Triangle Petroleum (TPLMQ) 10-K 13 Apr 15 2015 FY Annual report Financial data

Document_And_Entity_Informatio

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	31-Jan-15
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2015
Entity Registrant Name	Triangle Petroleum Corp
Entity Central Index Key	1281922
Current Fiscal Year End Date	-30
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

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Jan. 31, 2015	Jan. 31, 2014
In Thousands, unless otherwise specified
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

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Jan. 31, 2015	Jan. 31, 2014
Common stock, par value	$0.00	$0.00
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%

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	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

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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

Consolidated_Statement_of_Stoc

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

Description_Of_Business

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.

Summary_Of_Significant_Account

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.

Segment_Reporting

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, $91.0 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.

LongTerm_Debt

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 $120.0 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 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 $6.6 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

Hedging_And_Commodity_Derivati

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

Oil_And_Natural_Gas_Properties

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 $138.8 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.

Acquisitions

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.

Asset_Retirement_Obligations

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.

Equity_Investment_And_Equity_I

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			31-Jan-15		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		1-Oct-24		$	12.78	5,600,000	4,000,000
	Series 2 Warrants		1-Oct-24		$	22.09	2,400,000	2,400,000
	Series 3 Warrants		12-Sep-25		$	22.09	3,000,000	3,000,000
	Series 4 Warrants		12-Sep-25		$	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.

Capital_Stock

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.

ShareBased_Compensation

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
			Number of		Average
			Shares		Exercise Price
	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-1 units		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.

Fair_Value_Measurements

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)		Level 1			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			Level 3		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			Fair Value			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

Income_Taxes

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.

Related_Party_Transactions

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.

Commitments_And_Contingencies

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 Program    Pursuant 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.

Supplemental_Disclosures_Of_Ca

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	$	—	$	—

Quarterly_Financial_Informatio

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).

Supplemental_Information_On_Oi

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:
	31-Jan-12		538		202		—
	31-Jan-13		4,985		5,906		—
	31-Jan-14		13,734		10,930		1,440
	31-Jan-15		29,605		24,136		2,350
	Proved Undeveloped Reserves included above:
	31-Jan-12		827		472		—
	31-Jan-13		7,554		6,679		—
	31-Jan-14		18,182		15,574		2,541
	31-Jan-15		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.

Summary_Of_Significant_Account1

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.

Summary_Of_Significant_Account2

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

Segment_Reporting_Tables

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

LongTerm_Debt_Tables

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

Hedging_And_Commodity_Derivati1

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

Oil_And_Natural_Gas_Properties1

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

Acquisitions_Tables

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

Asset_Retirement_Obligations_T

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.

Equity_Investment_And_Equity_I1

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			31-Jan-15		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		1-Oct-24		$	12.78	5,600,000	4,000,000
	Series 2 Warrants		1-Oct-24		$	22.09	2,400,000	2,400,000
	Series 3 Warrants		12-Sep-25		$	22.09	3,000,000	3,000,000
	Series 4 Warrants		12-Sep-25		$	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.

ShareBased_Compensation_Tables

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
			Number of		Average
			Shares		Exercise Price
	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-1 units		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

Fair_Value_Measurements_Tables

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)	Level 1			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			Level 3		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			Fair Value			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

Income_Taxes_Tables

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

Commitments_And_Contingencies_

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

Recovered_Sheet1

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	$	—	$	—

Quarterly_Financial_Informatio1

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

Supplemental_Information_On_Oi1

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:
	31-Jan-12	538		202		—
	31-Jan-13	4,985		5,906		—
	31-Jan-14	13,734		10,930		1,440
	31-Jan-15	29,605		24,136		2,350
	Proved Undeveloped Reserves included above:
	31-Jan-12	827		472		—
	31-Jan-13	7,554		6,679		—
	31-Jan-14	18,182		15,574		2,541
	31-Jan-15	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

Description_Of_Business_Detail

Description Of Business (Details)	12 Months Ended
	Jan. 31, 2015
	item
Description Of Business [Abstract]
Number of major focus lines of business	3

Summary_Of_Significant_Account3

Summary Of Significant Accounting Policies (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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%

Summary_Of_Significant_Account4

Summary Of Significant Accounting Policies (Details 2) (USD $)	Jan. 31, 2015	Jan. 31, 2014
In Thousands, unless otherwise specified
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

Summary_Of_Significant_Account5

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

Summary_Of_Significant_Account6

Summary Of Significant Accounting Policies (Details 4) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	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

Segment_Reporting_Details

Segment Reporting (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
	segment
Segment Reporting [Abstract]
Number of reportable segments	2
Deferred Revenue	$123.60	$91	$34.70
Deferred gross profit	$1.30	$2.20

Segment_Reporting_Details_2

Segment Reporting (Details 2) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	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

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	Jan. 31, 2015	Jan. 31, 2014	Jul. 18, 2014
In Thousands, unless otherwise specified
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

LongTerm_Debt_Details_2

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
Accrued interest	$15,900,000

Longterm_Debt_Details_3

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	0.13%
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	0.38%
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%

Longterm_Debt_Details_4

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	0.13%
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	0.38%
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%

Longterm_Debt_Details_5

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%

Longterm_Debt_Details_6

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%

Hedging_And_Commodity_Derivati2

Hedging And Commodity Derivative Financial Instruments (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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)

Hedging_And_Commodity_Derivati3

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		60.3

Hedging_And_Commodity_Derivati4

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

Oil_And_Natural_Gas_Properties2

Oil And Natural Gas Properties (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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

Oil_And_Natural_Gas_Properties3

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

Oil_And_Natural_Gas_Properties4

Oil And Natural Gas Properties (Details 3) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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

Acquisitions_Details

Acquisitions (Details) (USD $)	0 Months Ended	1 Months Ended	12 Months Ended			1 Months Ended
	Aug. 28, 2013	Aug. 31, 2013	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013	Jun. 30, 2014	Oct. 31, 2013
		acre				acre
Kodiak Oil And Natural Gas Property [Member]
Business Acquisition [Line Items]
Date of acquisition	28-Aug-13
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			1-Jun-14
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			1-Oct-13
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

Acquisitions_Details_2

Acquisitions (Details 2) (USD $)	0 Months Ended	1 Months Ended
In Thousands, unless otherwise specified	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

Acquisitions_Details_3

Acquisitions (Details 3) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	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	$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

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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

Asset_Retirement_Obligations_D1

Asset Retirement Obligations (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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

Equity_Investment_And_Equity_I2

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
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
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
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

Equity_Investment_And_Equity_I3

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	1-Oct-24
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	1-Oct-24
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	12-Sep-25
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	12-Sep-25
Equity method investments, warrant excercise price	$28.09
Equity Method Investment, Class AUnits Held	2,000,000	2,000,000

Equity_Investment_And_Equity_I4

Equity Investment And Equity Investment Derivatives (Details 3) (USD $)	12 Months Ended		0 Months Ended
In Thousands, except Share data, unless otherwise specified	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

Equity_Investment_And_Equity_I5

Equity Investment And Equity Investment Derivatives (Details 4) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	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
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

Equity_Investment_And_Equity_I6

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			12.5

Capital_Stock_Details

Capital Stock (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	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
Common stock repurchased (in shares)	11,400,000
Common stock repurchased	$76.80
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

ShareBased_Compensation_Detail

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

ShareBased_Compensation_Detail1

Share-Based Compensation (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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

ShareBased_Compensation_Detail2

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

ShareBased_Compensation_Detail3

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
Weighted average exercise price, options exercised	$1.25	$1.25	$3
Weighted average exercise price, options granted	$14	$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

ShareBased_Compensation_Detail4

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
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
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
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
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
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
Remaining contractual life	9 years 7 months 10 days
Outstanding options	233,334

ShareBased_Compensation_Detail5

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

ShareBased_Compensation_Detail6

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

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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

Fair_Value_Measurements_Detail1

Fair Value Measurements (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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

Fair_Value_Measurements_Detail2

Fair Value Measurements (Details 3) (USD $)	Jan. 31, 2015	Jan. 31, 2014	Jul. 18, 2014
In Thousands, unless otherwise specified
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%

Income_Taxes_Details

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

Income_Taxes_Details_2

Income Taxes (Details 2) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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%

Income_Taxes_Details_3

Income Taxes (Details 3) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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

Income_Taxes_Details_4

Income Taxes (Details 4) (USD $)	Jan. 31, 2015	Jan. 31, 2014
In Thousands, unless otherwise specified
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)

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	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
	item								item
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

Recovered_Sheet2

Commitments and Contingencies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
Long-term Purchase Commitment [Line Items]
Lease operating expense	$1.80	$0.80	$0.50
Early contract termination fee	10.2
Chief Executive Officer [Member]
Long-term Purchase Commitment [Line Items]
Contingent liability for bonus payout to CEO	$1.90
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%

Commitments_And_Contingencies_1

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

Supplemental_Disclosures_Of_Ca1

Supplemental Disclosures Of Cash Flow Information (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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

Quarterly_Financial_Informatio2

Quarterly Financial Information (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	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)

Supplemental_Information_On_Oi2

Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details) (USD $)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013	Jan. 31, 2012
	MBoe	MBoe	MBoe	MBoe
	item
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
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

Supplemental_Information_On_Oi3

Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 2)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013	Jan. 31, 2012
	MBbls	MBbls	MBbls	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

Supplemental_Information_On_Oi4

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	44.1

Supplemental_Information_On_Oi5

Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 4)	12 Months Ended
	Jan. 31, 2015	Jan. 31, 2014	Jan. 31, 2013
	MBoe	MBoe	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	29.6
Proved undeveloped wells, ending balance	54	52.5	19.8

Supplemental_Information_On_Oi6

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

Supplemental_Information_On_Oi7

Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 6) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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

Supplemental_Information_On_Oi8

Supplemental Information On Oil And Natural Gas Exploration Development And Production Activities Disclosures (Unaudited) (Details 7) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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