net profits interest. The Liquidation Value shall equal the dollar amount per unit that would, in the reasonable determination of RockPile, be distributed with respect to the initial Series B Unit tranche if, immediately prior to the issuance of a new Series B Unit tranche, the assets of RockPile were sold for their fair market value and the proceeds (net of any liabilities) were distributed.

The Series A Units are entitled to a return of contributed capital and an 8% preferred return 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 $40.0 million. As of January 31, 2015, the $40.0 million cumulative distribution threshold has been met. Therefore, 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 will be distributed on a pro rata basis. Subsequently issued 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.  RockPile’s limited liability company agreement was amended on January 31, 2015 to permit distributions to holders of vested Series B Units as prepayment for future amounts payable to them upon a RockPile liquidity event.  In the event a holder of vested Series B Units receives such a pre-liquidity event distribution, their capital account will be adjusted to reflect the prepayment.

Series B Units currently have a 7 to 52 month vesting schedule. 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. 

A summary of the activity for RockPile’s Series B Units is as follows:

	Series	Series	Series	Series
	B-1units	B-2 units	B-3 units	B-4 units	Total
Units outstanding - January 31, 2012	—	—	—	—	—
Units granted	3,100,000	60,000	—	—	3,160,000
Units outstanding - January 31, 2013	3,100,000	60,000	—	—	3,160,000
Units granted	—	—	910,000	—	910,000
Units outstanding - January 31, 2014	3,100,000	60,000	910,000	—	4,070,000
Units redeemed	(180,000)	—	—	—	(180,000)
Units granted	—	—	—	1,412,000	1,412,000
Units outstanding - January 31, 2015	2,920,000	60,000	910,000	1,412,000	5,302,000
Vested	2,920,000	30,000	188,000	—	3,138,000
Unvested	—	30,000	722,000	1,412,000	2,164,000

As of January 31, 2015, there was approximately $2.6 million of unrecognized compensation expense related to unvested Series B Units.  We expect to recognize such expense on a pro-rata basis on the Series B Units’ vesting schedule during the next five fiscal years.

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Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 4)	12 Months Ended
	Jan. 31, 2015 MBoe	Jan. 31, 2014 MBoe	Jan. 31, 2013 MBoe
Reserve Quantities [Line Items]
Proved undeveloped reserve (BOE) beginning balance	23,319	8,668	905
Became developed reserves during fiscal year	(8,461)	(3,701)	(363)
Traded for net acres in drill spacing units		(353)	(256)
Net revisions	1,676	84	66
Acquisition of additional interests in PUD location	528	5,466	172
Additional proved undeveloped locations			8,144
Extensions and discoveries of proved reserves	5,830	13,155
Proved undeveloped reserve (BOE) ending balance	22,892	23,319	8,668
Gross Wells [Member]
Reserve Quantities [Line Items]
Proved undeveloped wells, beginning balance	104	59	17
Proved undeveloped wells, became developed during period	(30)	(32)	(9)
Proved undeveloped wells, traded for net acres in other drill spacing units		(4)	(5)
Proved undeveloped wells, net revisions	(14)		(1)
Proved undeveloped wells, acquisition of additional interests in proved undeveloped locations	6	13
Proved undeveloped wells, additional proved undeveloped locations			57
Proved undeveloped wells, extensions and discoveries	37	68
Proved undeveloped wells, ending balance	103	104	59
Net Wells [Member]
Reserve Quantities [Line Items]
Proved undeveloped wells, beginning balance	52.5	19.8	2.6
Proved undeveloped wells, became developed during period	(18.5)	(7.9)	(1.2)
Proved undeveloped wells, traded for net acres in other drill spacing units		(0.8)	(0.7)
Proved undeveloped wells, net revisions	4.7		(0.1)
Proved undeveloped wells, acquisition of additional interests in proved undeveloped locations	1.3	11.8	0.3
Proved undeveloped wells, additional proved undeveloped locations			18.9
Proved undeveloped wells, extensions and discoveries	14.0	29.6
Proved undeveloped wells, ending balance	54.0	52.5	19.8

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Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 2)	12 Months Ended
	Jan. 31, 2015 MBbls	Jan. 31, 2014 MBbls	Jan. 31, 2013 MBbls	Jan. 31, 2012 MBbls
Crude Oil Reserves [Member]
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	31,916	12,539	1,365
Revisions of previous estimates	2,087	2,727	665
Purchase of reserves	3,655	6,836	230
Extensions, discoveries and other additions	13,946	12,059	10,960
Sale of reserves	(2)	(491)	(229)
Production	(3,511)	(1,754)	(452)
Total proved reserves, ending balance	48,091	31,916	12,539
Proved Developed, Volume	29,605	13,734	4,985	538
Proved Undeveloped, Volume	18,486	18,182	7,554	827
Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	26,504	12,585	674
Revisions of previous estimates	1,475	(859)	1,832
Purchase of reserves	2,928	4,714	181
Extensions, discoveries and other additions	11,710	11,064	10,251
Sale of reserves	(3)	(374)	(165)
Production	(2,429)	(626)	(188)
Total proved reserves, ending balance	40,185	26,504	12,585
Proved Developed, Volume	24,136	10,930	5,906	202
Proved Undeveloped, Volume	16,049	15,574	6,679	472
Natural Gas Liquids Reserves [Member]
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	3,981
Revisions of previous estimates	(776)	1,762
Purchase of reserves	7	690
Extensions, discoveries and other additions	1,129	1,599
Production	(260)	(70)
Total proved reserves, ending balance	4,081	3,981
Proved Developed, Volume	2,350	1,440
Proved Undeveloped, Volume	1,731	2,541

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Document And Entity Information (USD $)	12 Months Ended
	Jan. 31, 2015	Apr. 01, 2015	Jul. 31, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Jan. 31, 2015
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2015
Entity Registrant Name	Triangle Petroleum Corp
Entity Central Index Key	0001281922
Current Fiscal Year End Date	--01-31
Entity Filer Category	Accelerated Filer
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 695,506,738
Entity Common Stock, Shares Outstanding		75,288,381

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Fair Value Measurements

12 Months Ended

Jan. 31, 2015

Fair Value Measurements [Abstract]

Fair Value Measurements

12.  FAIR VALUE MEASUREMENTS

The FASB’s ASC 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; and

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

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.

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, 2015 and January 31, 2014, by level within the fair value hierarchy:

	As of January 31, 2015
(in thousands)	Level1		Level 2		Level 3		Total
Assets:
Equity investment derivative assets	$	—	$	—	$	504	$	504
Commodity derivative assets	$	—	$	62,248	$	—	$	62,248
Liabilities:
RockPile earn-out liability	$	—	$	(1,825)	$	—	$	(1,825)

	As of January 31, 2014
(in thousands)	Level 1		Level 2		Level3		Total
Assets:
Equity investment derivative assets	$	—	$	—	$	39,734	$	39,734
Commodity derivative assets	$	—	$	2,147	$	—	$	2,147
Liabilities:
RockPile earn-out liability	$	—	$	(1,739)	$	—	$	(1,739)

Commodity Derivative Instruments.The Company determines its estimate of the fair value of commodity 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 considering 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.  The Company believes that each of its counterparties is creditworthy and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.  At January 31, 2015, commodity derivative instruments utilized by the Company consist of costless collars and swaps.  The Company’s commodity derivative instruments are valued using public indices and are traded with third-party counterparties, but are not openly traded on an exchange.  As such, the Company has classified these commodity derivative instruments as Level 2.

Caliber Class A (Series 1 through Series 4) Warrants.  The Company determines its estimate of the fair value of Caliber Class A Warrants using a MCS model.  For each MCS, the value of the Class A Units was forecasted at the end of each quarter based on a predetermined yield, and the strike price for the warrant is adjusted accordingly.  The fair value of the underlying Class A Units was estimated employing primarily a discounted cash flows analysis.  At January 31, 2015, the Company’s Caliber Class A Warrants are valued using valuation models that are generally less observable from objective sources.  As such, the Company has classified these instruments as Level 3.

Earn-out Liability.  The Company determined the estimated fair value of the earn-out liability relating to RockPile’s acquisition of Team Well using a market approach based on information derived from an analysis performed for RockPile by an independent third-party. This analysis used publicly available information from market participants in the same industry, generally accepted methods for estimating an investor’s return requirements, and quoted market prices in active markets. As such, the earn-out liability has been classified as Level 2.

Summary of Level 3 Financial Assets and Liabilities.  The following table presents the rollforward of the fair values of the Company’s Level 3 financial assets and liabilities:

	Class A
	Trigger
(in thousands)	Units		Warrants
Balance at January 31, 2013	$	—	$	—
Initial recognition of equity investment derivative assets		38,091		1,696
Balance at January 31, 2014		38,091		1,696
Interest paid in-kind		—		—
Net unrecognized loss		—		—
Net unrealized gain		1,745		(1,192)
Conversion to Class A Units		(39,836)		—
Balance at January 31, 2015	$	—	$	504

Fair Value of Financial Instruments.  The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable and payable, derivatives and Caliber Class A Warrants (discussed above) and long-term debt. The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short-term maturities. The Convertible Note’s estimated fair value is based on discounted cash flows analysis and option pricing.  The carrying amount of the Company’s revolving credit facilities approximated fair value because the interest rate of the facilities is variable. The fair value of other notes and mortgages payable is not significantly different than their carry values.  The fair value of the TUSA 6.75% Notes is derived from quoted market prices. This disclosure does not impact our financial position, results of operations or cash flows.

	January 31, 2015				January 31, 2014
	Carrying		Estimated		Carrying		Estimated
(in thousands)	Value		FairValue		Value		Fair Value
5% convertible note	$	135,877	$	137,790	$	129,290	$	169,170
Revolving credit facilities		224,159		224,159		204,515		204,515
TUSA 6.75% notes		429,500		303,871		—		—
Other notes and mortgages payable		10,605		10,605		9,403		9,403

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Fair Value Measurements (Details 3) (USD $) In Thousands, unless otherwise specified	Jan. 31, 2015	Jan. 31, 2014	Jul. 18, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
5% convertible note, carrying value	$ 135,877	$ 129,290
Convertible note	137,790	169,170
Long-term portion of credit facilities	224,159	196,065
Revolving credit facilities, carrying value	224,159	204,515
Revolving credit facilities, fair value	224,159	204,515
Other notes and mortgages payable, carrying value	10,605	9,403
Other notes and mortgages payable, fair value	10,605	9,403
TUSA 6.75% notes, carrying value	429,500
TUSA 6.75% notes, fair value	$ 303,871
Convertible Notes [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt instrument, interest rate	5.00%	5.00%
TUSA Senior Notes [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt instrument, interest rate	6.75%		6.75%

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Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details) (USD $)	12 Months Ended
	Jan. 31, 2015 MBoe item	Jan. 31, 2014 MBoe	Jan. 31, 2013 MBoe	Jan. 31, 2012 MBoe
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items]
Productive wells, gross	145
Productive wells, net	38.6
New proved undeveloped, gross	37
New proved undeveloped, net	14.0
Proved Undeveloped Reserve BOE 1	22,892	23,319	8,668	905
Net increase and decrease on proved undeveloped reserve BOE 1	427
Proved undeveloped reserves, conversion to proved developed reserves	8,461	3,701	363
Investment in drilling and completion of wells	$ 151,600,000
Investment in drilling and completion per well	8,200,000
Estimated future development costs	(439,749,000)	(505,432,000)	(199,173,000)
Estimated future net costs	$ 1,798,580,000	$ 1,263,799,000	$ 509,005,000
Gross Wells [Member]
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items]
Proved undeveloped wells, became developed during period	30	32	9
Net Wells [Member]
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items]
Proved undeveloped wells, became developed during period	18.5	7.9	1.2
Crude Oil Reserves [Member]
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items]
Proved reserves added by extensions and discoveries	13,946	12,059	10,960
Revisions of previous estimates	2,087	2,727	665
Natural Gas Reserves [Member]
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items]
Proved reserves added by extensions and discoveries	11,710	11,064	10,251
Revisions of previous estimates	1,475	(859)	1,832
Natural Gas Liquids Reserves [Member]
Unaudited Supplemental Oil And Natural Gas Disclosures [Line Items]
Proved reserves added by extensions and discoveries	1,129	1,599
Revisions of previous estimates	(776)	1,762

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Consolidated Statements of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
REVENUES
Oil and natural gas liquids sales	$ 284,502	$ 160,548	$ 39,614
Oilfield services	288,453	98,199	20,747
Total revenues	572,955	258,747	60,361
EXPENSES:
Lease operating expenses	25,703	14,454	3,566
Gathering, transportation and processing	18,520	4,302	150
Production taxes	29,774	18,006	4,492
Depreciation and amortization	124,055	58,011	15,081
Accretion of asset retirement obligations	167	56	184
Oilfield services	216,596	82,327	16,606
General and administrative, net of amounts capitalized	62,757	34,629	28,543
Total operating expenses	477,572	211,785	68,622
INCOME FROM OPERATIONS	95,383	46,962	(8,261)
OTHER INCOME (EXPENSE):
Interest expense, net	(25,100)	(7,132)	(2,672)
Amortization of deferred loan costs	(3,149)	(554)	(146)
Gain on extinguishment of debt	6,610
Commodity derivatives gains (losses)	64,050	1,082	(3,570)
Equity investment income (loss)	81		(283)
Gain on equity investment derivatives	553	39,785
Other income	469	1,278	448
Total other income (expense)	43,514	34,459	(6,223)
INCOME (LOSS) BEFORE INCOME TAXES	138,897	81,421	(14,484)
Income tax provision	45,500	7,941
NET INCOME (LOSS)	93,397	73,480	(14,484)
Less: net loss attributable to the noncontrolling interest in subsidiary			724
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ 93,397	$ 73,480	$ (13,760)
Earnings (loss) per common share outstanding:
Basic	$ 1.12	$ 1.07	$ (0.31)
Diluted	$ 0.97	$ 0.91	$ (0.31)
Weighted average common shares outstanding:
Basic	83,611	68,579	44,475
Diluted	101,032	84,558	44,475

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Oil And Natural Gas Properties

12 Months Ended

Jan. 31, 2015

Oil And Natural Gas Properties [Abstract]

Oil And Natural Gas Properties

6.  OIL AND NATURAL GAS PROPERTIES

The following table sets forth the capitalized costs incurred in our oil and natural gas production, exploration, and development activities in the United States for years ended January 31, 2015, 2014, and 2013:

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Costs incurred during the period
Acquisition of properties:
Proved	$	90,920	$	80,201	$	623
Unproved		47,858		41,377		20,570
Exploration		180,174		96,731		55,583
Development		226,765		216,046		91,666
Oil and natural gas expenditures		545,717		434,355		168,442
Asset retirement obligations, net		1,818		676		370
	$	547,535	$	435,031	$	168,812

During fiscal years 2015, 2014, and 2013, we acquired oil and natural gas properties, and participated in the drilling and/or completion of wells, for total consideration of approximately $545.7 million, $434.4 million, and $168.4 million, including $138.8million, $121.6 million, and $21.2 million, respectively, for the acquisition of oil and natural gas properties.  Total consideration paid includes common stock of $2.4 million and $1.2 million for fiscal years 2014 and 2013, respectively.  During fiscal years 2015, 2014, and 2013, we capitalized $4.8 million, $3.7 million, and $2.0 million, respectively, of internal land, geology, and operations 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 properties.

The following table summarizes oil and natural gas property costs not being amortized at January 31, 2015, by year that the costs were incurred:

			Fiscal Year Costs Incurred
									2012
(in thousands)	Total		2015		2014		2013		and prior
Acquisition	$	113,606	$	46,982	$	25,785	$	10,220	$	30,619
Exploration		22,305		20,830		1,475		—		—
Capitalized interest		6,985		4,899		2,086		—		—
Total	$	142,896	$	72,711	$	29,346	$	10,220	$	30,619

The $142.9million of costs not being amortized includes $17.1 million in costs for unevaluated wells in progress expected to be completed prior to January 31, 2016.  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, 2015 will be reclassified to proved properties over the next five years.

Depreciation and amortization expense of oil and natural gas properties in the U.S. for fiscal years 2015, 2014, and 2013 was $106.9 million, $51.0 million and $13.5 million, respectively.

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Hedging And Commodity Derivative Financial Instruments

12 Months Ended

Jan. 31, 2015

Commodity Derivative Instruments [Abstract]

Commodity Derivative Instruments

5.  HEDGING AND COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

Through TUSA, the Company has entered into commodity derivative instruments utilizing costless collars and swaps 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 three counterparties.  The Company has netting arrangements with each 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.  The Company has not designated any of its derivative contracts as fair value or cash flow hedges.  Therefore, the Company does not apply hedge accounting to its commodity derivative instruments.  Net gains and losses on derivative activities are recorded based on the changes in the fair values of the derivative instruments.  Net gains and losses on derivative activities are recorded in the commodity derivatives gains (losses) caption on the consolidated statements of operations.  The Company’s cash flows are only impacted when the actual settlements under the commodity derivative contracts result in a payment to or from the counterparty.  These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows. 

The components of commodity derivative gains (losses) in the consolidated statements of operations are as follows (in thousands):

	For the Years Ended January 31,
	2015		2014		2013
Realized commodity derivative gains (losses)	$	11,422	$	(4,643)	$	-
Unrealized commodity derivative gains (losses)		52,628		5,725		(3,570)
Commodity derivative gains (losses), net	$	64,050	$	1,082	$	(3,570)

The Company’s commodity derivative contracts as of January 31, 2015 are summarized below:

	Contract		Quantity	Weighted Average	Weighted Average
Term End Date	Type	Basis (1)	(Bbl/d)	Put Strike	Call Strike
Fiscal Year 2016	Collar	NYMEX	4,356	$ 86.85	$ 98.63

(1) “NYMEX” refers to West Texas Intermediate crude oil prices at Cushing, Oklahoma as quoted on the New York Mercantile Exchange.

Subsequent to January 31, 2015, the Company entered into crude oil swaps for 1,500 Bbl/d at a weighted average price of $60.07 per barrel effective for the period from October 1, 2015 through December 31, 2016, and crude oil swaps for 500 Bbl/d at a weighted average price of $60.30 per barrel, effective for the period from January 1, 2016 through December 31, 2016.

The estimated fair values of commodity derivatives included in the consolidated balance sheets at January 31, 2015 and 2014 are summarized below. The net fair value of the Company’s commodity derivatives changed by $60.1 million from a net asset of $2.1 million at January 31, 2014 to a net asset of $62.2 million at January 31, 2015, primarily due to (i) changes in the futures prices for oil, which are used in the calculation of the fair value of commodity derivatives, (ii) settlement of commodity derivative positions during the current period and (iii) changes to the Company’s commodity derivative portfolio in fiscal year 2015. The Company does not offset asset and liability positions with the same counterparties within the consolidated financial statements; rather, all contracts are presented at their gross estimated fair value. As of the dates indicated, the Company’s derivative assets and liabilities are presented below (in thousands). These balances represent the estimated fair value of the contracts. The Company has not designated any of its derivative contracts as cash-flow hedging instruments for accounting purposes. The main headings represent the balance sheet captions for the contracts presented (in thousands).

	For the Years Ended January 31,
	2015		2014
Current Assets:
Crude oil derivative contracts	$	62,248	$	955
Other Long-Term Assets:
Crude oil derivative contracts		—		1,192
Total derivative asset	$	62,248	$	2,147

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Quarterly Financial Information (Unaudited)

12 Months Ended

Jan. 31, 2015

Quarterly Financial Information [Abstract]

Quarterly Financial Information

17.  QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The Company’s quarterly financial information for fiscal years 2015 and 2014 is as follows:

	For the Year Ended January 31, 2015 (1)
	First		Second		Third		Fourth
(in thousands)	Quarter		Quarter		Quarter		Quarter
Total revenue	$	99,782	$	141,989	$	174,196	$	156,988
Income from operations (2)	$	22,347	$	38,489	$	33,345	$	1,202
Net income	$	14,542	$	14,552	$	25,398	$	38,905
Net income attributable to common stockholders	$	14,542	$	14,552	$	25,398	$	38,905
Net income per common share - basic	$	0.17	$	0.17	$	0.30	$	0.50
Net income per common share - diluted	$	0.15	$	0.15	$	0.26	$	0.42
	For the Year Ended January 31, 2014 (1)
	First		Second		Third		Fourth
(in thousands)	Quarter		Quarter		Quarter		Quarter
Total revenue	$	34,294	$	50,394	$	88,549	$	85,510
Income from operations (2)	$	4,328	$	12,973	$	17,160	$	12,501
Net income	$	5,211	$	6,799	$	47,221	$	14,249
Net income attributable to common stockholders	$	5,211	$	6,799	$	47,221	$	14,249
Net income per common share - basic	$	0.10	$	0.12	$	0.60	$	0.17
Net income per common share - diluted	$	0.10	$	0.12	$	0.50	$	0.15

(1) Amounts reported for the quarter period.

(2) There were immaterial reclassifications for the periods presented between operating expenses and other income (expense).

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Income Taxes

12 Months Ended

Jan. 31, 2015

Income Taxes [Abstract]

Income Taxes

13.  INCOME TAXES

The Company’s income tax provision (benefit) is composed of the following:

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Current tax expense (benefit)	$	—	$	—	$	—
Deferred tax expense (benefit)
Federal		42,400		7,324		(2,137)
State		3,100		617		(223)
Foreign		—		—		(83)
Valuation allowance - United States and Canada		—		—		2,443
Total income tax provision (benefit)	$	45,500	$	7,941	$	—
Income (loss) before income taxes	$	138,897	$	81,421	$	(14,484)
Effective income tax rate		33%		10%		0%

A reconciliation of the income tax provision (benefit) computed by applying the federal statutory rate of 35.0% to the Company’s income tax provision (benefit) is as follows:

	For the Years Ended January 31,
(in thousands)		2015		2014		2013
Federal statutory tax expense (benefit)	$	48,613	$	28,498	$	(5,069)
State income tax expense / (benefit), net of federal income tax benefit		3,618		2,324		(361)
Permanent differences		3,196		3,221		2,280
Difference in foreign tax rates		539		164		28
Effect of tax rate change		(147)		(258)		(71)
Credits		(338)		(100)		—
State NOL adjustment		1,061		—		—
Bad debt deduction for receivables from Elmworth		(14,517)		—		—
Attribute reduction - cancellation of debt exclusion - Elmworth		8,466		—		—
Changes in valuation allowance		(7,464)		(26,364)		2,443
Other		2,473		456		750
Provision for income taxes	$	45,500	$	7,941	$	—

The difference in foreign tax rate of $0.5 million in fiscal year 2015 is a result of adjusting the U.S. blended statutory tax rate of 37.6% down to the Canadian statutory tax rate of 25.0%. 

The components of Triangle’s net deferred income tax assets and liabilities are as follows for fiscal years 2015 and 2014:

	For the Years Ended January 31,
(in thousands)	2015		2014
Current:
Assets:
Asset retirement obligations	$	1,394	$	1,071
Accruals		1,138		103
Total current assets		2,532		1,174
Valuation allowance		(1,193)		(492)
Total current assets after valuation allowance		1,339		682
Liabilities:
Hedging liabilities		(20,806)		(361)
Total current liabilities		(20,806)		(361)
Net current deferred income tax asset (liability)	$	(19,467)	$	321
Non-Current:
Assets:
Canadian oil and natural gas properties	$	—	$	6,080
United States net losses carried forward		48,443		33,129
Canadian net losses carried forward		—		1,905
Asset retirement obligations		1,198		416
Stock-based compensation		3,182		3,105
Property and equipment		—		157
Other		2,395		1,864
Total non-current assets		55,218		46,656
Valuation allowance		—		(8,165)
Total non-current assets after valuation allowance		55,218		38,491
Liabilities:
United States oil and natural gas properties		(56,531)		(29,536)
Investment in Caliber		(32,661)		(16,766)
Hedging liabilities		—		(451)
Total deferred non-current income tax liability		(89,192)		(46,753)
Net non-current deferred income tax liability	$	(33,974)	$	(8,262)
Total net deferred income tax liability	$	(53,441)	$	(7,941)

As of fiscal year 2013 the Company placed a full valuation allowance against deferred income taxes.  During the year ended January 31, 2014, Triangle had determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that the net U.S. deferred tax assets will be realized. Therefore, all deferred tax benefits were recognized in fiscal year 2014 and the full valuation allowance removed as part of the effective tax rate.

Triangle has also determined in its judgment, based upon all available evidence (both positive and negative), that it is more likely than not that the net Canadian deferred tax assets will not be realized. Therefore, all remaining Canadian deferred tax assets will have a full valuation allowance placed against them.  As a result of the cancellation of indebtedness related to the Elmworth intercompany, certain deferred tax assets and the related valuation allowance were reduced.  The key negative evidence relating to the Canadian deferred tax assets considered in this determination includes the following: (i) a history of both book and tax losses; (ii) cumulative losses in recent years; (iii) an expectation of tax losses during the next four to five years. Therefore, the combination of historical/cumulative losses as well as an expectation of book and taxable losses in the foreseeable future is the basis for the placement of a full valuation allowance against all of the Canadian deferred tax assets. 

The Company has net operating loss carryovers as of January 31, 2015 of $136.9 million for federal income tax purposes and $131.1 million for financial reporting purposes. The difference of $5.8 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable.  The United States NOL carryforwards begin expiring in 2024.  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, 2015 and 2014, 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 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.

The tax years for fiscal years ending 2012 to 2015 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 2012 to 2015, except for Colorado which is open for the fiscal years 2011 to 2015.  We also file with various Canadian taxing authorities which remain open for fiscal years 2011 to 2015.

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Income Taxes (Details 4) (USD $) In Thousands, unless otherwise specified	Jan. 31, 2015	Jan. 31, 2014
Income Taxes [Abstract]
Asset retirement obligations	$ 1,394	$ 1,071
Accurals	1,138	103
Total current assets	2,532	1,174
Valuation allowance	(1,193)	(492)
Total current assets after valuation allowance	1,339	682
Hedging liabilities	(20,806)	(361)
Total current liabilities	(20,806)	(361)
Net current deferred income tax asset	(19,467)	321
Canadian oil and natural gas properties		6,080
United States net losses carried forward	48,443	33,129
Canadian net losses carried forward		1,905
Asset retirement obligations	1,198	416
Stock-based compensation	3,182	3,105
Property and equipment		157
Other	2,395	1,864
Total non-current assets	55,218	46,656
Valuation allowance		(8,165)
Total non-current assets after valuation allowance	55,218	38,491
United States oil and natural gas properties	(56,531)	(29,536)
Investment in Caliber	(32,661)	(16,766)
Hedging liabilities		(451)
Total deferred non-current income tax liability	(89,192)	(46,753)
Deferred income tax liability	(33,974)	(8,262)
Total net deferred income tax liability	$ (53,441)	$ (7,941)

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Equity Investment And Equity Investment Derivatives

12 Months Ended

Jan. 31, 2015

Equity Investment [Abstract]

Equity Investment

9.   EQUITY INVESTMENT AND EQUITY INVESTMENT DERIVATIVES

Equity Investment.   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 FREIF. The joint venture entity, Caliber, was formed to provide crude oil, natural gas and water transportation and related services to the Company and third parties primarily within the Williston Basin of North Dakota and Montana.

Pursuant to the terms of the October 1, 2012 Contribution Agreement (the “Contribution Agreement”), Triangle Caliber Holdings agreed to contribute $30.0 million to Caliber in exchange for 3,000,000 Class A Units; 4,000,000 Class A Trigger Units with certain performance conditions; 4,000,000 Series 1 Warrants and 1,600,000 Class A Trigger Unit Warrants with an exercise price of $14.69;2,400,000 Series 2 Warrants with an exercise price of $24.00; and FREIF Caliber Holdings agreed to contribute $70.0 million to Caliber in exchange for 7,000,000 Class A Units, with the general partner of Caliber being owned and controlled equally by Triangle Caliber Holdings and FREIF Caliber Holdings. 

On September 12, 2013, Triangle Caliber Holdings and FREIF Caliber Holdings entered into an Amended and Restated Contribution Agreement (“A&R Contribution Agreement”), which amended and restated the Contribution Agreement. Pursuant to the terms of the A&R Contribution Agreement, FREIF Caliber Holdings agreed to contribute an additional $80.0 million to Caliber in exchange for an additional 8,000,000 Class A Units, to be issued no later than June 30, 2014, and 5,000,000 Series 5 Warrants with an exercise price of $32.00. Also pursuant to the terms of the A&R Contribution Agreement, Triangle Caliber Holdings received 3,000,000 Series 3 Warrants with an exercise price of $24.00;2,000,000 Series 4 Warrants with an exercise price of $30.00;  and the performance conditions associated with the 4,000,000 Class A Trigger Units granted in connection with the Contribution Agreement were removed and replaced with a provision to convert the 4,000,000 Class A Trigger Units into 4,000,000 Class A Units at the earlier of the commissioning of the Alexander gas processing facility or June 30, 2014. The conversion of the Class A Trigger Units on June 30, 2014 did not require any additional contribution of capital from Triangle Caliber Holdings. Additionally, the 1,600,000 Class A Trigger Unit Warrants granted in connection with the Contribution Agreement converted to 1,600,000 Series 1 Warrants on June 30, 2014 with an exercise price of $14.69.

Following the issuance of the additional 8,000,000 Class A Units to FREIF Caliber Holdings and the conversion by Triangle Caliber Holdings of its 4,000,000 Class A Trigger Units into 4,000,000 Class A Units, FREIF Caliber Holdings owned 15,000,000 Class A Units, representing an approximate sixty-eight percent (68%) limited partner interest in Caliber, and Triangle Caliber Holdings owned 7,000,000 Class A Units, representing an approximate thirty-two percent (32%) limited partner interest in Caliber.

The following summarizes the Company’s equity investment holdings in Caliber as of January 31, 2015 and 2014 and the strike prices for exercising warrants as of January 31, 2015:

	Expiration		Strike Price at		As of January 31,
	Date		January 31, 2015		2015	2014
Class A Units		—		—	7,000,000	3,000,000
Class A Trigger Units		—		—	—	4,000,000
Class A Trigger Unit Warrants		—		—	—	1,600,000
Series 1 Warrants		October 1, 2024	$	12.78	5,600,000	4,000,000
Series 2 Warrants		October 1, 2024	$	22.09	2,400,000	2,400,000
Series 3 Warrants		September 12, 2025	$	22.09	3,000,000	3,000,000
Series 4 Warrants		September 12, 2025	$	28.09	2,000,000	2,000,000

The Company’s investment interest in Caliber is considered to be variable, and Caliber is considered to be a variable interest entity because the power to direct the activities that most significantly impact Caliber’s economic performance does not reside with the holders of equity investment at risk.  The Company is not considered the primary beneficiary of Caliber since it does not have the power to direct the activities of Caliber that are considered most significant to its economic performance.  Under the equity method, our investment will be adjusted each period for contributions made, distributions received, the change in the fair value of our holdings of equity investment derivatives of Caliber, our share of Caliber’s net income and accretion of any basis differences.  Our maximum exposure to loss related to Caliber is limited to our equity investment.  We evaluate our equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

The following summarizes the activities related to the Company’s equity investment in Caliber for the years ended January 31, 2015 and 2014:

	For the Years Ended January 31,
(in thousands)	2015		2014
Balance at beginning of year	$	68,536	$	11,768
Capital contributions		—		18,000
Distributions		(6,080)		(3,150)
Equity investment share of net income before intra-company profit eliminations		1,402		2,184
Change in fair value of:
Class A Trigger Units (1)		1,745		38,091
Class A Trigger Unit Warrants (2)		532		234
Series 1 Warrants		(1,241)		926
Series 2 Warrants		(254)		254
Series 3 Warrants		(207)		207
Series 4 Warrants		(22)		22
Total changes in fair value		553		39,734
Balance at end of year	$	64,411	$	68,536
Fair value of trigger unit warrants and warrants at end of year	$	504	$	39,734

(1) The change in value was prior to the vesting of the Class A Trigger Units into Class A Units on June 30, 2014.

(2) On June 30, 2014, the 1,600,000 Class A Trigger Unit Warrants then outstanding automatically converted into Series 1 Warrants upon the Company’s vesting of the Class A Trigger Units, resulting in an aggregate of 5,600,000 Series 1 Warrants outstanding.

Equity Investment Derivatives.At January 31, 2015 and 2014, the Company held Class A (Series 1 through Series 4) Warrants to acquire additional ownership in Caliber.  These instruments are considered to be equity investment derivatives and are valued using the following valuation techniques, which are generally less observable from objective sources. 

At each period end, the fair value of the Class A (Series 1 through Series 4) Warrants were estimated using a Monte Carlo Simulation (“MCS”) model.  An MCS model provides a numeric approach to stochastic stock movement to forecast the future price of the underlying Class A Units, as opposed to an analytic solution provided by Black-Scholes.  For each MCS, the value of the Class A Units was forecasted at the end of each quarter based on a predetermined yield, and the strike price for the warrant is adjusted accordingly.  The fair value of the underlying Class A Units was estimated employing primarily a discounted cash flows analysis.  The resulting value represented a marketable minority value of Caliber.  As the Class A Units represent a non-marketable equity interest in a private enterprise, an adjustment to our preliminary value estimates was made to account for the lack of liquidity. 

The MCS model assumed that the Class A Warrants would be exercised at the earlier of (a) the contractual life of 12 years, and (b) the point at which the exercise price would be reduced to $5.00 per warrant (at which point it would be advantageous for Triangle to exercise early to capture future distributions on the Class A Units).  The key inputs to the MCS model are the same as the Black-Scholes model previously used including 10-year historical volatilities for publicly-traded comparable companies, risk-free interest rates over the expected warrant term and dividend yields based on expected distributions.  The change in fair value during the years ended January 31, 2015 and 2014 resulted in a $0.6 million and $39.8 million increase, respectively, in our equity investment account and as a gain on equity investment derivatives.  Also included in the gain on equity investment derivatives during the year ended January 31, 2015 was a gain of $1.7 million associated with the change in fair value of the 4,000,000 million Class A Trigger Units which vested on June 30, 2014.

On January 31, 2015, Triangle Caliber Holdings entered into a series of agreements modifying its joint venture with FREIF.  In connection with the modifications, Triangle Caliber Holdings entered into a Second Amended and Restated Contribution Agreement, dated January 31, 2015 (the “2nd A&R Contribution Agreement”), with FREIF, and the general partner of Caliber, owned and controlled equally between Triangle Caliber Holdings and FREIF.  Pursuant to the terms of the 2nd A&R Contribution Agreement, FREIF agreed to contribute an additional $34.0 million to Caliber in exchange for 2,720,000 Class A Units.  FREIF funded the $34.0 million contribution, and the additional 2,720,000 Class A Units were issued, on February 2, 2015.  Triangle made no capital contribution to Caliber in connection with the 2nd A&R Contribution Agreement or the issuance of the 2,720,000 Class A Units.  Following the issuance, FREIF holds 17,720,000 Class A Units, representing an approximate 71.7% Class A Units ownership interest in Caliber, and Triangle Caliber Holdings holds 7,000,000 Class A Units, representing an approximate 28.3% Class A Units ownership interest in Caliber.  Triangle will recognize a gain in the first quarter of fiscal year 2016 of $4.2 million related to Caliber’s issuance of these 2,720,000 Class A Units to FREIF. 

Also pursuant to the terms of the 2nd A&R Contribution Agreement, Triangle Caliber Holdings received warrants for the purchase of an additional 3,626,667 Class A Units, and FREIF received warrants for the purchase of an additional 906,667 Class A Units.   The warrants received by Triangle Caliber Holdings on February 2, 2015 included 2,357,334 Series 1 through 4 warrants at strike prices and expiration dates noted above and 1,269,333 Series 6 warrants with a strike price of $12.50 and an expiration date of February 2, 2018.  Triangle will also recognize a gain of $0.2 million in the first quarter of fiscal year 2016 related to the fair value of the warrants issued, which will be amortized over the lives of the related warrants. 

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Acquisitions (Details) (USD $)	0 Months Ended	1 Months Ended	12 Months Ended			1 Months Ended
	Aug. 28, 2013	Aug. 31, 2013 acre	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013	Jun. 30, 2014 acre	Oct. 31, 2013
Kodiak Oil And Natural Gas Property [Member]
Business Acquisition [Line Items]
Date of acquisition	Aug. 28, 2013
Number of acres purchased	5,600
Cash paid for acquisition	$ 83,800,000
Number of leasehold interest acres that could be exchanged		600
Pro forma depreciation, amortization and accretion expense			3,400,000	16,500,000	12,600,000
Marathon Oil And Gas [Member]
Business Acquisition [Line Items]
Date of acquisition			Jun. 01, 2014
Number of acres purchased						41,100
Cash paid for acquisition						90,352,000
Acquisition transaction costs						1,300,000
Total consideration for acquisition						90,352,000
Net downward adjustment included in the purchase price consideration						9,600,000
Team Well Service, Inc. [Member]
Business Acquisition [Line Items]
Date of acquisition			Oct. 01, 2013
Team Well Service, Inc. [Member] | Rockpile [Member]
Business Acquisition [Line Items]
Cash paid for acquisition							6,800,000
Unsecured note payable							800,000
Earn-out payments							1,500,000
Identifiable intangible assets							3,900,000
Goodwill							$ 1,700,000

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Acquisitions

12 Months Ended

Jan. 31, 2015

Acquisitions [Abstract]

Acquisitions

7.  ACQUISITIONS

Kodiak Oil & Gas Property Acquisition.  In August 2013, TUSA acquired interests in approximately 5,600 net acres of leaseholds and related producing properties along with various other related rights, permits, contracts, equipment and other assets, all located in McKenzie County, North Dakota, from Kodiak Oil & Gas Corporation (“Kodiak”).  We paid approximately $83.8 million in cash.  In addition, the Company and Kodiak also agreed to exchange certain of Triangle’s oil and natural gas leasehold interests in Kodiak’s operated units for approximately 600 net acres of leasehold interests held by Kodiak in units then operated by the Company.  The effective date for the acquisition and the exchange was July 1, 2013.

Marathon Oil & Gas Property Acquisition.  In June 2014, we acquired from Marathon Oil Company (“Marathon”) certain oil and natural gas leaseholds and related producing properties located in Williams County, North Dakota, Sheridan County, Montana, and Roosevelt County, Montana comprising approximately 41,100 net acres and various other related rights, permits, contracts, equipment and other assets for approximately $90.4 million in cash, net of certain closing adjustments of $9.6 million.  Transaction costs related to the acquisition incurred during the year ended January 31, 2015 of approximately $1.3 million are recorded in general and administrative expenses.

The acquisitions were accounted for using the acquisition method under ASC-805, Business Combinations, which requires the assets acquired and liabilities assumed to be recorded at fair value as of the acquisition date of June 30, 2014.  The following table summarizes the purchase price and the estimated values of assets acquired and liabilities assumed:

Purchase price (in thousands):
Cash	$	90,352
Total consideration given	$	90,352
Fair value allocation of purchase price:
Oil and natural gas properties:
Proved properties	$	71,044
Unproved properties		20,262
Total oil and natural gas properties		91,306
Accounts payable		(469)
Asset retirement obligations assumed		(485)
Fair value of net assets acquired	$	90,352

Pro Forma Financial Information.  The following unaudited pro forma financial information represents the combined results for the Company and the properties acquired from Kodiak, in August of 2013, and Marathon, in June of 2014, as if the acquisitions had occurred on February 1, 2012. 

	For the Years Ended January 31,
(in thousands, except per share data)	2015		2014		2013
Operating revenues	$	584,696	$	312,081	$	92,933
Net income (loss)	$	96,438	$	91,579	$	(2,407)
Earnings (loss) per common share
Basic	$	1.15	$	1.22	$	(0.04)
Diluted	$	1.00	$	1.04	$	(0.04)
Weighted average common shares outstanding:
Basic		83,611		75,047		55,794
Diluted		101,032		91,026		55,794

For purposes of the pro forma information it was assumed that the net proceeds generated from the issuance of the Company’s common stock were utilized to fund the August 28, 2013 acquisition and that such issuance occurred on February 1, 2012.  The pro forma information includes the effects of adjustments for depreciation, amortization and accretion expense of $3.4 million, $16.5 million and $12.6 million for fiscal years 2015, 2014 and 2013, respectively.  The pro forma results do not include any cost savings that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired.  The pro forma results are not necessarily indicative of what actually would have occurred if the transactions had been completed, or the common stock had been issued, as of the beginning of the period, nor are they necessarily indicative of future results.

Acquisition of Team Well Service, Inc.In October 2013, RockPile completed its acquisition of Team Well Service, Inc. (“Team Well”), an operator of well service rigs in North Dakota, in exchange for (i) $6.8 million in cash; (ii) unsecured seller notes of $0.8 million; and, (iii) contingent consideration of $1.5 million.  The final purchase price allocation resulted in identifiable intangible assets and goodwill of approximately $3.9 million and $1.7 million, respectively.  Transaction and other costs associated with the acquisition of net assets are expensed as incurred.  Pro forma information has not been provided for the Team Well acquisition as the impact is immaterial to our consolidated financial statements.

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Asset Retirement Obligations

12 Months Ended

Jan. 31, 2015

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

8.  ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations (“ARO”) represent the estimated present value of the amounts expected to be incurred to plug, abandon, and remediate producing and shut-in properties at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its ARO when incurred by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.

The following tables reflect the change in ARO for the years ended January 31, 2015 and 2014:

	For the Years Ended January 31,
(in thousands)	2015		2014
Balance at the beginning of the period	$	4,629	$	3,422
Liabilities incurred		1,821		944
Revision of estimates		2,737		774
Sale of assets		(29)		(83)
Liabilities settled		(747)		(484)
Accretion		167		56
Balance at the end of the period		8,578		4,629
Less current portion of obligations		(5,391)		(3,333)
Long-term ARO	$	3,187	$	1,296

The current portion of ARO is classified with other accrued liabilities and the long-term ARO is classified in other long-term liabilities in the accompanying consolidated balance sheets.

A significant portion of the current obligations relates to the reclamation of man-made ponds holding produced formation water and the plugging and abandonment of well bores in the Maritimes Basin of Canada of $4.8 million and $2.0 million as of January 31, 2015 and January 31, 2014, respectively.  Internal engineering re-assessment of Canadian ARO resulted in revisions $2.7 million and $1.0 million to the ARO during fiscal years 2015 and 2014.  Since our Canadian oil and natural gas properties were fully impaired, the ARO revisions were expensed and included in depreciation and amortization expenses in the accompanying consolidated statements of operations for the years ended January 31, 2015 and 2014, respectively.

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Capital Stock

12 Months Ended

Jan. 31, 2015

Share-Based Compensation [Abstract]

Capital Stock

10.  CAPITAL STOCK

The Company had 106.4 million shares of common stock issued or reserved for issuance at January 31, 2015. At January 31, 2015, the Company had 75.2 million shares of common stock issued and outstanding.  The Company also had 3.6 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2011 Omnibus Incentive Plan and its 2014 Equity Incentive Plan (the “2014 Plan”).  The Company also had 4.6 million shares of common stock reserved that remained available for issuance under the 2014 Plan, as well as 6.0 million shares of common stock reserved for issuance under the CEO Stand-Alone Stock Option Agreement.  Lastly, the Company had 17.0 million shares of common stock reserved for issuance pursuant to the Convertible Note at January 31, 2015.

The Company’s Board of Directors (the “Board”) approved a program authorizing the repurchase of outstanding shares of the Company’s common stock in amounts equal to the aggregate of (i) $25.0 million of the Company’s common stock (“Tranche 1”), (ii) up to the number of shares of common stock authorized for issuance under the Company’s 2014 Equity Incentive Plan and its CEO Stand-Alone Stock Option Agreement (“Tranche 2”), and (iii) up to the number of shares potentially issuable, at any given time, pursuant to the paid-in-kind interest accrued on the Convertible Note (“Tranche 3”). The program stipulates that shares of common stock may be repurchased from time to time, in amounts and at prices that the Company deems appropriate, subject to market and business conditions and other considerations. The repurchase program has no expiration date and may be suspended or discontinued at any time without prior notice. During fiscal year 2015, the Company repurchased an aggregate of 11.4 million shares of the Company’s common stock under the program at a total cost of $76.8 million.  The repurchased shares of common stock were immediately retired and charged to available retained earnings with the balance charged to additional paid-in capital.  As of January 31, 2015, the number of shares of common stock remaining available for repurchase under the Board approved program is 4,949,393 shares.

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Asset Retirement Obligations (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Asset Retirement Obligations [Line Items]
Accretion of asset retirement obligations	$ 167	$ 56	$ 184
Asset retirement obligations, current	5,391	3,333
Reclamation Of Man Made Ponds And Plugging And Abandonment Of Well Bores and Plug And Abandon Vertical Wells [Member]
Asset Retirement Obligations [Line Items]
Asset retirement obligations, current	4,800	2,000
Canada [Member] | Internal Engineering Re-assessment [Member]
Asset Retirement Obligations [Line Items]
Accretion of asset retirement obligations	$ 2,700	$ 1,000

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Related Party Transactions (Details) (USD $)	3 Months Ended								12 Months Ended
	Jan. 31, 2015 item	Oct. 31, 2014	Jul. 31, 2014	Apr. 30, 2014	Jan. 31, 2014	Oct. 31, 2013	Jul. 31, 2013	Apr. 30, 2013	Jan. 31, 2015 item	Jan. 31, 2014	Jan. 31, 2013
Related Party Transaction [Line Items]
Revenues	$ 156,988,000	$ 174,196,000	$ 141,989,000	$ 99,782,000	$ 85,510,000	$ 88,549,000	$ 50,394,000	$ 34,294,000	$ 572,955,000	$ 258,747,000	$ 60,361,000
Number of salt water disposal wells	1								1
Proceeds from sale of salt water disposal wells									1,500,000		3,265,000
TUSA [Member]
Related Party Transaction [Line Items]
Revenues									36,600,000	15,000,000
Caliber North Dakota LLC [Member]
Related Party Transaction [Line Items]
Term of midstream agreements with Caliber									15 years
Minmum commitment over term of agreements	405,000,000								405,000,000
Remaining commitment	359,200,000								359,200,000
Revenues									43,000,000	15,600,000
Proceeds from sale of salt water disposal wells									1,500,000
Reimbursed administrative services from Caliber									$ 900,000

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Equity Investment And Equity Investment Derivatives (Details 2) (Caliber Midstream Partners, L.P. [Member], USD $)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014
Class A Units [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Class AUnits Held	7,000,000	3,000,000
Class A Triggering Units [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Class AUnits Held		4,000,000
Class A Trigger Unit Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Class AUnits Held		1,600,000
Series 1 Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Warrant expiration date	Oct. 01, 2024
Equity method investments, warrant excercise price	$ 12.78
Equity Method Investment, Class AUnits Held	5,600,000	4,000,000
Series 2 Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Warrant expiration date	Oct. 01, 2024
Equity method investments, warrant excercise price	$ 22.09
Equity Method Investment, Class AUnits Held	2,400,000	2,400,000
Series 3 Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Warrant expiration date	Sep. 12, 2025
Equity method investments, warrant excercise price	$ 22.09
Equity Method Investment, Class AUnits Held	3,000,000	3,000,000
Series 4 Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Warrant expiration date	Sep. 12, 2025
Equity method investments, warrant excercise price	$ 28.09
Equity Method Investment, Class AUnits Held	2,000,000	2,000,000

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Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014
Asset Retirement Obligations [Abstract]
Balance, beginning of period	$ 4,629	$ 3,422
Liabilities incurred	1,821	944
Revision of estimates	2,737	774
Sales of assets	(29)	(83)
Liabilities settled	(747)	(484)
Accretion	167	56
Balance, end of period	8,578	4,629
Less current portion of obligations	(5,391)	(3,333)
Long-term asset retirement obligations	$ 3,187	$ 1,296

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Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 3)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract]
Oil price per barrel	79.71	93.09	84.76
Natural gas price per Mcf	6.09	3.99	5.23
Natural gas liquids price per barrel	34.61	44.10

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Share-Based Compensation (Tables)

12 Months Ended

Jan. 31, 2015

Share-Based Compensation [Abstract]

Non-Cash Stock-Based Compensation Cost

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Restricted stock units	$	6,254	$	7,496	$	6,639
Stock options		2,299		1,135		60
Stock issued pursuant to termination agreements		—		—		99
RockPile Series B Units		509		590		617
		9,062		9,221		7,415
Less amounts capitalized to oil and natural gas properties		(1,143)		(1,391)		(949)
Compensation expense	$	7,919	$	7,830	$	6,466

Restricted Stock Units Outstanding

		Weighted-
	Number of	Average Award
	Shares	Date Fair Value
Restricted stock units outstanding - January 31, 2012	2,488,342	$	7.02
Units granted	1,041,400	$	6.37
Units forfeited	(5,600)	$	7.59
Units vested	(1,000,057)	$	6.90
Restricted stock units outstanding - January 31, 2013	2,524,085	$	6.68
Units granted	1,440,133	$	6.95
Units forfeited	(141,909)	$	6.58
Units vested	(946,681)	$	6.71
Restricted stock units outstanding - January 31, 2014	2,875,628	$	6.62
Units granted	1,523,700	$	9.42
Units forfeited	(394,921)	$	7.21
Units vested	(1,090,362)	$	7.04
Restricted stock units outstanding - January 31, 2015	2,914,045	$	7.92

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

		Weighted
	Numberof	Average
	Shares	ExercisePrice
Options outstanding - January 31, 2012 (142,500 exercisable)	235,833	$	1.50
Options exercised	(4,167)	$	3.00
Options outstanding - January 31, 2013 (231,666 exercisable)	231,666	$	1.48
Options forfeited	(15,000)	$	3.00
Options exercised	(108,333)	$	1.25
Options granted	6,000,000	$	11.25
Options outstanding - January 31, 2014 (108,333 exercisable)	6,108,333	$	11.07
Options forfeited	—	$	—
Options exercised	(108,333)	$	1.25
Options granted	700,000	$	14.00
Options outstanding - January 31, 2015 (600,000 exercisable)	6,700,000	$	11.54

Option Grant Plan Fair Value Assumptions

The following assumptions were used for the Black-Scholes model to calculate the share-based compensation expense for the options granted in fiscal year 2015:

Risk free rate	1.06	%
Dividend yield	—
Expected volatility	54	%
Weighted average expected stock option life (years)	3.0

Stock Options Outstanding By Exercise Price

The following table presents additional information related to the stock options outstanding at January 31, 2015:

		Remaining
Exercise Price		Contractual Life	Number of Shares
per Share		(years)	Outstanding		Exercisable
$	7.50	8.43		750,000		75,000
$	8.50	8.43		750,000		75,000
$	10.00	8.43		1,500,000		150,000
$	12.00	8.43		1,500,000		150,000
$	15.00	8.43		1,500,000		150,000
$	12.00	6.61		233,333		—
$	14.00	6.61		233,333		—
$	16.00	9.61		233,334		—
				6,700,000		600,000
Weighted average exercise price per share			$	11.54	$	11.25
Weighted average remaining contractual life				8.34		8.43

Summary Of Series B Unit Activity

	Series	Series	Series	Series
	B-1units	B-2 units	B-3 units	B-4 units	Total
Units outstanding - January 31, 2012	—	—	—	—	—
Units granted	3,100,000	60,000	—	—	3,160,000
Units outstanding - January 31, 2013	3,100,000	60,000	—	—	3,160,000
Units granted	—	—	910,000	—	910,000
Units outstanding - January 31, 2014	3,100,000	60,000	910,000	—	4,070,000
Units redeemed	(180,000)	—	—	—	(180,000)
Units granted	—	—	—	1,412,000	1,412,000
Units outstanding - January 31, 2015	2,920,000	60,000	910,000	1,412,000	5,302,000
Vested	2,920,000	30,000	188,000	—	3,138,000
Unvested	—	30,000	722,000	1,412,000	2,164,000

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Long-term Debt (Details 4) (USD $)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Mar. 25, 2014	Nov. 13, 2014	Nov. 12, 2014
Debt Instrument [Line Items]
Credit facility	224,159,000	$ 204,515,000
Rockpile [Member]
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity			100,000,000
Credit facility	104,887,000	21,515,000
Rockpile [Member] | Federal Funds Rate [Member]
Debt Instrument [Line Items]
Credit facility, basis spread on interest rate	0.50%
Rockpile [Member] | Eurodollar Rate Plus 1% [Member]
Debt Instrument [Line Items]
Credit facility, basis spread on interest rate	1.00%
Rockpile [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Credit facility, fronting fee percentage	0.125%
Rockpile [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity				$ 150,000,000	$ 100,000,000
Maximum [Member] | Rockpile [Member]
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Maximum [Member] | Rockpile [Member] | Eurodollar Rate Plus 1% [Member]
Debt Instrument [Line Items]
Credit facility, margin on dollar amount based on usage	2.25%
Maximum [Member] | Rockpile [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Credit facility, margin on dollar amount based on usage	3.25%
Minimum [Member] | Rockpile [Member]
Debt Instrument [Line Items]
Commitment fee percentage	0.375%
Minimum [Member] | Rockpile [Member] | Eurodollar Rate Plus 1% [Member]
Debt Instrument [Line Items]
Credit facility, margin on dollar amount based on usage	1.50%
Minimum [Member] | Rockpile [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Credit facility, margin on dollar amount based on usage	2.50%

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Commitments And Contingencies

12 Months Ended

Jan. 31, 2015

Commitments And Contingencies [Abstract]

Commitments And Contingencies

15.  COMMITMENTS AND CONTINGENCIES

Triangle has entered into non-cancelable operating leases for office facilities and Rockpile has entered into various non-cancelable operating leases relating to (i) equipment for transportation, transloading and storage bulk commodities and light vehicles, (ii) transloading services and track rental and (iii) transportation equipment management, logistics and maintenance.  Rent expense incurred under the non-cancelable operating leases was $1.8 million, $0.8 million, and $0.5 million for the fiscal years ended January 31, 2015, 2014, and 2013, respectively.

As of January 31, 2015, the future minimum lease payments under operating leases that have initial or remaining non-cancelable terms in excess of one year are:

Fiscal Years Ending January 31,	Annual Rental Amount (in thousands)
2016	$	2,807
2017	$	2,749
2018	$	2,357
2019	$	2,108
2020 and thereafter	$	2,686

As of January 31, 2015 the Company was subject to commitments on four drilling rig contracts.  Two of the drilling rig contracts expire in first quarter of fiscal year 2016, and the remaining contracts expire in the second and fourth quarters of fiscal year 2016.  In the event of early termination of the contracts, the Company would be obligated to pay an aggregate amount of approximately $10.2 million as of January 31, 2015 as required under the terms of the contracts. 

CEO Transaction Bonus ProgramPursuant to the Third Amended and Restated Employment Agreement, dated July 4, 2014 (the “Employment Agreement”), between the Company and Jonathan Samuels, our President and Chief Executive Officer, Mr. Samuels is entitled to a cash bonus payable upon a liquidity event involving RockPile or Caliber based on the percentage gain realized by the Company relative to its initial investment in the relevant entity (“Transaction Bonus”). The amount of this Transaction Bonus would be equivalent to 5% of that gain in Caliber for a Caliber liquidity event, and 3.5% of that gain in RockPile for a RockPile liquidity event. The right to the Transaction Bonus vests and becomes non-forfeitable in thirds on the first three anniversaries of the execution date of the Employment Agreement, with acceleration or forfeiture of the unvested portions of such right upon the occurrence of certain events. 

On January 31, 2015, Triangle and Mr. Samuels entered into a First Amendment to Third Amended and Restated Employment Agreement (the “First Amendment”) that modified the Employment Agreement to permit Triangle’s Board to authorize distributions to Mr. Samuels pursuant to his Transaction Bonus program in advance of defined liquidity events.  Any Board authorized distribution to Mr. Samuels related to the Transaction Bonus program would reduce any future award payable to Mr. Samuels following a liquidity event.  There are no clawback provisions in the First Amendment that would require Mr. Samuels to repay Triangle for any excess distributions or payments received.

In connection with the First Amendment, the Board authorized the payment of a Transaction Bonus to Mr. Samuels of $1.9 million which has been recorded as a liability as of January 31, 2015.  The payment of the Board authorized distribution will occur on the earlier of December 31, 2015 or when the WTI (NYMEX) price of oil exceeds $65 for 5 days over a consecutive 30 day period, subject to Mr. Samuel’s continuous employment with the Company through the applicable distribution date.  Because consummation of a liquidity event involving RockPile or Caliber is contingent on many unknown factors, the Company has determined that the contingent liability associated with such a bonus is not probable at January 31, 2015, and, therefore, no amounts have been recorded in the accompanying consolidated balance sheets other than the Board authorized distribution.

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Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Jan. 31, 2015

Summary Of Significant Accounting Policies [Abstract]

Schedule of accounts receivable

The components of accounts receivable include the following (in thousands):

	For the Years Ended January 31,
		2015		2014
Oil and natural gas sales	$	21,445	$	25,866
Joint interest billings		72,235		43,660
Oilfield services revenue		59,408		29,109
Other		11,350		7,828
Total accounts receivable	$	164,438	$	106,463

Schedules of Concentration of Risk, by Risk Factor [Table Text Block]

	Fiscal Years Ended January 31,
	2015		2014		2013
Oil & Gas Customer A		13%		22%		N/A
Oil & Gas Customer B		12%		15%		N/A
Oil & Gas Customer C		12%		N/A		N/A
Oilfield Services Customer A		15%		N/A		N/A
Oilfield Services Customer B		12%		13%		N/A

Schedule of Oilfield services equipment and other property and equipment

	For the Years Ended January 31,
(in thousands)	2015		2014
Land	$	7,888	$	2,512
Building and leasehold improvements		33,625		18,388
Oilfield service equipment		116,354		56,355
Vehicles		4,811		2,288
Software, computers and office equipment		5,327		3,016
Capital leases		853		—
Total depreciable assets		168,858		82,559
Accumulated depreciation		(35,189)		(12,800)
Depreciable assets, net		133,669		69,759
Assets not placed in service		1,247		1,333
Total oilfield service equipment and other property & equipment, net	$	134,916	$	71,092

Schedule of weighted average dilutive and anti-dilutive securities

The following table details the weighted average dilutive and anti-dilutive securities, which consist of options and unvested restricted stock, for the periods presented (in thousands):

	For the Years Ended January 31,
	2015		2014		2013
Dilutive		17,421		15,979		—
Anti-dilutive shares		6,905		5,250		4,500

Schedule of computations of net income(loss) per common share (basic and diluted)

	For the Years Ended January 31,
(in thousands, except per share data)	2015		2014		2013
Net income (loss) attributable to common stockholders	$	93,397	$	73,480	$	(13,760)
Effect of 5% convertible note conversion		4,135		3,392		—
Net income (loss) attributable to common stockholders after effect of debt conversion	$	97,532	$	76,872	$	(13,760)
Basic weighted average common shares outstanding		83,611		68,579		44,475
Effect of dilutive securities		17,421		15,979		—
Diluted weighted average common shares outstanding		101,032		84,558		44,475
Basic net income (loss) per share	$	1.12	$	1.07	$	(0.31)
Diluted net income (loss) per share	$	0.97	$	0.91	$	(0.31)

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Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 6) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Unaudited Supplemental Oil And Natural Gas Disclosures [Abstract]
Future cash inflows	$ 4,219,155	$ 3,252,079	$ 1,128,676
Future costs:
Production	(1,586,288)	(1,118,508)	(333,185)
Development	(439,749)	(505,432)	(199,173)
Future income tax expense	(394,538)	(364,340)	(87,313)
Future net cash flows	1,798,580	1,263,799	509,005
10% discount factor	(977,088)	(690,564)	(297,653)
Standardized measure of discounted future net cash flows relating to proved reserves	$ 821,492	$ 573,235	$ 211,352

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Long-Term Debt (Details 2) (USD $)	Jan. 31, 2015	Jan. 31, 2014
Debt Instrument [Line Items]
Accrued interest	$ 2,250,000	$ 268,000
Convertible Notes [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	5.00%	5.00%
Debt instrument, face amount	120,000,000
Convertible note, conversion price	$ 8.00
Accrued interest	$ 15,900,000

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Description Of Business (Details)	12 Months Ended
	Jan. 31, 2015 item
Description Of Business [Abstract]
Number of major focus lines of business	3

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 93,397	$ 73,480	$ (14,484)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	124,055	58,011	15,081
Share-based compensation	7,919	7,830	6,637
Interest expense not paid in cash	6,587	6,267	3,023
Amortization of deferred loan costs	3,149	554	146
Gain on extinguishment of debt	(6,610)
Accretion of asset retirement obligations	167	56	184
Commodity derivatives (gains) losses	(64,050)	(1,082)	3,570
Settlements on commodity derivative instruments	11,422	(4,643)
Equity investment income (loss)	(81)		283
Gain on equity investment derivatives	(553)	(39,785)
Gain on securities held for investment		(1,040)	(204)
Deferred income taxes	45,500	7,941
Changes in related current assets and current liabilities:
Accounts receivable	(65,448)	(65,929)	(30,295)
Other current assets	(9,926)	(3,579)	(2,694)
Accounts payable and accrued liabilities	57,233	44,840	21,762
Asset retirement expenditures	(2,206)	(484)	(253)
Other	262	(1)	8
Cash provided by operating activities	200,817	82,436	2,764
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas expenditures	(359,102)	(279,531)	(114,625)
Acquisitions of oil and natural gas properties	(138,778)	(121,578)	(21,193)
Purchase of oil field services equipment	(59,624)	(27,414)	(16,535)
Purchase of other property and equipment	(26,739)	(10,928)	(14,684)
Sale of oil and natural gas properties	1,500		3,265
Acquisition of oilfield services companies		(7,715)
Equity investment in Caliber Midstream Partners, L.P.		(18,000)	(12,001)
Purchase of equity investment derivative contracts			(3,889)
Equity investment cash distribution	6,080	3,150
Sale of marketable securities		6,105
Other	(356)	345	(50)
Cash used in investing activities	(577,019)	(455,566)	(179,712)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities	504,159	211,820	41,700
Repayments of credit facilities	(484,515)	(32,306)	(16,700)
Proceeds from notes payable	450,527	14,430	120,000
Repayments of other notes and mortgages payable	(416)	(5,876)
Early extinguishment of repurchased debt	(13,890)
Debt issuance costs	(13,980)	(2,670)	(1,270)
Proceeds from issuance of common stock		245,369
Stock offering costs		(7,072)
Payments to settle tax on vested restricted stock units	(2,854)	(2,058)	(1,884)
Issuance of common stock on exercise of options	135	162	13
Common stock repurchased and retired	(76,843)
Purchase of minority interest In RockPile			(609)
Other		(36)
Cash provided by financing activities	362,323	421,763	141,250
NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS	(13,879)	48,633	(35,698)
CASH AND EQUIVALENTS, BEGINNING OF PERIOD	81,750	33,117	68,815
CASH AND EQUIVALENTS, END OF PERIOD	$ 67,871	$ 81,750	$ 33,117

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Supplemental Disclosures Of Cash Flow Information (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Supplemental Disclosures of Cash Flow Information [Abstract]
Interest expense	$ 19,713	$ 1,419	$ 75
Income taxes	600
Increased accounts payable and accrued liabilities	47,838	30,785	36,654
Issuance of common stock		2,438	1,204
Capitalized stock-based compensation	1,143	1,391	949
Change in asset retirement obligations	1,818	673	1,869
Capitalized interest	4,899	809
Acquisition of oilfield services equipment through notes payable and liabilities		1,990
Purchase minority interest in Rockpile			12,349
Notes payable issued for redemption of RockPile B units	$ 1,041

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Long-Term Debt

12 Months Ended

Jan. 31, 2015

Long-Term Debt [Abstract]

Long-term Debt

4.  LONG-TERM DEBT

As of January 31, 2015 and 2014, respectively, the Company’s long-term debt consisted of the following:

	For the Years Ended January 31,
	2015		2014
5% convertible note	$	135,877	$	129,290
TUSA credit facility due October 2018		119,272		183,000
RockPile credit facility due March 2019		104,887		21,515
TUSA 6.75% notes due July 2022		429,500		—
Other notes and mortgages payable		10,605		9,403
Total debt		800,141		343,208
Less current portion of debt:
RockPile credit facility		—		(8,450)
Other notes and mortgages payable		(503)		(401)
Total long-term debt	$	799,638	$	334,357

Convertible Note.On July 31, 2012, the Company sold to NGP Triangle Holdings, LLC a 5% convertible note with an initial principal amount of $120.0million (the “Convertible Note”) that became convertible after November 16, 2012 into the Company’s common stock at a conversion rate of one share per $8.00 of note principal.

The Convertible Note accrues interest at a rate of 5.0% per annum, compounded quarterly, 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 is paid-in-kind by adding to the principal balance of the Convertible Note, provided that, after October 31, 2017, the Company has the option to make such interest payments in cash.  As of January 31, 2015, $15.9 million of accrued interest has been added to the principal balance of the Convertible Note.

TUSA Credit Facility.  On April 11, 2013, TUSA entered into an Amended and Restated Credit Agreement, which was subsequently amended on various dates.  On November 25, 2014, TUSA entered into a Second Amended and Restated Credit Agreement, which provides for a $1.0 billion senior secured revolving credit facility, with a sublimit for the issuance of letters of credit equal to $15.0 million.  As of November 25, 2014, the borrowing base was set by the lenders at $435.0million. The TUSA credit facility has a maturity date of October 16, 2018.

Borrowings under the TUSA 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 0.50%, or (C) the one month eurodollar rate (as defined in the agreement) plus 1%), plus an applicable margin that ranges between 0.50% and 1.50%, depending on TUSA’s utilization percentage of the then effective borrowing base, or (ii) the eurodollar rate plus an applicable margin that ranges between 1.50% and 2.50%, depending on TUSA’s utilization percentage of the then effective borrowing base.

The lenders will redetermine the borrowing base under the TUSA credit facility on a semi-annual basis by the beginning of each May 1st and November 1st.  In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year.  If at any time the borrowing base is less than the amount of outstanding credit exposure under the TUSA credit facility, TUSA will be required to (i) prepay the principal amount of the loans in an amount sufficient to eliminate the excess, (ii) pledge additional collateral, (iii) prepay the excess in three equal monthly installments, or (iv) any combination of options (i) through (iii).  TUSA will pay a per annum fee on all letters of credit issued under the TUSA credit facility, which fee will equal the applicable margin for loans accruing interest based on the eurodollar rate and a fronting fee to the issuing lender equal to the greater of 0.125% of the letter of credit amount and $500 per letter of credit. TUSA will pay a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the TUSA credit facility. The TUSA credit facility is collateralized by certain of TUSA’s assets, including (1) at least 80% of the adjusted engineered value of TUSA’s oil and natural gas interests evaluated in determining the borrowing base for the facility, and (2) all of the personal property of TUSA and its subsidiaries.  The obligations under the TUSA credit facility are guaranteed by TUSA’s domestic subsidiaries, but Triangle is not a guarantor.

The TUSA credit facility contains various covenants and restrictive provisions that may, among other things, limit TUSA’s ability to sell assets, incur additional indebtedness, pay dividends, make investments or loans and create liens.  In addition, the facility contains financial covenants requiring TUSA to maintain specified ratios of consolidated current assets to consolidated current liabilities and consolidated debt to consolidated EBITDAX.  As of January 31, 2015, TUSA was in compliance with all covenants under the TUSA credit facility.

RockPile Credit Facility.  On March 25, 2014, RockPile entered into a Credit Agreement to provide a $100.0 million senior secured revolving credit facility.  On November 13, 2014, RockPile entered into Amendment No. 1 to Credit Agreement and Incremental Commitment Agreement, which amended the credit facility to increase the borrowing capacity under the facility from $100.0 million to $150.0 million.  The RockPile credit facility has a maturity date of March 25, 2019.

Borrowings under the RockPile credit facility bear interest, at RockPile’s option, at either (i) the alternative base rate (the highest of (a) the administrative agent’s prime rate, (b) the federal funds rate plus 0.5%, or (c) the one-month adjusted Eurodollar rate (as defined in the agreement) plus 1.0%), plus an applicable margin that ranges between 1.5% and 2.25%, depending on RockPile’s leverage ratio as of the last day of RockPile’s most recently completed fiscal quarter, or (ii) the Eurodollar rate plus an applicable margin that ranges between 2.50% and 3.25%, depending on RockPile’s leverage ratio as of the last day of RockPile’s most recently completed fiscal quarter.

RockPile will pay a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the RockPile credit facility.  RockPile will also pay a per annum fee on all letters of credit issued under the RockPile credit facility, which will equal the applicable margin for loans accruing interest based on the Eurodollar rate and a fronting fee to the issuing lender equal to 0.125% of the letter of credit amount.  Triangle is not a guarantor under the RockPile credit facility. 

The RockPile credit facility contains financial covenants requiring RockPile to maintain specified ratios of consolidated debt to EBITDA and Adjusted EBITDA to Fixed Charges.  Amendment No. 1 also modified covenants in the RockPile credit facility related to certain restrictions on the payment of dividends and distributions and increased the amount of permitted capital expenditures.  As of January 31, 2015, RockPile was in compliance with all financial covenants under the RockPile credit facility.

TUSA 6.75% Notes.  On July 18, 2014, TUSA entered into an Indenture (the “Indenture”) among TUSA, a TUSA wholly-owned subsidiary as guarantor, and Wells Fargo Bank, National Association, as trustee, governing the terms of TUSA’s $450.0 million aggregate principal amount of TUSA 6.75%Notes due 2022 (the ”TUSA 6.75% Notes”).

The TUSA 6.75% Notes were issued in a private offering exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), to qualified institutional buyers in accordance with Rule 144A and to persons outside of the United States pursuant to Regulation S under the Securities Act.  The TUSA 6.75% Notes are senior unsecured obligations of TUSA and are guaranteed on a senior unsecured basis by the initial guarantor and another TUSA wholly-owned subsidiary that became a guarantor of the TUSA 6.75% Notes in early December 2014.  The TUSA 6.75% Notes have not been registered under the Securities Act and may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements.

The TUSA 6.75% Notes bear interest at a rate of 6.75% per year, accruing from July 18, 2014.  Interest on the TUSA 6.75% Notes is payable semiannually in arrears on January 15 and July 15 of each year, beginning on January 15, 2015.  The TUSA 6.75% Notes will mature on July 15, 2022, subject to earlier repurchase or redemption in accordance with the terms of the Indenture.  The Company incurred $10.5 million of offering costs which have been deferred and are being recognized on the effective interest method over the life of the notes.

TUSA may redeem some or all of the TUSA 6.75% Notes at any time prior to July 15, 2017 at a price equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest, if any, to the redemption date and a make-whole premium set forth in the Indenture.  On or after July 15, 2017, TUSA may redeem some or all of the TUSA 6.75% Notes at any time at redemption prices set forth in the Indenture, plus accrued and unpaid interest, if any, to the redemption date.  In addition, at any time prior to July 15, 2017, TUSA may redeem up to 35% of the aggregate principal amount of the TUSA 6.75% Notes at a specified redemption price set forth in the Indenture plus accrued and unpaid interest, if any, to the redemption date, with the net cash proceeds of certain equity offerings.  If TUSA experiences certain change of control events, TUSA must offer to repurchase the TUSA 6.75% Notes at 101% of their principal amount, plus accrued and unpaid interest, if any, to the redemption date.

The Indenture permits TUSA to purchase TUSA 6.75% Notes in the open market.  In fiscal year 2015, TUSA repurchased TUSA 6.75% Notes with a face value of $20.5 million for $13.9 million.  TUSA immediately retired the repurchased notes and recognized a gain on extinguishment of debt of $6.6million.

The Indenture contains covenants that, among other things, restrict TUSA’s ability and the ability of any guarantor subsidiary to sell certain assets; make certain dividends, distributions, investments and other restricted payments; incur certain additional indebtedness and issue preferred stock; create certain liens; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries, and consolidate, merge or sell substantially all of TUSA’s assets.  These covenants are subject to a number of important exceptions and qualifications.  As of January 31, 2015, TUSA was in compliance with all covenants under the TUSA 6.75% Notes.

Second Lien Credit Facility.  On June 27, 2014, TUSA entered into a Second Lien Credit Agreement, which provided for a $60.0 million second priority secured credit facility, which was funded at signing. All borrowings under the second lien credit facility were scheduled to mature on October 16, 2019 (nine months after the maturity of the TUSA credit facility).  Borrowings under the second lien credit facility bore interest, at our option, at either (i) LIBOR (subject to a floor) plus a margin of 7.0% or (ii) a base rate (subject to a floor) plus a margin of 6.0%.  The second lien credit facility also provided that no prepayment fees would be payable for prepayments made during the first twelve months.

Upon issuance of the TUSA 6.75% Notes on July 18, 2014, TUSA terminated the second lien credit facility and repaid all amounts owing thereunder.

Future Maturities of Outstanding Debt.Scheduled annual maturities of long-term debt outstanding as of January 31, 2015 were as follows:

For the Years Ending January 31, (in thousands):
2016	$	503
2017		1,450
2018		1,594
2019		119,852
2020		105,565
Thereafter		571,177
	$	800,141

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Oil And Natural Gas Properties (Details 2) (USD $)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Issuance of common stock for oil and gas properties		$ 2,400,000	$ 1,200,000
Capitalized internal land and geology department costs	4,800,000	3,700,000	2,000,000
Costs not being amortized	142,896,000
Duration for Unproved property costs to be reclassified to proved property costs	5 years
Depreciation and amortization expense for oil and gas properties	106,900,000	51,000,000	13,500,000
Oil and Gas Properties [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Total consideration to purchase oil and gas properties	545,700,000	434,400,000	168,400,000
Unproved Leaseholds [Member] | Oil and Gas Properties [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Total consideration to purchase oil and gas properties	138,800,000	121,600,000	21,200,000
Unevaluated Wells In Progress [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Costs not being amortized	$ 17,100,000

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Income Taxes (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Income Taxes [Abstract]
Deferred income tax expense (benefit), Federal	$ 42,400	$ 7,324	$ (2,137)
Deferred income tax expense (benefit), State	3,100	617	(223)
Deferred income tax expense (benefit), Foreign			(83)
Valuation allowance - United States and Canada	(7,464)	(26,364)	2,443
Income tax expense (benefit)	45,500	7,941
Income (loss) before income taxes	$ 138,897	$ 81,421	$ (14,484)
Effective income tax rate	33.00%	10.00%	0.00%

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Equity Investment And Equity Investment Derivatives (Details 5) (USD $)	12 Months Ended		0 Months Ended		1 Months Ended	3 Months Ended	0 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Feb. 02, 2015	Jan. 31, 2015	Oct. 31, 2012	Apr. 30, 2015	Sep. 12, 2013
Schedule of Equity Method Investments [Line Items]
Gain (loss) on equity investment derivative	$ 553,000	$ 39,785,000
Class A Triggering Units [Member]
Schedule of Equity Method Investments [Line Items]
Gain (loss) on equity investment derivative	1,700,000
Series 1, Series 2, Series 3 and Series 4 Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, warrants received			2,357,334
Caliber Midstream Partners, L.P. [Member]
Schedule of Equity Method Investments [Line Items]
Contributed capital		18,000,000
Caliber Midstream Partners, L.P. [Member] | Triangle Caliber Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Contributed capital				0
Equity method investments, Class A Units received					3,000,000
Equity method investment, Class A units held			7,000,000
Equity method investments, warrants received				3,626,667
Caliber Midstream Partners, L.P. [Member] | FREIF Caliber Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Contributed capital				34,000,000
Equity method investments, Class A Units received				2,720,000	7,000,000
Equity method investment, Class A units held			17,720,000
Equity method investments, warrants received				906,667
Caliber Midstream Partners, L.P. [Member] | Forecast [Member]
Schedule of Equity Method Investments [Line Items]
Gain (loss) on equity investment derivative						4,200,000
Gain (loss) on equity investment derivative, related to warrants						$ 200,000
Caliber Midstream Partners, L.P. [Member] | Forecast [Member] | Triangle Caliber Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, Class A Units received							4,000,000
Equity method investment, Class A units held	7,000,000			7,000,000
Equity method ownership percentage	32.00%			32.00%
Caliber Midstream Partners, L.P. [Member] | Forecast [Member] | FREIF Caliber Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, Class A Units received							8,000,000
Equity method investment, Class A units held	15,000,000			15,000,000
Equity method ownership percentage	68.00%			68.00%
Caliber Midstream Partners, L.P. [Member] | Class A Triggering Units [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, Class A units held		4,000,000
Caliber Midstream Partners, L.P. [Member] | Class A Triggering Units [Member] | Triangle Caliber Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage			28.30%
Caliber Midstream Partners, L.P. [Member] | Class A Triggering Units [Member] | FREIF Caliber Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage			71.70%
Caliber Midstream Partners, L.P. [Member] | Class A Trigger Unit Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investment, Class A units held		1,600,000
Caliber Midstream Partners, L.P. [Member] | Series 6 Warrants [Member] | Triangle Caliber Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, warrants received			1,269,333
Equity method investments, warrant excercise price			12.50

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Segment Reporting (Tables)

12 Months Ended

Jan. 31, 2015

Segment Reporting [Abstract]

Schedule Of Segment Reporting

	For the Year Ended January 31, 2015
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	284,502	$	—	$	—	$	—	$	284,502
Oilfield services for third parties		—		294,526		—		(6,073)		288,453
Intersegment revenues		—		123,577		—		(123,577)		—
Total revenues		284,502		418,103		—		(129,650)		572,955
Expenses:
Lease operating and production taxes		55,477		—		—		—		55,477
Gathering, transportation and processing		18,520		—		—		—		18,520
Depreciation and amortization		116,633		22,008		921		(15,507)		124,055
Accretion of asset retirement obligations		167		—		—		—		167
Cost of oilfield services		—		301,142		308		(84,854)		216,596
General and administrative, net of amounts capitalized:
Salaries and benefits		6,028		14,620		11,559		—		32,207
Stock-based compensation		1,155		509		6,255		—		7,919
Other general and administrative		9,042		10,598		2,991		—		22,631
Total operating expenses		207,022		348,877		22,034		(100,361)		477,572
Income (loss) from operations		77,480		69,226		(22,034)		(29,289)		95,383
Other income (expense), net		51,216		(3,024)		(2,356)		(2,322)		43,514
Net income (loss) before income taxes	$	128,696	$	66,202	$	(24,390)	$	(31,611)	$	138,897
As of January 31, 2015:
Net oil and natural gas properties	$	1,200,872	$	—	$	—	$	(74,782)	$	1,126,090
Oilfield services equipment - net	$	—	$	87,549	$	—	$	—	$	87,549
Other property and equipment - net	$	9,679	$	22,246	$	15,442	$	—	$	47,367
Total assets	$	1,408,768	$	202,649	$	131,649	$	(88,196)	$	1,654,870
Total liabilities	$	754,925	$	163,987	$	204,354	$	(13,414)	$	1,109,852

	For the Year Ended January 31, 2014
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	160,548	$	—	$	—	$	—	$	160,548
Oilfield services for third parties		—		102,606		—		(4,407)		98,199
Intersegment revenues		—		91,019		—		(91,019)		—
Total revenues		160,548		193,625		—		(95,426)		258,747
Expenses:
Lease operating and production taxes		32,460		—		—		—		32,460
Gathering, transportation and processing		4,302		—		—		—		4,302
Depreciation and amortization		56,788		8,905		620		(8,302)		58,011
Accretion of asset retirement obligations		56		—		—		—		56
Cost of oilfield services		—		142,339		—		(60,012)		82,327
General and administrative, net of amounts capitalized:
Salaries and benefits		3,541		6,894		6,864		—		17,299
Stock-based compensation		1,127		590		6,113		—		7,830
Other general and administrative		3,939		4,222		1,339		—		9,500
Total operating expenses		102,213		162,950		14,936		(68,314)		211,785
Income (loss) from operations		58,335		30,675		(14,936)		(27,112)		46,962
Other income (expense), net		(172)		(991)		38,998		(3,376)		34,459
Net income (loss) before income taxes	$	58,163	$	29,684	$	24,062	$	(30,488)	$	81,421
As of January 31, 2014:
Net oil and natural gas properties	$	725,958	$	—	$	—	$	(43,171)	$	682,787
Oilfield services equipment - net	$	—	$	46,585	$	—	$	—	$	46,585
Other property and equipment - net	$	1,594	$	18,912	$	4,001	$	—	$	24,507
Total assets	$	816,282	$	126,114	$	148,438	$	(63,312)	$	1,027,522
Total liabilities	$	318,875	$	64,017	$	141,609	$	(20,141)	$	504,360

	For the Year Ended January 31, 2013
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	39,614	$	—	$	—	$	—	$	39,614
Oilfield services for third parties		—		22,535		—		(1,788)		20,747
Intersegment revenues		—		34,672		—		(34,672)		—
Total revenues		39,614		57,207		—		(36,460)		60,361
Expenses:
Lease operating and production taxes		8,058		—		—		—		8,058
Gathering, transportation and processing		150		—		—		—		150
Depreciation and amortization		13,578		2,857		378		(1,732)		15,081
Accretion of asset retirement obligations		184		—		—		—		184
Cost of oilfield services		—		39,534		—		(22,928)		16,606
General and administrative, net of amounts capitalized:
Salaries and benefits		4,367		8,422		1,959		—		14,748
Stock-based compensation		2,507		617		3,342		—		6,466
Other general and administrative		2,223		2,708		2,398		—		7,329
Total operating expenses		31,067		54,138		8,077		(24,660)		68,622
Income (loss) from operations		8,547		3,069		(8,077)		(11,800)		(8,261)
Other income (expense), net		(6,318)		4		974		(883)		(6,223)
Net income (loss) before income taxes	$	2,229	$	3,073	$	(7,103)	$	(12,683)	$	(14,484)
As of January 31, 2013:
Net oil and natural gas properties	$	310,557	$	—	$	—	$	(11,800)	$	298,757
Oilfield services equipment - net	$	—	$	18,878	$	—	$	—	$	18,878
Other property and equipment - net	$	1,597	$	12,443	$	1,739	$	—	$	15,779
Total assets	$	362,878	$	38,668	$	40,220	$	(13,445)	$	428,321
Total liabilities	$	91,134	$	11,845	$	125,364	$	(1,645)	$	226,698

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Share-Based Compensation (Details 4) (Employee Stock Option [Member], USD $)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options outstanding, beginning balance	6,108,333	231,666	235,833
Options forfeited		(15,000)
Options exercised	(108,333)	(108,333)	(4,167)
Options granted	700,000	6,000,000
Options outstanding, ending balance	6,700,000	6,108,333	231,666
Weighted average exercise price, options outstanding beginning balance	$ 11.07	$ 1.48	$ 1.50
Weighted average exercise price, options forfeited		$ 3.00
Weighted average exercise price, options exercised	$ 1.25	$ 1.25	$ 3.00
Weighted average exercise price, options granted	$ 14.00	$ 11.25
Weighted average exercise price, options outstanding ending balance	$ 11.54	$ 11.07	$ 1.48
Options exercisable, beginning	108,333	231,666	142,500
Options exercisable, ending	600,000	108,333	231,666

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Supplemental Disclosures of Cash Flow Information (Tables)

12 Months Ended

Jan. 31, 2015

Supplemental Disclosures of Cash Flow Information [Abstract]

Schedule of Supplemetal Cash Flow Disclosures

	For the Years Ended January 31,
(in thousands)	2015		2014		2013
Cash paid during the period for:
Interest expense	$	19,713	$	1,419	$	75
Income taxes	$	600	$	—	$	—
Non-cash investing activities:
Additions (reductions) to oil and natural gas properties through:
Increased accounts payable and accrued liabilities	$	47,838	$	30,785	$	36,654
Issuance of common stock	$	—	$	2,438	$	1,204
Capitalized stock based compensation	$	1,143	$	1,391	$	949
Change in asset retirement obligations	$	1,818	$	673	$	1,869
Capitalized interest	$	4,899	$	809	$	—
Acquisition of oilfield services equipment through notes payable and liabilities	$	—	$	1,990	$	—
Purchase of minority interest in RockPile	$	—	$	—	$	12,349
Non-cash financing activities:
Notes payable issued for redemption of RockPile B Units	$	1,041	$	—	$	—

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Related Party Transactions

12 Months Ended

Jan. 31, 2015

Related Party Transactions [Abstract]

Related Party Transactions

14. RELATED PARTY TRANSACTIONS

TUSA and an affiliate of Caliber have entered into certain midstream services agreements for (i) crude oil gathering, stabilization, treating and redelivery; (ii) natural gas compression, gathering, dehydration, processing and redelivery; (iii) produced water transportation and disposal services; and (iv) fresh water transportation for TUSA’s oil and natural gas drilling and production operations.  The agreements also include an acreage dedication from TUSA and a firm volume commitment by the Caliber affiliate for each service line.  TUSA has agreed to deliver minimum monthly revenues derived from the fees paid by TUSA to the Caliber affiliate for volumes of oil, natural gas, produced water, and fresh water for a primary term of 15 years beginning on the 2014 in-service dates for the Caliber facilities.  The aggregate minimum revenue commitment over the term of the agreements is $405.0 million, of which $359.2 million was outstanding at January 31, 2015.

TUSA and an affiliate of Caliber have also entered into a gathering services agreement, pursuant to which the Caliber affiliate will provide certain gathering-related measurement services to TUSA, and a fresh water sales agreement, that will make available certain volumes of fresh water for purchase by TUSA at a set per barrel fee for a primary term of five years from the in-service date anticipated to be in the first half of fiscal year 2016.  The fresh water sales agreement obligates TUSA to purchase all of the fresh water it requires for its drilling and operating activities exclusively from the Caliber affiliate, subject to availability, but it does not require TUSA to purchase a minimum volume of fresh water.

For the years ended January 31, 2015 and 2014, Caliber had $43.0 million and $15.6 million of revenue, respectively, of which $36.6 million and $15.0 million, respectively, were from TUSA.  Also, TUSA sold one salt water disposal well to an affiliate of Caliber for $1.5 million in fiscal year 2015. 

For the year ended January 31, 2015, Triangle received $0.9 million from Caliber for certain administrative services supplemental to those provided by Caliber employees.  The administrative services were provided pursuant to the October 1, 2012 Services Agreement between Triangle and Caliber.