10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE

ACT OF 1934

For the quarterly period ended July 31, 2015

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE

ACT OF 1934

For the transition period from _________ to _________

Commission file number 001-34945

TRIANGLE PETROLEUM CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

Delaware	98-0430762
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

1200 17th Street, Suite 2600

Denver, CO 80202

(Address of Principal Executive Offices)

(303) 260-7125

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ☒ Yes  ☐ No

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

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

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

Yes ☐   No ☒

As of September 3, 2015, there were 75,504,924 shares of the registrant’s common stock outstanding.

TRIANGLE PETROLEUM CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTERLY PERIOD ENDED JULY 31, 2015

April
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			1
PART I.FINANCIAL INFORMATION			2
	ITEM 1.	FINANCIAL STATEMENTS (UNAUDITED)	2
		CONDENSED CONSOLIDATED BALANCE SHEETS	3
		CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS	4
		CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	5
		CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY	6
		NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	7
	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	24
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	35
	ITEM 4.	CONTROLS AND PROCEDURES	36
PART II.  OTHER INFORMATION			37
	ITEM 1.	LEGAL PROCEEDINGS	37
	ITEM 1A.	RISK FACTORS	37
	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	37
	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	38
	ITEM 4.	MINE SAFETY DISCLOSURES	38
	ITEM 5.	OTHER INFORMATION	38
	ITEM 6.	EXHIBITS	39
SIGNATURES			40

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this report and other materials we file with the U.S. Securities and Exchange Commission (“SEC”), or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect our current expectations or forecasts of future events. Words such as “anticipates,” “expects,” “intends,” “plans,” “predicts,” “believes,” “seeks,” “estimates,” “could,” “would,” “will,” “may,” “can,” “continue,” “potential,” “likely,” “should,” and the negative of these terms or other comparable terminology, often identify forward-looking statements. Statements in this quarterly report that are not statements of historical facts are hereby identified as forward-looking statements for the purpose of the safe harbor provided by Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and Section 27A of the Securities Act of 1933, as amended (the “Securities Act”).

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

· future capital expenditures and performance;

· future operating results;

· anticipated drilling and development;

· drilling results;

· results of acquisitions;

· relationships with partners; and

· plans for our subsidiaries.

Actual results or developments may be different than we anticipate or may have unanticipated consequences to, or effects on, us or our business or operations. All of the forward-looking statements made in this report are qualified by the discussion of risks and uncertainties under “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended January 31, 2015, and in our other public filings with the SEC. Although the expectations reflected in the forward-looking statements are based on our current beliefs and expectations, undue reliance should not be placed on any such forward-looking statements due to the risks and uncertainties noted above and because such statements speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this report and in our future reports filed with the SEC. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this report may not occur.

1

PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS (UNAUDITED)

Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands, except share data)

	January 31, 2015		July 31, 2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	67,871	$	45,870
Accounts receivable		171,911		116,159
Commodity derivatives		54,775		26,677
Other current assets		14,952		8,947
Total current assets		309,509		197,653
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and natural gas properties, full cost method of accounting
Proved properties		1,159,584		1,302,145
Unproved properties and properties under development, not being amortized		142,896		112,918
Total oil and natural gas properties		1,302,480		1,415,063
Accumulated amortization		(176,390)		(627,296)
Net oil and natural gas properties		1,126,090		787,767
Oilfield services equipment, net		87,549		79,997
Other property and equipment, net		47,367		48,825
Net property, plant and equipment		1,261,006		916,589
OTHER ASSETS
Deferred loan costs		14,038		13,601
Equity investment		64,411		73,709
Commodity derivatives		—		2,689
Other		5,906		5,716
Total other assets		84,355		95,715
Total assets	$	1,654,870	$	1,209,957

See notes to condensed consolidated financial statements.

2

Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands, except share data)

	January 31, 2015		July 31, 2015
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued capital expenditures	$	176,182	$	130,698
Other accrued liabilities		73,440		57,667
Current portion of long-term debt		503		677
Interest payable		2,250		1,725
Deferred income taxes		19,467		—
Total current liabilities		271,842		190,767
LONG-TERM LIABILITIES
5% convertible note		135,877		139,295
Borrowings on credit facilities		224,159		259,192
TUSA 6.75% notes		429,500		425,889
Other notes and mortgages payable		10,102		12,687
Deferred income taxes		33,974		—
Other		4,398		4,435
Total liabilities		1,109,852		1,032,265
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Common stock, $0.00001 par value, 140,000,000 shares authorized; 75,174,442 and 75,488,871 shares issued and outstanding at January 31, 2015 and July 31, 2015, respectively		1		1
Additional paid-in capital		545,017		551,236
Retained earnings (accumulated deficit)		—		(373,545)
Total stockholders' equity		545,018		177,692
Total liabilities and stockholders’ equity	$	1,654,870	$	1,209,957

See notes to condensed consolidated financial statements.

3

Triangle Petroleum Corporation

Condensed Consolidated Statements of Operations (Unaudited)

(In thousands, except per share data)

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
	2014		2015		2014		2015
REVENUES:
Oil, natural gas and natural gas liquids sales	$	80,506	$	55,263	$	141,340		103,041
Oilfield services		61,483		54,470		100,431		124,980
Total revenues		141,989		109,733		241,771		228,021
EXPENSES:
Lease operating expenses		6,698		11,369		11,424		22,278
Gathering, transportation and processing		3,733		6,641		7,535		12,989
Production taxes		8,677		5,449		15,025		10,236
Depreciation and amortization		26,707		32,244		47,994		70,050
Impairment of oil and natural gas properties		—		206,000		—		398,000
Accretion of asset retirement obligations		40		90		65		147
Oilfield services		43,554		46,719		71,264		112,183
General and administrative, net of amounts capitalized		14,091		14,589		27,492		29,448
Total operating expenses		103,500		323,101		180,799		655,331
INCOME (LOSS) FROM OPERATIONS		38,489		(213,368)		60,972		(427,310)
OTHER INCOME (EXPENSE):
Interest expense, net		(4,218)		(9,866)		(6,890)		(18,972)
Amortization of deferred loan costs		(1,167)		(731)		(1,359)		(1,347)
Gain on extinguishment of debt		—		1,156		—		1,156
Realized commodity derivative gains (losses)		(2,954)		17,016		(3,772)		36,484
Unrealized commodity derivative gains (losses)		2,033		8,033		(2,605)		(25,409)
Equity investment income (loss)		190		1,210		64		1,398
Gain (loss) on equity investment derivatives		(7,534)		4,516		2,920		4,516
Gain on Caliber capital transactions		—		—		—		2,880
Other income		52		(1,312)		114		(382)
Total other income (expense)		(13,598)		20,022		(11,528)		324
INCOME (LOSS) BEFORE INCOME TAXES		24,891		(193,346)		49,444		(426,986)
INCOME TAX PROVISION (BENEFIT)		10,339		—		20,350		(53,441)
NET INCOME (LOSS)	$	14,552	$	(193,346)	$	29,094	$	(373,545)
Earnings (loss) per common share outstanding:
Basic	$	0.17	$	(2.56)	$	0.34	$	(4.96)
Diluted	$	0.15	$	(2.56)	$	0.30	$	(4.96)
Weighted average common shares outstanding:
Basic		86,172		75,410		86,064		75,334
Diluted		103,774		75,410		103,511		75,334

See notes to condensed consolidated financial statements.

4

Triangle Petroleum Corporation

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

	For the Six Months Ended July 31,
	2014		2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	29,094	$	(373,545)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		47,994		70,050
Impairment of oil and natural gas properties		—		398,000
Share-based compensation		3,815		6,134
Interest expense paid-in-kind on 5% convertible note		3,252		3,418
Amortization of deferred loan costs		1,359		1,347
Gain on extinguishment of debt		—		(1,156)
Accretion of asset retirement obligations		65		147
Unrealized commodity derivative (gains) losses		2,605		25,409
Equity investment (income) loss		(64)		(1,398)
Gain on equity investment derivatives		(2,920)		(4,516)
Gain on Caliber capital transactions		—		(2,880)
Deferred income taxes		19,800		(53,441)
Changes in related current assets and current liabilities:
Accounts receivable		(44,363)		55,752
Other current assets		(581)		6,005
Accounts payable and accrued liabilities		2,994		(48,345)
Asset retirement expenditures		(136)		(377)
Other		(1,068)		(559)
Cash provided by operating activities		61,846		80,045
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property expenditures		(149,479)		(128,734)
Acquisitions of oil and natural gas properties		(131,368)		(243)
Purchases of oilfield services equipment		(24,579)		(8,657)
Purchases of other property and equipment		(3,080)		(4,208)
Sale of oil and natural gas properties		—		6,000
Other		58		15
Cash used in investing activities		(308,448)		(135,827)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities		245,116		110,810
Repayments of credit facilities		(410,015)		(75,777)
Proceeds from notes payable		450,000		3,035
Repayments of other notes and mortgages payable		(199)		(298)
Early extinguishment of repurchased debt		—		(2,455)
Debt issuance costs		(10,331)		(910)
Payments to settle tax on vested restricted stock units		(2,192)		(624)
Cash provided by financing activities		272,379		33,781
NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS		25,777		(22,001)
CASH AND EQUIVALENTS, BEGINNING OF PERIOD		81,750		67,871
CASH AND EQUIVALENTS, END OF PERIOD	$	107,527	$	45,870

See notes to condensed consolidated financial statements.

5

Triangle Petroleum Corporation

Condensed Consolidated Statement of Stockholders’ Equity (Unaudited)

For the Six Months Ended July 31, 2015

(in thousands, except share data)

						Retained
	Shares of	Common		Additional		Earnings
	Common	Stock at		Paid-in		(Accumulated		Total
	Stock	Par Value		Capital		Deficit)		Equity
Balance - January 31, 2015	75,174,442	$	1	$	545,017	$	—	$	545,018
Vesting of restricted stock units (net of shares surrendered for taxes)	314,429		—		(624)		—		(624)
Share-based compensation	—		—		6,843		—		6,843
Net income (loss) for the period	—		—		—		(373,545)		(373,545)
Balance - July 31, 2015	75,488,871	$	1	$	551,236	$	(373,545)	$	177,692

See notes to condensed consolidated financial statements.

6

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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 predominantly located 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. Caliber was formed for the purpose of providing oil, natural gas and water transportation and related services to oil and natural gas exploration and production companies in the Williston Basin.

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

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation. These unaudited condensed 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.

Certain information and footnote disclosures normally included in our annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to SEC rules and regulations. We believe the disclosures made are adequate to make the information not misleading. We recommend that these unaudited condensed consolidated financial statements be read in conjunction with our audited consolidated financial statements and notes included in our Annual Report on Form 10-K for the fiscal year ended January 31, 2015, as filed with the SEC (“Fiscal 2015 Form 10-K”). In the opinion of management, all material adjustments considered necessary for a fair presentation of the Company’s interim results have been reflected. All such adjustments are considered to be of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results.

No condensed 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 condensed 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 unproved properties and other assets; (v) assigning fair value and allocating purchase price in connection with business combinations; (vi) accrued revenue and related receivables;

7

(vii) valuation of commodity derivative instruments and equity derivative instruments; (viii) accrued expenses and related 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 condensed consolidated financial statements.

Principles of Consolidation. The accounts of Triangle and its wholly-owned subsidiaries are presented in the accompanying condensed consolidated financial statements. All significant 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. The investment in Caliber is accounted for utilizing the equity method of accounting.  

Oil and Natural Gas Properties. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the amortizable pool of proved properties or in unproved properties, collectively, the full cost pool. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations.

At the end of each quarterly period, we must compute a limitation on capitalized costs, which is equal to the sum of the present value of estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC (unweighted arithmetic average of commodity prices in effect on the first day of each of the previous twelve months), less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects. We then conduct a “ceiling test” that compares the net book value of the full cost pool, after taxes, to the full cost ceiling limitation. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record an impairment of our oil and natural gas properties.  

The ceiling test for each period presented was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing 12 month simple average spot prices at the first of the month for natural gas at Henry Hub (“HH”) and West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation.

	Trailing 12 Month Simple Average Spot Prices
	January 31, 2015		April 30, 2015		July 31, 2015
Oil (per Bbl)	$	91.22	$	78.58	$	67.65
Natural gas (per MMbtu)	$	4.20	$	3.69	$	3.23
Natural gas liquids (per Bbl)	$	50.07	$	41.96	$	34.98

We recognized impairments to our proved oil and natural gas properties of $206.0 million and $398.0 million for the three and six months ended July 31, 2015, respectively, primarily due to the decline in oil, natural gas and natural gas liquids prices. We did not recognize impairments to our proved oil and natural gas properties for the three and six months ended July 31, 2014. We will incur additional impairments to our oil and natural gas properties in future quarters if prices stay at current levels or decline further.  The amount of any future impairment is difficult to predict, and will depend, in part, upon future oil, natural gas and natural gas liquids prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs. The ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results.  Impairment charges do not affect cash flow from operating activities but do adversely affect our net income and stockholders’ equity.  Any recorded impairment of oil and natural gas properties is not reversible at a later date.

The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.

8

Oilfield Services Equipment and Other Property and Equipment.  Oilfield services equipment and other property and equipment consisted of the following as of:

(in thousands)	January 31, 2015		July 31, 2015
Land	$	7,888	$	7,888
Building and leasehold improvements		33,625		35,506
Oilfield service equipment		116,354		122,946
Vehicles		4,811		5,761
Software, computers and office equipment		5,327		6,481
Capital leases		853		853
Total depreciable assets		168,858		179,435
Accumulated depreciation		(35,189)		(54,121)
Depreciable assets, net		133,669		125,314
Assets not placed in service		1,247		3,508
Total oilfield service equipment and other property & equipment, net	$	134,916	$	128,822

Income Taxes.  The Company computes its quarterly tax provision using the effective tax rate method based on applying the anticipated annual effective rate to its year-to-date income or loss, except for discrete items. Income tax on discrete items is computed and recorded in the period in which the specific transaction occurs.

As noted above, the carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation resulting in an impairment of $398.0 million for the six months ended July 31, 2015. This impairment results in Triangle having three years of cumulative historical pre-tax losses and a net deferred tax asset position. Additionally, Triangle will likely be required to recognize additional impairments of its oil and natural gas properties in future periods if oil and natural gas prices remain at current levels or continue to decline and such impairments will likely be material. Triangle also had net operating loss carryovers (“NOLs”) for federal income tax purposes of $136.9 million at January 31, 2015. These losses and expected future losses were a key consideration that led Triangle to provide a valuation allowance against its net deferred tax assets as of April 30 and July 31, 2015 since it cannot conclude that it is more likely than not that its net deferred tax assets will be fully realized in future periods.

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. At each reporting period, 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. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

In the first quarter of fiscal year 2016 the Company recorded the benefit of reversing its net deferred tax liability. As long as the Company concludes that it will continue to have a need for a valuation allowance against its net deferred tax assets, the Company likely will not have any additional income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims or for state income taxes.

As of July 31, 2015, the Company had no unrecognized tax benefits. The Company’s management does not believe that there are any new items or changes in facts or judgments that should impact the Company’s position during the first six months of fiscal year 2016. Given the substantial net operating loss carryforwards at both the federal and state levels, neither significant interest expense nor penalties charged for any examining agents’ tax adjustments of income tax returns are anticipated, as any such adjustments would very likely only adjust net operating loss carryforwards.

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

9

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:

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
	2014		2015		2014		2015
Dilutive		17,602,373		—		17,447,130		—
Anti-dilutive shares		4,500,000		10,888,828		4,500,000		10,888,828

The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the periods presented:

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
(in thousands, except per share data)	2014		2015		2014		2015
Net income (loss) attributable to common stockholders	$	14,552	$	(193,346)	$	29,094	$	(373,545)
Effect of 5% convertible note conversion		996		—		1,983		—
Net income (loss) attributable to common stockholders after effect of 5% convertible note conversion	$	15,548	$	(193,346)	$	31,077	$	(373,545)
Basic weighted average common shares outstanding		86,172		75,410		86,064		75,334
Effect of dilutive securities		17,602		—		17,447		—
Diluted weighted average common shares outstanding		103,774		75,410		103,511		75,334
Basic net income (loss) per share	$	0.17	$	(2.56)	$	0.34	$	(4.96)
Diluted net income (loss) per share	$	0.15	$	(2.56)	$	0.30	$	(4.96)

Reclassifications.  Certain amounts in our unaudited condensed consolidated statement of operations for the three and six months ended July 31, 2014 have been reclassified to conform to the financial statement presentation for the periods ended July 31, 2015. The unaudited condensed consolidated 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 that 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.

10

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 and its subsidiaries, is responsible for a variety of oilfield and complementary well completion services for both TUSA-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 three months ended July 31, 2015 and 2014.

	For the Three Months Ended July 31, 2015
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	55,263	$	—	$	—	$	—	$	55,263
Oilfield services for third parties		—		54,830		—		(360)		54,470
Intersegment revenues		—		14,601		—		(14,601)		—
Total revenues		55,263		69,431		—		(14,961)		109,733
Expenses:
Lease operating and production taxes		16,818		—		—		—		16,818
Gathering, transportation and processing		6,641		—		—		—		6,641
Depreciation and amortization		24,527		8,718		407		(1,408)		32,244
Impairment of oil and natural gas properties		206,000		—		—		—		206,000
Accretion of asset retirement obligations		90		—		—		—		90
Cost of oilfield services		—		56,353		(1,238)		(8,396)		46,719
General and administrative, net of amounts capitalized:
Salaries and benefits		584		3,940		3,045		—		7,569
Stock-based compensation		375		84		3,167		—		3,626
Other general and administrative		349		1,034		2,011		—		3,394
Total operating expenses		255,384		70,129		7,392		(9,804)		323,101
Income (loss) from operations		(200,121)		(698)		(7,392)		(5,157)		(213,368)
Other income (expense), net		18,290		(845)		3,116		(539)		20,022
Income (loss) before income taxes	$	(181,831)	$	(1,543)	$	(4,276)	$	(5,696)	$	(193,346)

11

	For the Three Months Ended July 31, 2014
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	80,506	$	—	$	—	$	—	$	80,506
Oilfield services for third parties		—		64,093		—		(2,610)		61,483
Intersegment revenues		—		37,962		—		(37,962)		—
Total revenues		80,506		102,055		—		(40,572)		141,989
Expenses:
Lease operating and production taxes		15,375		—		—		—		15,375
Gathering, transportation and processing		3,733		—		—		—		3,733
Depreciation and amortization		26,287		4,690		186		(4,456)		26,707
Accretion of asset retirement obligations		40		—		—		—		40
Cost of oilfield services		—		68,867		—		(25,313)		43,554
General and administrative, net of amounts capitalized:
Salaries and benefits		1,560		2,922		2,051		—		6,533
Stock-based compensation		343		127		1,337		—		1,807
Other general and administrative		2,882		2,329		540		—		5,751
Total operating expenses		50,220		78,935		4,114		(29,769)		103,500
Income (loss) from operations		30,286		23,120		(4,114)		(10,803)		38,489
Other income (expense), net		(4,267)		(667)		(7,752)		(912)		(13,598)
Net income (loss) before income taxes	$	26,019	$	22,453	$	(11,866)	$	(11,715)	$	24,891

The following tables present selected financial information for our operating segments for the six months ended July 31, 2015 and 2014.

	For the Six Months Ended July 31, 2015
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	103,041	$	—	$	—	$	—	$	103,041
Oilfield services for third parties		—		125,920		—		(940)		124,980
Intersegment revenues		—		24,105		—		(24,105)		—
Total revenues		103,041		150,025		—		(25,045)		228,021
Expenses:
Lease operating and production taxes		32,514		—		—		—		32,514
Gathering, transportation and processing		12,989		—		—		—		12,989
Depreciation and amortization		53,826		18,207		732		(2,715)		70,050
Impairment of oil and natural gas properties		398,000		—		—		—		398,000
Accretion of asset retirement obligations		147		—		—		—		147
Cost of oilfield services		—		126,939		—		(14,756)		112,183
General and administrative, net of amounts capitalized:
Salaries and benefits		925		8,769		6,298		—		15,992
Stock-based compensation		696		135		5,303		—		6,134
Other general and administrative		756		2,831		3,735		—		7,322
Total operating expenses		499,853		156,881		16,068		(17,471)		655,331
Income (loss) from operations		(396,812)		(6,856)		(16,068)		(7,574)		(427,310)
Other income (expense), net		(2,712)		(1,720)		5,802		(1,046)		324
Income (loss) before income taxes	$	(399,524)	$	(8,576)	$	(10,266)	$	(8,620)	$	(426,986)
As of July 31, 2015:
Net oil and natural gas properties	$	871,169	$	—	$	—	$	(83,402)	$	787,767
Oilfield services equipment - net	$	—	$	79,997	$	—	$	—	$	79,997
Other property and equipment - net	$	9,194	$	21,759	$	17,872	$	—	$	48,825
Total assets	$	1,023,660	$	159,486	$	130,445	$	(103,634)	$	1,209,957
Total liabilities	$	770,143	$	130,685	$	151,669	$	(20,232)	$	1,032,265

12

	For the Six Months Ended July 31, 2014
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	141,340	$	—	$	—	$	—	$	141,340
Oilfield services for third parties		—		103,650		—		(3,219)		100,431
Intersegment revenues		—		59,837		—		(59,837)		—
Total revenues		141,340		163,487		—		(63,056)		241,771
Expenses:
Lease operating and production taxes		26,449		—		—		—		26,449
Gathering, transportation and processing		7,535		—		—		—		7,535
Depreciation and amortization		46,440		8,280		362		(7,088)		47,994
Accretion of asset retirement obligations		65		—		—		—		65
Cost of oilfield services		—		112,578		—		(41,314)		71,264
General and administrative, net of amounts capitalized:
Salaries and benefits		2,801		5,660		4,333		—		12,794
Stock-based compensation		738		217		2,860		—		3,815
Other general and administrative		4,419		4,688		1,776		—		10,883
Total operating expenses		88,447		131,423		9,331		(48,402)		180,799
Income (loss) from operations		52,893		32,064		(9,331)		(14,654)		60,972
Other income (expense), net		(10,834)		(1,174)		1,746		(1,266)		(11,528)
Income (loss) before income taxes	$	42,059	$	30,890	$	(7,585)	$	(15,920)	$	49,444

Certain income statement reclassifications were made as previously noted, as well as changes 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 defer recognition of oilfield services income (intersegment revenues less cost of oilfield services and related depreciation) for wells that we operate and this deferred income is credited to proved oil and natural gas properties. In addition, we eliminate our non-operating partners’ share of oilfield services income for well completion activities on properties we operate. We also defer Caliber gross profit from our share of its income associated with services it provided that 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. For the three months ended July 31, 2015 and 2014, $0.1 and $2.9 million, respectively, of the depreciation and amortization elimination relates to the Exploration and Production segment and the balance relates to the Oilfield Services segment. For the six months ended July 31, 2015 and 2014, $0.6 and $4.3 million, respectively, of the depreciation and amortization elimination relates to the Exploration and Production segment and the balance relates to the Oilfield Services segment.

These differences, as well as differing amounts for impairments, result in basis differences between the net oil and gas property amounts presented in Triangle’s financial statements compared to those presented in TUSA’s standalone financial statements.

13

4.  LONG-TERM DEBT

The Company’s long-term debt consisted of the following as of January 31, 2015 and July 31, 2015:

(in thousands)	January 31, 2015		July 31, 2015
5% convertible note	$	135,877	$	139,295
TUSA credit facility due October 2018		119,272		172,272
RockPile credit facility due March 2019		104,887		86,920
TUSA 6.75% notes due July 2022		429,500		425,889
Other notes and mortgages payable		10,605		13,364
Total debt		800,141		837,740
Less current portion of debt:
Other notes and mortgages payable		(503)		(677)
Total long-term debt	$	799,638	$	837,063

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 September 30, 2017, the Company has the option to make such interest payments in cash. As of July 31, 2015, $19.3 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. The TUSA credit facility has a maturity date of October 16, 2018.

On April 30, 2015, TUSA entered into Amendment No. 1 to its Second Amended and Restated Credit Agreement (“Amendment No. 1”) to, among other things, replace the existing total funded debt leverage ratio with a senior secured leverage ratio, add an interest coverage ratio, and add an equity cure right for non-compliance with financial covenants. The May 2015 semi-annual redetermination of the borrowing base was conducted concurrently with the execution of Amendment No. 1, and the borrowing base was adjusted from $435.0 million to $350.0 million.

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 1.0%), 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 May1 and November1. 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 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 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

14

assets to consolidated current liabilities, consolidated senior secured debt to consolidated EBITDAX, and interest to consolidated EBITDAX. As of July 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 pays a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the RockPile credit facility. RockPile also pays 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. The obligations under the RockPile credit facility are guaranteed by RockPile’s subsidiaries, but Triangle is not a guarantor.

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 July 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 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 a price equal to 105% of the principal amount of the notes redeemed (103% after July 15, 2018, 102% after July 15, 2019 and 100% after July 15, 2020), 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.

15

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, immediately retired the repurchased notes, and recognized a gain on extinguishment of debt of $6.6 million.  During the three months ended July 31, 2015, TUSA repurchased additional TUSA 6.75% Notes with a face value of $3.6 million for $2.5 million, immediately retired the repurchased notes, and recognized a gain on extinguishment of debt of $1.1 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 July 31, 2015, TUSA was in compliance with all covenants under the TUSA 6.75% Notes.

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 or reduce 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 four 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:

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
(in thousands)	2014		2015		2014		2015
Realized commodity derivative gains (losses)	$	(2,954)	$	17,016	$	(3,772)	$	36,484
Unrealized commodity derivative gains (losses)		2,033		8,033		(2,605)		(25,409)
Commodity derivative gains (losses), net	$	(921)	$	25,049	$	(6,377)	$	11,075

16

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

	Contract		Quantity	Weighted Average		Weighted Average		Weighted Average
	Type	Basis (1)	(Bbl/d)	Put Strike		Call Strike		Price
August 1, 2015 to January 31, 2016	Collar	NYMEX	2,739	$	85.45	$	98.20
August 1, 2015 to January 31, 2016	Swap	NYMEX	1,755					$	60.22
February 1, 2016 to January 31, 2017	Swap	NYMEX	2,746					$	60.23

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

In August 2015, the Company unwound certain commodity derivative swap contracts and realized a gain of $9.3 million.  The early settled contracts were for 2,000 barrels of oil per day at an average fixed price of $60.34 for the period from January 1, 2016 to December 31, 2016.

The estimated fair values of commodity derivatives included in the consolidated balance sheets at January 31, 2015 and July 31, 2015 are summarized below. 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)	January 31, 2015		July 31, 2015
Current Assets:
Crude oil derivative contracts	$	54,775	$	26,677
Other Long-Term Assets:
Crude oil derivative contracts		—		2,689
Total derivative asset	$	54,775	$	29,366

6.  ACQUISITIONS

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.

The acquisition was 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 unaudited pro forma financial information represents the combined results for the Company and the properties acquired from Marathon, in June of 2014, as if the acquisitions had occurred on February 1, 2014.

	For the Three Months Ended		For the Six Months Ended
(in thousands, except per share data)	July 31, 2014		July 31, 2014
Operating revenues	$	146,559	$	253,206
Net income (loss)	$	15,427	$	31,341
Earnings (loss) per common share
Basic	$	0.18	$	0.36
Diluted	$	0.16	$	0.32
Weighted average common shares outstanding:
Basic		86,172		86,064
Diluted		103,774		103,511

17

The pro forma information includes the effects of adjustments for depreciation and amortization expense of $1.3 million and $3.3 million, respectively, for the three and six month periods ended July 31, 2014. 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 as of the beginning of the period, nor are they necessarily indicative of future results.

7.  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”), a wholly-owned subsidiary of First Reserve Energy Infrastructure Fund. 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.

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, which is 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 recognized a gain in the first six months of fiscal year 2016 of $2.9 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 (Series 5) 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 Class A (Series 1 through 4) Warrants at strike prices and expiration dates noted below and 1,269,333 Class A (Series 6) Warrants with a strike price of $12.50 and an expiration date of February 2, 2018.

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

	Expiration		Strike Price at		As of	As of
	Date		July 31, 2015		January 31, 2015	July 31, 2015
Class A Units		—	$	—	7,000,000	7,000,000
Series 1 Warrants		October 1, 2024	$	12.78	5,600,000	6,615,467
Series 2 Warrants		October 1, 2024	$	22.09	2,400,000	2,835,200
Series 3 Warrants		September 12, 2025	$	22.09	3,000,000	3,544,000
Series 4 Warrants		September 12, 2025	$	28.09	2,000,000	2,362,667
Series 6 Warrants		February 2, 2018	$	12.50	—	1,269,333

18

The following summarizes the activities related to the Company’s equity investment in Caliber for the six months ended July 31, 2015:

	For the Six Months Ended
(in thousands)	July 31, 2015
Balance at January 31, 2015	$	64,411
Capital contributions		—
Distributions		—
Equity investment share of net income before intra-company profit eliminations		1,902
Change in fair value of warrants		4,516
Gain on Caliber capital transactions		2,880
Balance at July 31, 2015	$	73,709
Fair value of warrants at July 31, 2015	$	5,020

Equity Investment Derivatives.  At January 31, 2015 and July 31, 2015, the Company held Class A (Series 1 through Series 4 and Series 6) Warrants to acquire additional ownership in Caliber. These instruments are considered to be equity investment derivatives and are valued at each reporting period using valuation techniques for which the inputs are generally less observable than from objective sources.

8.  CAPITAL STOCK

The Company had 106.7 million shares of common stock issued or reserved for issuance at July 31, 2015. At July 31, 2015, the Company had 75.5 million shares of common stock issued and outstanding. The Company also had 1.8 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2011 Omnibus Incentive Plan and 3.1 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2014 Equity Incentive Plan (the “2014 Plan”). The Company also had 2.9 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 17.4 million shares of common stock reserved for issuance pursuant to the Convertible Note at July 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 of common stock 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. There were no common stock repurchases for the three and six months ended July 31, 2015. As of July 31, 2015, the number of shares of common stock remaining available for repurchase under the Board approved program was 5,374,890 shares.

9.  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

19

consultants of the Company and its subsidiaries. The maximum number of shares of common stock issuable under the 2014 Plan is 6.0 million shares, subject to adjustment for certain transactions.

For the three and six months ended July 31, 2014 and 2015, the Company recorded share-based compensation related to restricted stock units, stock options and RockPile Series B Units as follows:

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
(in thousands)	2014		2015		2014		2015
Restricted stock units	$	1,503	$	2,584	$	3,274	$	4,663
Stock options		487		1,347		973		2,045
RockPile Series B Units		127		84		217		135
		2,117		4,015		4,464		6,843
Less amounts capitalized to oil and natural gas properties		(310)		(389)		(649)		(709)
Compensation expense	$	1,807	$	3,626	$	3,815	$	6,134

Restricted Stock Units. During the six months ended July 31, 2015, the Company granted 1,773,343 restricted stock units as compensation to employees, officers, and directors which generally vest over one to five years. As of July 31, 2015, there was approximately $23.2 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 3.3 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 activity for our restricted stock units during the six months ended July 31, 2015:  

		Weighted
		Average
	Number of	Award Date
	Shares	Fair Value
Restricted stock units outstanding - January 31, 2015	2,914,045	$	7.92
Units granted	1,773,343	$	4.93
Units forfeited	(63,588)	$	8.62
Units vested	(434,971)	$	7.79
Restricted stock units outstanding - July 31, 2015	4,188,829	$	6.66

Stock Options. There were no grants, exercises or forfeitures of stock options during the six months ended July 31, 2015. The following table summarizes the stock options outstanding at July 31, 2015:  

		Remaining
Exercise Price		Contractual Life	Number of Shares
per Share		(years)	Outstanding		Exercisable
$	7.50	7.93		750,000		150,000
$	8.50	7.93		750,000		150,000
$	10.00	7.93		1,500,000		300,000
$	12.00	7.93		1,500,000		300,000
$	15.00	7.93		1,500,000		300,000
$	12.00	6.12		233,333		—
$	14.00	6.12		233,333		—
$	16.00	9.12		233,334		—
				6,700,000		1,200,000
Weighted average exercise price per share			$	11.54	$	11.25
Weighted average remaining contractual life				7.85		7.93

As of July 31, 2015, there was approximately $16.5 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 2.8 years.

20

RockPile Share-Based Compensation. RockPile currently has two classes of equity; Series A Units, which are voting units with an 8% preference, and Series B Units, which are non-voting 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 following table summarizes the activity for RockPile’s Series B Units for the six months ended July 31, 2015:

	Series	Series	Series	Series
	B-1units	B-2 units	B-3 units	B-4 units	Total
Units outstanding - January 31, 2015	2,920,000	60,000	910,000	1,412,000	5,302,000
Units redeemed	—	—	—	—	—
Units granted	—	—	—	—	—
Units forfeited	—	—	(96,000)	(74,000)	(170,000)
Units outstanding - July 31, 2015	2,920,000	60,000	814,000	1,338,000	5,132,000
Vested	2,920,000	30,000	352,000	117,600	3,419,600
Unvested	—	30,000	462,000	1,220,400	1,712,400

Series B Units currently have a 1 to 46 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. As of July 31, 2015, there was approximately $2.3 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’ remaining vesting schedule.

10.  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 July 31, 2015, by level within the fair value hierarchy:

	As of January 31, 2015
(in thousands)	Level 1		Level 2		Level3		Total
Assets:
Commodity derivative assets	$	—	$	54,775	$	—	$	54,775
Equity investment derivative assets	$	—	$	—	$	504	$	504
Liabilities:
RockPile earn-out liability	$	—	$	(1,825)	$	—	$	(1,825)

21

	As of July 31, 2015
(in thousands)	Level1		Level 2		Level 3		Total
Assets:
Commodity derivative assets	$	—	$	29,366	$	—	$	29,366
Equity investment derivative assets	$	—	$	—	$	5,020	$	5,020
Liabilities:
RockPile earn-out liability	$	—	$	(1,242)	$	—	$	(1,242)

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 July 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 and Series 6) Warrants. The Company determines its estimate of the fair value of Caliber Class A Warrants using a Monte Carlo Simulation (“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. At July 31, 2015, the fair value of the underlying Class A Units was estimated employing an income approach using a MCS model and discounted cash flows,and a market approach based on observed valuation multiples for comparable public companies.  Key inputs into these valuation approaches are generally less observable than those from objective sources. Therefore, 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 Service, Inc. 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.

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 values of the other notes and mortgages payable is not significantly different than their carrying 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.

The carrying values and fair values of the Company’s debt instruments are as follows:

	January 31, 2015				July 31, 2015
	Carrying		Estimated		Carrying		Estimated
(in thousands)	Value		FairValue		Value		Fair Value
5% convertible note	$	135,877	$	137,790	$	139,295	$	136,361
Revolving credit facilities		224,159		224,159		259,192		259,192
TUSA 6.75% notes		429,500		303,871		425,889		317,293
Other notes and mortgages payable		10,605		10,605		13,364		13,364

22

11.  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 in 2014. The aggregate minimum revenue commitment over the term of the agreements is $405.0 million, of which $336.3 million was outstanding at July 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.

During the six months ended July 31, 2015, TUSA sold one salt water disposal well to an affiliate of Caliber for net proceeds of $6.0 million.

12.  SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION

	For the Six Months Ended July 31,
(in thousands)	2014		2015
Cash paid during the period for:
Interest expense	$	4,717	$	16,078
Income taxes	$	550	$	—
Non-cash investing activities:
Additions to oil and natural gas properties through:
Increase (decrease) in accounts payable and accrued liabilities	$	37,151	$	(15,770)
Capitalized stock based compensation	$	649	$	709
Change in asset retirement obligations	$	1,106	$	425
Non-cash financing activities:
Notes payable issued for redemption of RockPile Series B Units	$	1,041	$	—

23

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

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

Summary of results for the six months ended July 31, 2015

· Average daily production volumes were 13,646 Boe/day for the six months ended July 31, 2015, compared to 9,359 Boe/day for the six months ended July 31, 2014, an increase of 46%.

· TUSA spud 16 gross (13.0 net) operated wells and completed 14 gross (9.9 net) operated wells during the six months ended July 31, 2015. As of July 31, 2015, TUSA had 18 gross (16.4 net) operated wells that have been drilled and were pending completion.

· Lower average realized prices of $41.72per Boe for the six months ended July 31, 2015, versus $83.42 per Boe for the six months ended July 31, 2014, resulted in oil, natural gas and natural gas liquids sales for the six months ended July 31, 2015 of $103.0 million compared to $141.3 million for the six months ended July 31, 2014.

· RockPile completed 14 TUSA wells and 89 third-party wells in the six months ended July 31, 2015, as compared to 24 TUSA wells and 36 third-party wells in the six months ended July 31, 2014.

· Oilfield services revenue for the six months ended July 31, 2015 was $125.0 million compared to $100.4 million for the six months ended July 31, 2014.  

· The competitive oilfield services pricing environment resulted in a negative gross profit of $3.3 million for the six months ended July 31, 2015 compared to a gross profit of $23.7 million for the six months ended July 31, 2014 after eliminations of intercompany gross profit.

· The carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation  at  July 31, 2015, resulting in an impairment of $398.0 million for the six months ended July 31, 2015.

· Cash flows provided by operating activities were $80.0 million for the six months ended July 31, 2015 compared to $61.8 million for the six months ended July 31, 2014.

· TUSA amended its credit facility to revise its financial covenants and add an equity cure right.

Drilling and Completions

The following tables summarize our wells spud and completed during the three and six months ended July 31, 2015:

	For the Three Months Ended				For the Six Months Ended
	July 31, 2015				July 31, 2015
	Spud		Completed		Spud		Completed
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Operated wells	5	4.1	9	6.6	16	13.0	14	9.9
Non-operated wells	2	0.1	5	0.2	4	0.1	27	0.8
	7	4.2	14	6.8	20	13.1	41	10.7

Properties, Plan of Operations and Capital Expenditures

We own operated and non-operated leasehold positions in the Williston Basin of North Dakota and Montana. As of July 31, 2015, we have completed a total of 110 gross (79.4 net) operated wells in the Williston Basin and have an interest in approximately 474 gross (26.3 net) non-operated wells.

As of July 31, 2015, we were running one drilling rig, which we released in August 2015. We plan to periodically reassess the appropriate number of rigs for our future drilling program based on a variety of factors including, but not limited to, prevailing oil and natural gas prices and operational efficiencies.

24

Our oil and natural gas property expenditures during the six months ended July 31, 2014 and 2015 are summarized below:

	For the Six Months Ended
	July 31,
(in thousands)	2014		2015
Costs incurred during the period
Acquisition of properties:
Proved	$	91,067	$	243
Unproved		40,301		—
Exploration		52,338		49,499
Development		133,186		68,405
Oil and natural gas expenditures		316,892		118,147
Asset retirement obligations, net		1,106		425
	$	317,998	$	118,572

For the three and six months ended July 31, 2015, we recorded impairments to our oil and natural gas properties of $206.0 million and $398.0 million, respectively, primarily due to the significant decline in oil, natural gas and natural gas liquids prices. The trailing twelve month reference prices at July 31, 2015 were $67.65 per Bbl of oil, $3.23 per MMbtu for natural gas and $34.98 per Bbl of natural gas liquids. For the three and six months ended July 31, 2014, we did not record an impairment to our oil and natural gas properties.

Because the ceiling calculation requires rolling 12-month average commodity prices, the effect of lower quarter-over-quarter prices in fiscal year 2016 compared to fiscal year 2015 will be a lower ceiling limitation each quarter.  We will incur additional impairments to our oil and natural gas properties in future quarters if prices stay at current levels or decline further.  The amount of any future impairment is difficult to predict and will depend, in part, upon future oil, natural gas and natural gas liquids prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs.

If the simple average of oil, natural gas and natural gas liquids prices as of the first day of each month for the trailing 12-month period ended July 31, 2015 had been $58.58 per Bbl of oil, $2.98 per MMbtu for natural gas and $29.44 per Bbl of natural gas liquids and all other factors remained constant, our impairment for the six months ended July 31, 2015 would have increased, on a pro forma basis, by approximately $180 million. The aforementioned prices were calculated based on a 12-month simple average, which includes the oil and natural gas prices on the first day of the month for the ten months ended August 31, 2015 and the prices for August 2015 were held constant for the remaining two months.

This calculation of the impact of lower commodity prices is prepared based on the presumption that all other inputs and assumptions are held constant with the exception of oil, natural gas and natural gas liquids prices. Therefore, this calculation strictly isolates the impact of commodity prices on our ceiling test limitation and proved reserves. The impact of price is only a single variable in the estimation of our proved reserves and other factors could have a significant impact on future reserves and the present value of future cash flows. The other factors that impact future estimates of proved reserves include, but are not limited to, extensions and discoveries, changes in costs, drilling results, revisions due to performance and other factors, changes in development plans and production. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods and this pro forma estimate should not be construed as indicative of our development plans or future results.

The ceiling calculation is not intended to be indicative of the fair market value of our proved reserves or future results.  Impairment charges do not affect cash flow from operating activities but do adversely affect our net income and stockholders’ equity.  Any recorded impairment of oil and natural gas properties is not reversible at a later date.

25

U.S. Leaseholds

As of July 31, 2015, we have leased approximately 221,032 gross and 107,326 net acres in the Williston Basin, with approximately 191,150 gross and 78,961 net acres in our core focus area located predominantly in McKenzie and Williams Counties, North Dakota, and eastern Roosevelt and Sheridan Counties, Montana. The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases:

	DevelopedAcres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
North Dakota	160,084	62,351	20,336	7,289	180,420	69,640
Montana	6,662	6,190	33,950	31,496	40,612	37,686
Total Williston Basin	166,746	68,541	54,286	38,785	221,032	107,326

Summary of Operating Results

The following table reflects the components of our production volumes, average realized prices, oil, natural gas and natural gas liquids revenues, and operating expenses for the periods indicated. No pro forma adjustments have been made for the acquisitions and divestitures of oil and natural gas properties, which will affect the comparability of the data below. The information set forth below is not necessarily indicative of future results.

	For the Three Months Ended				For the Six Months Ended
	July 31				July 31
Oil and Natural Gas Operations	2014		2015		2014		2015
Production volumes:
Crude oil (Mbbls)		837		1,015		1,435		2,040
Natural gas (MMcf)		494		751		935		1,491
Natural gas liquids (Mbbls)		51		102		103		181
Total barrels of oil equivalent (Mboe)		970		1,242		1,694		2,470
Average daily production volumes (Boe/d)		10,543		13,500		9,359		13,646
Average realized prices:
Crude oil ($ per Bbl)	$	90.78	$	51.71	$	90.82	$	47.52
Natural gas ($ per Mcf)	$	5.49	$	2.56	$	6.77	$	2.89
Natural gas liquids ($ per Bbl)	$	35.29	$	8.36	$	45.12	$	9.96
Total average realized price ($ per Boe)	$	82.94	$	44.50	$	83.42	$	41.72
Oil, natural gas and natural gas liquids revenues (in thousands):
Crude oil	$	75,983	$	52,490	$	130,355	$	96,932
Natural gas		2,711		1,920		6,333		4,306
Natural gas liquids		1,812		853		4,652		1,803
Total oil, natural gas and natural gas liquids revenues	$	80,506	$	55,263	$	141,340	$	103,041
Operating expenses (in thousands):
Lease operating expenses	$	6,698	$	11,369	$	11,424	$	22,278
Gathering, transportation and processing		3,733		6,641		7,535		12,989
Production taxes		8,677		5,449		15,025		10,236
Oil and natural gas amortization expense		23,429		24,213		42,139		52,906
Impairment of oil and natural gas properties		—		206,000		—		398,000
Accretion of asset retirement obligations		40		90		65		147
Total operating expenses	$	42,577	$	253,762	$	76,188	$	496,556
Operating expenses per Boe:
Lease operating expenses	$	6.91	$	9.15	$	6.74	$	9.02
Gathering, transportation and processing	$	3.85	$	5.35	$	4.45	$	5.26
Production taxes	$	8.95	$	4.39	$	8.87	$	4.14
Oil and natural gas amortization expense	$	24.15	$	19.50	$	24.88	$	21.42

26

Comparison of Quarter Ended July 31, 2015 to Quarter Ended July 31, 2014

Oil, Natural Gas and Natural Gas Liquids Revenues.  Revenues from oil, natural gas and natural gas liquids for the three months ended July 31, 2015 decreased 31% to $55.3 million from $80.5 million for the three months ended July 31, 2014. Total production increased 28% due to our drilling and completion program. This increase in production was offset by a 46% decrease in weighted average realized prices from $82.94 per Boe for the three months ended July 31, 2014 to $44.50 per Boe for the three months ended July 31, 2015.

Lease Operating Expenses. Lease operating expense increased to $9.15 per Boe for the three months ended July 31, 2015 from $6.91 per Boe for the three months ended July 31, 2014. The cost increase is primarily the result of increased workover expenses and higher produced water disposal costs. We expect that lease operating expenses on a per Boe basis will continue to be higher in fiscal year 2016 than the prior year due to the decrease in our drilling and completion program compared to fiscal year 2015.

Gathering, Transportation and Processing. Gathering, transportation and processing expenses increased to $5.35 per Boe for the three months ended July 31, 2015 compared to $3.85 per Boe for the three months ended July 31, 2014.  We began transporting and processing our oil, natural gas, and natural gas liquids through Caliber’s facilities in fiscal year 2015. We often receive higher average realized prices by using Caliber’s facilities, partly offset by higher gathering, transportation, and process expenses.  We expect future expenses on a per Boe basis to be similar to those incurred to date in fiscal year 2016.

Production Taxes.  Production taxes decreased 37% in the second quarter of fiscal year 2016 to $5.4 million from $8.7 million for the second quarter of fiscal year 2015. The 31% decrease in oil, natural gas and natural gas liquids revenues for the three months ended July 31, 2015 versus the three months ended July 31, 2014 is the primary reason for the decrease.

Oil and Natural Gas Amortization.  Oil and natural gas amortization expense increased 3% to $24.2 million for the three months ended July 31, 2015 from $23.4 million for the three months ended July 31, 2014. On a per Boe basis, our oil and natural gas amortization expense decreased by $4.65 from $24.15 for the three months ended July 31, 2014 to $19.50 for the three months ended July 31, 2015 primarily due to the impairment recorded in the first quarter of fiscal year 2016.

Impairment Expense.During the second quarter of fiscal year 2016, we recorded a $206.0 million non-cash impairment of the carrying value of our proved oil and natural gas properties as a result of the ceiling test limitation. The impairment resulted primarily from lower realized oil prices. No provision for impairment was recorded during the second quarter of fiscal year 2015.

Oilfield Services Gross Profit. We formed RockPile with the strategic objective of having both greater control over one of our largest cost centers as well as to provide locally-sourced, high-quality completion services to TUSA and other operators in the Williston Basin. Since formation, RockPile has been focused on procuring new oilfield and complementary well completion equipment, building physical and supply chain infrastructure in North Dakota, recruiting and training employees, and establishing third-party customers. RockPile’s results of operations are affected by a number of variables including drilling and stimulation activity, pricing environment, service performance, equipment utilization, and the ability to secure and retain third-party customers. Pressure pumping direct costs include the cost of chemicals and proppant, labor (wages and benefits), logistics expenses, insurance, repairs and maintenance, and safety costs. Cost of goods sold as a percentage of revenue will vary based upon the pricing environment, completion design and equipment utilization.

For the three months ended July 31, 2015, RockPile performed hydraulic fracturing, cased-hole wireline, pressure pumping and workover services for TUSA and 9 third-party customers. Equipment utilized to perform these services consisted of four spreads, six wireline trucks, and five workover rigs. RockPile has increased its base of third-party customers; however, the competitive oilfield services pricing environment resulted in a 11% decrease in consolidated oilfield services revenues from $61.5 million for the three months ended July 31, 2014 to $54.5 million for the three months ended July 31, 2015. Hydraulic fracturing services resulted in 48 total well completions (9 for TUSA and 39 for third-parties) for the three months ended July 31, 2015 compared to 34 total well completions (15 for TUSA and 19 for third-parties) for the three months ended July 31, 2014.

27

The current competitive oilfield services pricing environment has resulted in a negative gross profit of $1.0 million for the quarter ended July 31, 2015 compared to a gross profit of $14.8 million for the quarter ended July 31, 2014, after eliminations of $5.3 million and $13.7 million of intercompany gross profit, respectively. We expect that the oilfield services pricing environment will continue to be very competitive as long as oil and natural gas prices remain near current levels, resulting in compressed or negative gross profits compared to the prior year.

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

	For the Three Months Ended July 31, 2014						For the Three Months Ended July 31, 2015
(inthousands)	OilfieldServices		Eliminations		Consolidated		OilfieldServices		Eliminations		Consolidated
Revenues
Oilfield services	$	102,055	$	(40,572)	$	61,483	$	69,431	$	(14,961)	$	54,470
Total revenues		102,055		(40,572)		61,483		69,431		(14,961)		54,470
Cost of sales
Oilfield services		68,867		(25,313)		43,554		56,353		(8,396)		47,957
Depreciation		4,690		(1,609)		3,081		8,718		(1,236)		7,482
Total cost of sales		73,557		(26,922)		46,635		65,071		(9,632)		55,439
Gross profit	$	28,498	$	(13,650)	$	14,848	$	4,360	$	(5,329)	$	(969)

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

	For the Three Months Ended July 31, 2014								For the Three Months Ended July 31, 2015
	Exploration and		Oilfield				Consolidated		Exploration and		Oilfield				Consolidated
(in thousands)	Production		Services		Corporate		Total		Production		Services		Corporate		Total
Salaries and benefits	$	1,560	$	2,922	$	2,051	$	6,533	$	584	$	3,940	$	3,045	$	7,569
Stock-based compensation		343		127		1,337		1,807		375		84		3,167		3,626
Other general and administrative		2,882		2,329		540		5,751		349		1,034		2,011		3,394
Total	$	4,785	$	5,378	$	3,928	$	14,091	$	1,308	$	5,058	$	8,223	$	14,589

Total general and administrative expenses increased $0.5 million to $14.6 million for the three months ended July 31, 2015 compared to $14.1 million for the three months ended July 31, 2014. The increase in corporate general and administrative expenses is primarily a result of increased compensation and benefit costs for personnel due to the growth of the businesses, partly offset by lower other general and administrative expenses.

Commodity Derivatives.  We have entered into commodity derivative instruments, primarily costless collars and swaps, to reduce the effect of price changes on a portion of our future oil production. Our commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. During the three months ended July 31, 2015, we recognized a gain of $25.0 million on our commodity derivative positions due to decreases in underlying crude oil prices, as compared to a loss of $0.9 million for the three months ended July 31, 2014. The fair values of the open commodity derivative instruments will continue to change in value until the transactions are settled. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time. We recorded a realized commodity derivative gain of $17.0 million in the second quarter of fiscal year 2016, as compared to a realized commodity derivative loss of $3.0 million in the second quarter of fiscal year 2015.

Income from Equity Investment. Our equity investment in Caliber consists of Class A Units and equity derivative instruments. The Company recognized a $4.5 million gain on its equity investment derivatives in the second quarter of fiscal year 2016 compared to a $7.5 million loss during the second quarter of fiscal year 2015 related to the change in the fair value of the equity investment derivatives. In addition, during the three months ended July 31, 2015, the Company recognized $1.5 million for its share of Caliber’s net income for the period.  This income was offset by $0.3 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by

28

Caliber and capitalized by the Company, resulting in recognized income of $1.2 million. During the three months ended July 31, 2014, the Company recognized $0.8 million for its share of Caliber’s net income for the period.  This income was offset by $0.6 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in recognized income of $0.2 million.

Interest Expense.  The $9.9 million in interest expense for the three months ended July 31, 2015 consists of (i) approximately $1.1 million in interest related to the TUSA credit facility, (ii) approximately $1.7 million in accrued interest related to the Convertible Note, (iii) approximately $7.2 million in interest related to the TUSA 6.75% Notes, (iv) approximately $0.8 million in interest expense associated with RockPile’s credit facility and notes payable, and (v)approximately $0.1 million in interest expense related to our other debt, all net of approximately $1.0 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. Approximately $16.6 million of interest expense and capitalized interest was paid in cash.

The $4.2 million in interest expense for the three months ended July 31, 2014 consists of (i) approximately $1.8 million in interest related to the TUSA credit facility, (ii) approximately $1.6 million in accrued interest related to our Convertible Note, (iii) approximately $1.2 million in interest related to the TUSA 6.75% Notes, and (iv) approximately $0.6 million in interest expense associated with RockPile’s credit facility and notes payable, all net of approximately $1.0 million of capitalized interest. Approximately $3.1 million of interest expense and capitalized interest was paid in cash.

Income Taxes.  We recorded a full valuation allowance against our net deferred tax assets in the first quarter of fiscal year 2016.  Therefore, we had no income tax provision for the three months ended July 31, 2015 compared to expense of $10.3 million for the three months ended July 31, 2014.

As previously noted, the carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation resulting in impairments of $192.0 million for the three months ended April 30, 2015 and $206.0 million for the three months ended July 31, 2015. These impairments resulted in Triangle having three years of cumulative historical pre-tax losses and a net deferred tax asset position. Additionally, Triangle will likely be required to recognize additional impairments of its oil and natural gas properties in future periods if oil and natural gas prices remain at current levels or continue to decline and such impairments will likely be material. Triangle also had NOLs for federal income tax purposes of $136.9 million at January 31, 2015. These losses and expected future losses were a key consideration that led Triangle to provide a valuation allowance against its net deferred tax assets as of April 30, 2015 and July 31, 2015 since it cannot conclude that it is more likely than not that its net deferred tax assets will be fully realized in future periods.

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. At each reporting period, 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. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings; sustained or continued improvements in oil prices; and taxable events that could result from one or more transactions. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

As long as the Company concludes that it will continue to have a need for a valuation allowance against its net deferred tax assets, the Company likely will not have any additional income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims or for state income taxes.

Comparison of the Six Month Period Ended July 31, 2015 to the Six Month Period Ended July 31, 2014

Oil, Natural Gas and Natural Gas Liquids Revenues.  Revenues from oil, natural gas and natural gas liquids for the six months ended July 31, 2015 decreased 27% to $103.0 million from $141.3 million for the six months ended July 31, 2014. Total production increased 46% for the six months ended July 31, 2015 compared to the six months ended July 31, 2014 due to our drilling and completion program. This increase in production was offset by a 50% decrease in weighted average realized prices from $83.42 per Boe for the six months ended July 31, 2014 to $41.72 per Boe for the six months ended July 31, 2015.

29

Lease Operating Expenses.  Lease operating expense increased to $9.02 per Boe for the six months ended July 31, 2015 from $6.74 per Boe for the six months ended July 31, 2014. The cost increase is primarily the result of increased workover expenses and higher produced water disposal costs. We expect that lease operating expenses on a per Boe basis will continue to be higher in fiscal year 2016 than the prior year due to the decrease in our drilling and completion program compared to fiscal year 2015.

Gathering, Transportation and Processing. Gathering, transportation and processing expenses increased to $5.26 per Boe for the six months ended July 31, 2015 compared to $4.45 per Boe for the six months ended July 31, 2014. We often receive higher average realized prices by using Caliber’s facilities, partly offset by higher gathering, transportation, and process expenses.  We expect future expenses on a per Boe basis to be similar to those incurred to date in fiscal year 2016.

Production Taxes.  Production taxes decreased 32% in the first six months of fiscal year 2016 to $10.2 million from $15.0 million for the first six months of fiscal year 2015. The 27% decrease in oil, natural gas and natural gas liquids revenues for the six months ended July 31, 2015 versus the six months ended July 31, 2014 is the primary reason for the decrease.

Oil and Natural Gas Amortization.  Oil and natural gas amortization expense increased 26% to $52.9 million for the six months ended July 31, 2015 from $42.1 million for the six months ended July 31, 2014. The increase is primarily related to increased production in the first six months of fiscal year 2016 as compared to the first six months of fiscal year 2015. On a per Boe basis, our oil and natural gas amortization expense decreased by $3.46 from $24.88 for the six months ended July 31, 2014 to $21.42 for the six months ended July 31, 2015 primarily due to increases in proved reserves from successful development and field extensions, and to the impairment recorded in the first quarter of fiscal year 2016.

Impairment Expense. During the first six months of fiscal year 2016, we recorded a $398.0 million non-cash impairment of the carrying value of our proved oil and natural gas properties as a result of the ceiling test limitation. The impairment resulted primarily from lower realized oil prices. No provision for impairment was recorded during the first six months of fiscal year 2015.

Oilfield Services Gross Profit.  For the six months ended July 31, 2015, RockPile performed hydraulic fracturing, cased-hole wireline, pressure pumping and workover services for TUSA and 14 third-party customers. Equipment utilized to perform these services consisted of four spreads, six wireline trucks, and five workover rigs. RockPile has increased its base of third-party customers, and consolidated oilfield services revenues increased 24% from $100.4 million for the six months ended July 31, 2014 to $125.0 million for the six months ended July 31, 2015. Hydraulic fracturing services resulted in 103 total well completions (14 for TUSA and 89 for third-parties) for the six months ended July 31, 2015 compared to 60 total well completions (24 for TUSA and 36 for third-parties) for the six months ended July 31, 2014.

The current competitive oilfield services pricing environment has resulted in a negative gross profit of $3.3 million for the six months ended July 31, 2015 compared to a gross profit of $23.7 million for the six months ended July 31, 2014, after eliminations of $8.2 million and $18.9 million of intercompany gross profit, respectively. We expect that the oilfield services pricing environment will continue to be very competitive as long as oil and natural gas prices remain near current levels, resulting in compressed or negative gross profits compared to the prior year.

The table below summarizes the RockPile contribution to our consolidated results for the six months ended July 31,  2014 and 2015:

	For the Six Months Ended July 31, 2014						For the Six Months Ended July 31, 2015
(in thousands)	Oilfield Services		Eliminations		Consolidated		Oilfield Services		Eliminations		Consolidated
Revenues
Oilfield services	$	163,487	$	(63,056)	$	100,431	$	150,025	$	(25,045)	$	124,980
Total revenues		163,487		(63,056)		100,431		150,025		(25,045)		124,980
Cost of sales
Oilfield services		112,578		(41,314)		71,264		126,939		(14,756)		112,183
Depreciation		8,280		(2,809)		5,471		18,207		(2,066)		16,141
Total cost of sales		120,858		(44,123)		76,735		145,146		(16,822)		128,324
Gross profit	$	42,629	$	(18,933)	$	23,696	$	4,879	$	(8,223)	$	(3,344)

30

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

	For the Six Months Ended July 31, 2014								For the Six Months Ended July 31, 2015
	Explorationand		Oilfield				Consolidated		Exploration and		Oilfield				Consolidated
(in thousands)	Production		Services		Corporate		Total		Production		Services		Corporate		Total
Salaries and benefits	$	2,801	$	5,660	$	4,333	$	12,794	$	925	$	8,769	$	6,298	$	15,992
Stock-based compensation		738		217		2,860		3,815		696		135		5,303		6,134
Other general and administrative		4,419		4,688		1,776		10,883		756		2,831		3,735		7,322
Total	$	7,958	$	10,565	$	8,969	$	27,492	$	2,377	$	11,735	$	15,336	$	29,448

Total general and administrative expenses increased $1.9 million to $29.4 million for the six months ended July31, 2015 compared to $27.5 million for the six months ended July 31, 2014. The increase in corporate general and administrative expenses is primarily a result of increased compensation and benefit costs for personnel due to the growth of the businesses, partly offset by lower other general and administrative expenses.

Commodity Derivatives.  We have entered into commodity derivative instruments, primarily costless collars and swaps, to reduce the effect of price changes on a portion of our future oil production. Our commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. During the six months ended July 31, 2015, we recognized a gain of $11.1 million on our commodity derivative positions due to decreases in underlying crude oil prices, as compared to a loss of $6.4 million for the six months ended July 31, 2014. The fair values of the open commodity derivative instruments will continue to change in value until the transactions are settled. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time. We recorded a realized commodity derivative gain of $36.5 million in the first six months of fiscal year 2016, as compared to a realized commodity derivative loss of $3.8 million in the first six months of fiscal year 2015.

Income from Equity Investment.  Our equity investment in Caliber consists of Class A Units and equity derivative instruments. The Company recognized a $4.5 million gain on its equity investment derivatives in the first six months of fiscal year 2016 compared to a $2.9 million gain during the first six months of fiscal year 2015 related to the change in the fair value of the equity investment derivatives. In addition, during the six months ended July 31, 2015, the Company recognized $1.9million for its share of Caliber’s net income for the period. This income was offset by $0.5 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in recognized income of $1.4 million. During the six months ended July 31, 2014, the Company recognized $0.9 million for its share of Caliber’s net income for the period. This income was offset by $0.8 million of intra-company gross profit recorded as a reduction of Triangle’s capitalized well costs attributable to services provided by Caliber and capitalized by the Company, resulting in a recognized income of $0.1 million. In addition, we recognized a gain in the first six months of fiscal year 2016 of $2.9 million related to Caliber’s issuance of 2,720,000 Class A Units to FREIF.  

Interest Expense.  The $19.0 million in interest expense for the six months ended July 31, 2015 consists of (i) approximately $2.0 million in interest related to the TUSA credit facility, (ii) approximately $3.4 million in accrued interest related to the Convertible Note, (iii) approximately $14.5 million in interest related to the TUSA 6.75% Notes, (iv) approximately $1.6 million in interest expense associated with RockPile’s credit facility and notes payable, and (v)approximately $0.2 million in interest expense related to our other debt, all net of approximately $2.7 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. Approximately $18.8 million of interest expense and capitalized interest was paid in cash.

The $6.9 million in interest expense for the six months ended July 31, 2014 consists of (i) approximately $3.1 million in interest related to the TUSA credit facility, (ii) approximately $3.3 million in accrued interest related to our Convertible Note, (iii) approximately $1.2 million in interest related to the TUSA 6.75% Notes and (iv) approximately $1.1 million in interest expense associated with RockPile’s credit facility and notes payable, all net of approximately $1.8 million of capitalized interest. Approximately $4.7 million of interest expense and capitalized interest was paid in cash.

31

Income Taxes.  As noted above, we recorded a full valuation allowance against our net deferred tax assets in the first six months of fiscal year 2016, and we recognized a benefit of $53.4 million compared to an expense of $20.4 million for the six months ended July 31, 2014.

Liquidity and Capital Resources

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

In the first six months of fiscal year 2016, our average realized price for oil was $47.52 per barrel, a decrease of 48% over the average realized price for the first six months of fiscal year 2015. This reflected the dramatic decrease in the price of oil that occurred over the second half of fiscal year 2015 and has continued through the first six months of fiscal year 2016. Future prices for oil will likely continue to fluctuate due to supply and demand factors, seasonality and other geopolitical and economic factors. We manage the impact that volatility in commodity prices has on our liquidity by periodically hedging a portion of our oil production to mitigate our potential exposure to price declines and maintaining flexibility in our capital investment program.

As of July 31, 2015, we had cash of approximately $45.9 million consisting primarily of cash held in bank accounts, as compared to approximately $67.9 million at January 31, 2015. At July 31, 2015, we also had available borrowing capacity of $177.7 million under the TUSA credit facility and $63.1 million under the RockPile credit facility.

As of July 31, 2015, we had approximately $837.7 million of debt outstanding, consisting of $425.9 million for the TUSA 6.75% Notes, $139.3 million for the Convertible Note, $172.3 million for the TUSA credit facility, $86.9 million for the RockPile credit facility, and $13.3 million for other notes and mortgages.

Cash Flows

The following is a summary of our changes in cash and cash equivalents for the six months ended July 31, 2014 and 2015:

	For the Six Months Ended July 31,
(inthousands)	2014		2015
Net cash provided by operating activities	$	61,846	$	80,045
Net cash used in investing activities		(308,448)		(135,827)
Net cash provided by financing activities		272,379		33,781
Net increase (decrease) in cash and equivalents	$	25,777	$	(22,001)

Net Cash Provided by Operating Activities.  Cash flows provided by operating activities were $80.0 million for the six months ended July 31, 2015, compared to $61.8 million for the six months ended July 31, 2014. Cash flows from operating activities were unfavorably impacted in the six months ended July 31, 2015 by lower realized oil prices and the competitive oilfield services pricing environment compared to the six months ended July 31, 2014, offset by favorable changes in current assets and current liabilities in the six months ended July 31, 2015.

Net Cash Used in Investing Activities.  During the six months ended July 31, 2015, we used $135.8 million in cash in investing activities compared to $308.4 million during the six months ended July 31, 2014. During the six months ended July 31, 2015 and 2014, we used $128.7 million and $149.5 million, respectively, on oil and natural gas property expenditures and $0.2 million and $131.4 million, respectively, to acquire oil and natural gas properties. During the six months ended July 31, 2015 and 2014, we also spent $8.7 million and $24.6 million, respectively, on purchases of oilfield services equipment and $4.2 million and $3.1 million, respectively, on other property and equipment, primarily facility construction and improvements. During the six months ended July 31, 2015, we received net proceeds of $6.0 million from the sale of a salt water disposal well to Caliber.

32

Net Cash Provided by Financing Activities.Cash flows provided by financing activities for the six months ended July 31, 2015 totaled $33.8 million, as compared to $272.4 million for the six months ended July 31, 2014. Our primary source of cash from financing activities during the six months ended July 31, 2015 came from $35.0 million in net borrowings from our credit facilities. Our primary financing activities during the six months ended July 31, 2014 included the issuance of $450.0 million of the TUSA 6.75% Notes and net repayments on our credit facilities of $164.9 million.

Capital Requirements Outlook

Our cash flows from operations for the first six months of fiscal year 2016 were insufficient to cover our capital requirements, and we continued to rely on external financing activities. We believe that the lag time between initial investment and cash flows from such investment is typical of the oil and natural gas industry where upfront costs are significant and cash flows are delayed. This holds true across our businesses, including drilling and completion costs for TUSA and equipment costs for RockPile. While we are not obligated to fund any further equity commitment for Caliber, the lag time between investment in operations and cash flows is exacerbated in the midstream space where initial construction costs and project timelines are substantial. In a higher oil and natural gas pricing environment such as we experienced in recent years, we expect that our cash flows from operations would increase significantly as additional TUSA oil and natural gas wells commence production, RockPile’s oilfield services increase, and Caliber’s gathering and processing system becomes more fully utilized. However, we expect that current depressed oil and natural gas prices, which have temporarily deferred our drilling program and created a very competitive oilfield services market, will continue to limit our cash flows from operations in upcoming quarters compared to the same periods in fiscal year 2015.

In response to the current oil and natural gas pricing environment, we have significantly reduced capital expenditures, and we may further adjust such expenditures as market dynamics warrant. We will likely remain dependent on borrowings under our credit facilities and, to a lesser extent, potential additional financings to fund the difference between cash flows from operations and our capital expenditures budget and other contractual commitments. Although we expect that our operating cash flows and availability under our credit facilities will be largely sufficient for our capital requirements, any additional shortfall may be financed through additional debt or equity instruments. There can be no assurance that we will achieve our anticipated future cash flows from operations, that credit will be available when needed, or that we would be able to complete alternative transactions in the capital markets if needed.

We may continue to pursue significant acquisition opportunities, which may require additional financing. Our ability to obtain additional financing on commercially reasonable terms is dependent on a number of factors, many of which we cannot control, including changes in our credit rating, interest rates, market perceptions of us and the oil and natural gas industry, and tax burdens due to new tax laws.

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

Sources of Capital

Cash flows from operations.  Our produced volumes have increased significantly over the past three years as a result of the successful development of our operated properties. However, due to the current depressed oil and natural gas pricing environment, we have temporarily deferred our drilling program, and we plan to delay the completion of certain wells subject to a number of factors, including the price of oil and natural gas at the time, oilfield services and materials costs, and the availability of third party work for RockPile. Consequently, our production volume growth is expected to slow throughout the remainder of fiscal year 2016, and the benefit we receive from any increased production is likely to be less than it was in comparable periods of fiscal year 2015 due to lower realized prices. If oil and natural gas prices recover sufficiently during the remainder of fiscal year 2016, we may increase drilling and completion expenditures, which we expect would increase production volumes and cash flows from operations.

Cash flows from our oilfield services segment decreased significantly in the first six months of fiscal year 2016 primarily due to efforts to remain competitive in the current oil and natural gas pricing environment by significantly

33

reducing fees that RockPile charges to its customers. As a result of the margin compression on fees charged for services, as well as the likelihood for lower utilization of RockPile services by customers slowing the pace of their development operations, we anticipate that RockPile’s cash flows from operations throughout the remainder of fiscal year 2016 will be substantially lower than comparable periods in fiscal year 2015.

Credit facilities.As of July 31, 2015, our maximum credit available under the TUSA credit facility was $1.0 billion, subject to a borrowing base of $350.0 million. As of July 31, 2015, we had $177.7 million of borrowing capacity available. The borrowing base under the TUSA credit facility is subject to redetermination on a semi-annual basis by May 1 and November 1. In addition, each of TUSA and the lenders may request an unscheduled borrowing base redetermination twice during each calendar year. We anticipate limited, if any, borrowing base growth in fiscal year 2016, and our borrowing base may be further reduced if oil and natural gas prices do not rebound. As of July 31, 2015, our maximum credit available under the RockPile credit facility was $150.0 million, and we had $63.1 million of borrowing capacity available. Notwithstanding a potential additional borrowing base reduction under the TUSA credit facility, we expect that the substantial borrowing capacity available under our credit facilities will be sufficient to finance any difference between our cash flows from operations and our anticipated capital expenditures.

Securities Offerings.Historically, we have financed our operations, property acquisitions and other capital investments in part from the proceeds of public and private offerings of our equity and debt securities. We may from time to time offer debt securities, common stock, preferred stock, warrants and other securities, or any combination of such securities, in amounts, at prices and on terms announced when and if the securities are offered. The specifics of any future public offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus or a prospectus supplement at the time of such offering.

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

Commodity Derivative Instruments

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

Working Capital

As part of our cash management strategy, we periodically use available funds to reduce amounts borrowed under our credit facilities. However, due to certain restrictive covenants contained in our credit facilities regarding our ability to dividend or otherwise transfer funds from the borrower to Triangle, we seek to maintain sufficient liquidity at Triangle to manage foreseeable and unforeseeable consolidated cash requirements. Since our principal source of operating cash flows (proved reserves to be produced in later periods) is not considered working capital, we often have low or negative working capital. Our working capital was $6.9 million as of July 31, 2015, as compared to $37.7 million at January 31, 2015.

Off-Balance Sheet Arrangements

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

34

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk.  Our primary market risk is related to changes in oil prices. The market price of oil has been highly volatile and is likely to continue to be highly volatile in the future, which will impact our prospective revenues from the sale of products or properties. Currently, we utilize swaps and costless collars to reduce the effect of price changes on a portion of our future oil production. We do not enter into derivative instruments for trading purposes. For accounting purposes, we mark our derivatives to fair value and recognize the changes in fair value under the gain (loss) from derivative activities line on the consolidated statements of operations.

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

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

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

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

	Contract		Quantity	Weighted Average		Weighted Average		Weighted Average
	Type	Basis (1)	(Bbl/d)	Put Strike		Call Strike		Price
August 1, 2015 to January 31, 2016	Collar	NYMEX	2,739	$	85.45	$	98.20
August 1, 2015 to January 31, 2016	Swap	NYMEX	1,755					$	60.22
February 1, 2016 to January 31, 2017	Swap	NYMEX	2,746					$	60.23

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

In August 2015, the Company unwound certain commodity derivative swap contracts and realized a gain of $9.3 million.  The early settled contracts were for 2,000 barrels of oil per day at an average fixed price of $60.34 for the period from January 1, 2016 to December 31, 2016.

We have elected not to apply cash flow hedge accounting to any of our derivative transactions and we therefore recognize mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income for those commodity derivatives that would qualify as cash flow hedges.

All derivative instruments are recorded on the balance sheet at fair value.  Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date.  Changes in the fair value of derivatives are recorded in commodity derivative (gains) losses on the consolidated statements of operations.  As of July 31, 2015, the fair value of our commodity derivatives was a net asset of $29.4 million.  An assumed increase of 10% in the forward commodity prices used in the July 31, 2015 valuation of our derivative instruments would result in a net derivative asset of approximately $20.7 million at July 31, 2015. Conversely, an assumed decrease of 10% in forward commodity prices would result in a net derivative asset of approximately $37.9 million at July31, 2015.

35

Interest Rate Risk.  As of July 31, 2015, we had $350.0 million of borrowing availability under the TUSA credit facility, of which $172.3 million was drawn at quarter-end. The credit facility bears interest at variable rates. Assuming we had the maximum amount outstanding at July 31, 2015 under the TUSA credit facility of $350.0 million, a 1.0% increase in interest rates would result in additional annualized interest expense of $3.5 million.

As of July 31, 2015, RockPile had an aggregate of $150.0 million available for borrowing under its credit facility of which approximately $86.9 million of principal was outstanding as of such date. The credit facility bears interest at variable rates. Assuming RockPile had the maximum amount outstanding at July 31, 2015 under the credit facility of $150.0 million, a 1.0% interest rate increase would result in additional annualized interest expense of approximately $1.5 million.

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

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of Jonathan Samuels, our President and Chief Executive Officer, and Justin Bliffen, our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of July31, 2015. Based on the evaluation, those officers believe that:

· our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and

· our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 was accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during the quarterly period ended July 31, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

36

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.

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

Item 1A.  Risk Factors.

There have been no material changes to the risk factors set forth in our Fiscal 2015 Form 10-K. Those risks, in addition to the other information set forth in this Quarterly Report on Form 10-Q and in our other filings with the SEC, could materially affect our business, financial condition or results of operations. Additional risks and uncertainties not currently known to us or that we deem to be immaterial could also materially adversely affect our business, financial condition or results of operations.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

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

						Maximum number
					Total number of	of shares that may
	Total Number		Average		shares purchased	yet be purchased
	of Shares		Price Paid		as part of publicly	under the plans
	Purchased		Per Share		announced plans (2)	at month end
May 1, 2015 to May 31, 2015	32,896		$	5.51	—	5,160,820	(3)
June 1, 2015 to June 30, 2015	5,524			5.22	—	5,374,890	(4)
July 1, 2015 to July 31, 2015	13,264			4.18	—	5,374,890
	51,684	(1)	$	5.14	—

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

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

(3) Includes the number of shares of common stock remaining available for repurchase pursuant to Tranche 2, plus the number of shares of common stock available for repurchase pursuant to Tranche 3 based on the paid-in-kind interest 37

accrued on the Convertible Note as of June 30, 2015. All shares of common stock authorized for repurchase under Tranche 1 have been exhausted.

(4) Includes an additional 214,070 shares of common stock potentially issuable pursuant to the paid-in-kind interest added to the principal balance of the Convertible Note on June 30, 2015.

Item 3.  Defaults Upon Senior Securities.

None.

Item 4.  Mine Safety Disclosures.

Not Applicable.

Item 5.  Other Information.

Not Applicable.

38

Item 6. Exhibits

3.1	Certificate of Incorporation of Triangle Petroleum Corporation, filed as Exhibit 3.1 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 17, 2014 and incorporated herein by reference.
3.2	Certificate of Amendment to the Certificate of Incorporation of Triangle Petroleum Corporation, filed as Exhibit 3.2 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on April 17, 2014 and incorporated herein by reference.
3.3	Bylaws of Triangle Petroleum Corporation, filed as Exhibit 3.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2012 and incorporated herein by reference.
31.1*	Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document

* Filed herewith.

39

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

TRIANGLE PETROLEUM CORPORATION
Date:  September 8,  2015	By:	/s/ JONATHAN SAMUELS
	Jonathan Samuels
	President and Chief Executive Officer

USTIN,  2015
Date:  September 8,  2015	By:	/s/ JUSTIN BLIFFEN
	Justin Bliffen
	Chief Financial Officer

40

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Jonathan Samuels, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Triangle Petroleum Corporation;

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

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

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

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

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

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

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

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

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

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

Date:September 8, 2015

/s/ JONATHAN SAMUELS

Jonathan Samuels

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Justin Bliffen, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Triangle Petroleum Corporation;

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

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

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

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

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

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

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

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

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

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

Date:September 8, 2015

/s/ JUSTIN BLIFFEN

Justin Bliffen

Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATIONS OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER

PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

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

Date: September 8, 2015	By:	/s/JONATHAN SAMUELS
	Name:	Jonathan Samuels
	Title:	President and Chief Executive Officer

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

Ju
Date: September 8, 2015	By:	/s/ JUSTIN BLIFFEN
	Name:	Justin Bliffen
	Title:	Chief Financial Officer

XML

Long-term Debt - Rockpile credit facility - (Details) - Rockpile [Member] - USD ($) $ in Millions	6 Months Ended
	Jul. 31, 2015	Nov. 13, 2014	Mar. 25, 2014
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity			$ 100.0
Federal Funds Rate [Member]
Debt Instrument [Line Items]
Credit facility, basis spread on interest rate	0.50%
Eurodollar Rate Plus 1% [Member]
Debt Instrument [Line Items]
Credit facility, margin on dollar amount based on usage	1.00%
Letter of Credit [Member]
Debt Instrument [Line Items]
Credit facility, fronting fee percentage	0.125%
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity		$ 150.0
Maximum [Member]
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Maximum [Member] | Eurodollar Rate Plus 1% [Member]
Debt Instrument [Line Items]
Credit facility, basis spread on interest rate	2.25%
Maximum [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Credit facility, basis spread on interest rate	3.25%
Minimum [Member]
Debt Instrument [Line Items]
Commitment fee percentage	0.375%
Minimum [Member] | Eurodollar Rate Plus 1% [Member]
Debt Instrument [Line Items]
Credit facility, basis spread on interest rate	1.50%
Minimum [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Credit facility, basis spread on interest rate	2.50%

XML

Fair Value Measurements - Assets and liabilities table - (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jul. 31, 2015	Jan. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Rockpile earn-out liability	$ (1,242)	$ (1,825)
Equity Investment Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	5,020
Crude Oil Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	29,366
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Rockpile earn-out liability	(1,242)	$ (1,825)
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	29,366
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	$ 5,020

XML

Equity Investment And Equity Investment Derivatives - Equity investment activity summary (Details) - Jul. 31, 2015 - USD ($) $ in Thousands	Total
Schedule of Equity Method Investments [Line Items]
Equity investment, Beginning balance	$ 64,411
Gain on Caliber capital transactions	2,880
Equity investment, Ending balance	73,709
Caliber Midstream Partners, L.P. [Member]
Schedule of Equity Method Investments [Line Items]
Equity investment, Beginning balance	64,411
Equity investment share of net income before intra-company profit eliminationsr	1,902
Change in fair value of warrants	4,516
Gain on Caliber capital transactions	2,880
Equity investment, Ending balance	73,709
Fair value of warrants	$ 5,020

XML

Fair Value Measurements - Debt instruments carrying value - (Details) - USD ($) $ in Thousands	Jul. 31, 2015	Jan. 31, 2015	Jul. 18, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
5% convertible note, carrying value	$ 139,295	$ 135,877
Convertible note	136,361	137,790
Long-term portion of credit facilities	259,192	224,159
Revolving credit facilities, carrying value	259,192	224,159
Revolving credit facilities, fair value	259,192	224,159
TUSA 6.75% notes, carrying value	425,889	429,500
TUSA 6.75% notes, fair value	317,293	303,871
Other notes and mortgages payable, carrying value	13,364	10,605
Other notes and mortgages payable, fair value	$ 13,364	$ 10,605
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 6.75% Notes [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt instrument, interest rate	6.75%	6.75%	6.75%

XML

Equity Investment And Equity Investment Derivatives - Equity Investment - (Details) - USD ($)		6 Months Ended
	Feb. 02, 2015	Jul. 31, 2015	Jan. 31, 2015
Schedule of Equity Method Investments [Line Items]
Gain on Caliber capital transactions		$ 2,880,000
Caliber Midstream Partners, L.P. [Member]
Schedule of Equity Method Investments [Line Items]
Gain on Caliber capital transactions		2,880,000
Class A Units [Member] | Caliber Midstream Partners, L.P. [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, units held		7,000,000	$ 7,000,000
Class A Units [Member] | Caliber Midstream Partners, L.P. [Member] | FREIF Caliber Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Capital contributions	$ 34,000,000
Equity method investments, Class A Units received	2,720,000
Equity method investments, units held		$ 17,720,000
Equity method ownership percentage		71.70%
Equity method investments, warrants received		906,667
Class A Units [Member] | Caliber Midstream Partners, L.P. [Member] | Triangle Caliber Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Capital contributions	$ 0
Equity method investments, units held		$ 7,000,000
Equity method ownership percentage		28.30%
Equity method investments, warrants received		3,626,667
Series 1 To 4 Warrants [Member] | Caliber Midstream Partners, L.P. [Member] | Triangle Caliber Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, warrants received		2,357,334
Series 6 Warrants [Member] | Caliber Midstream Partners, L.P. [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, units held		$ 1,269,333
Strike price		$ 12.50
Series 6 Warrants [Member] | Caliber Midstream Partners, L.P. [Member] | Triangle Caliber Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, warrants received		1,269,333
Strike price		$ 12.50

XML

Summary of Significant Accounting Policies - Earnings per Share- (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jul. 31, 2015	Jul. 31, 2014	Jul. 31, 2015	Jul. 31, 2014
Earnings Per Share, Diluted, Other Disclosures [Abstract]
Weighted Average Number Diluted Shares Outstanding Adjustment		17,602,373		17,447,130
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	10,888,828	4,500,000	10,888,828	4,500,000
Earnings Per Share Reconciliation [Abstract]
Net income	$ (193,346)	$ 14,552	$ (373,545)	$ 29,094
Effect of 5% Convertible Note conversion		996		1,983
Net income (loss) attributable to common shareholders after effect of debt conversion	$ (193,346)	$ 15,548	$ (373,545)	$ 31,077
Weighted Average Number of Shares Outstanding Reconciliation [Abstract]
Basic weighted average common shares outstanding	75,410,000	86,172,000	75,334,000	86,064,000
Effect of dilutive securities		17,602,373		17,447,130
Diluted weighted average common shares outstanding	75,410,000	103,774,000	75,334,000	103,511,000
Basic net income (loss) per share	$ (2.56)	$ 0.17	$ (4.96)	$ 0.34
Diluted net income (loss) per share	$ (2.56)	$ 0.15	$ (4.96)	$ 0.30
Anitdilutive securities excluded from calculation of diluted net income	10,888,828	4,500,000	10,888,828	4,500,000

XML

Supplemental Disclosures Of Cash Flow Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jul. 31, 2015	Jul. 31, 2014	Jul. 31, 2015	Jul. 31, 2014
Supplemental Disclosures of Cash Flow Information [Abstract]
Interest expense			$ 16,078	$ 4,717
Income taxes				550
Increase (decrease) in accounts payable and accrued liabilities			(15,770)	37,151
Capitalized stock-based compensation	$ 389	$ 310	709	649
Change in asset retirement obligations			$ 425	1,106
Notes payable issued for redemption of RockPile B units				$ 1,041

XML

Equity Investment And Equity Investment Derivatives (Tables)

6 Months Ended

Jul. 31, 2015

Equity Investment [Abstract]

Schedule Of Equity Investment In Caliber

	Expiration		Strike Price at		As of	As of
	Date		July 31, 2015		January 31, 2015	July 31, 2015
Class A Units		—	$	—	7,000,000	7,000,000
Series 1 Warrants		October 1, 2024	$	12.78	5,600,000	6,615,467
Series 2 Warrants		October 1, 2024	$	22.09	2,400,000	2,835,200
Series 3 Warrants		September 12, 2025	$	22.09	3,000,000	3,544,000
Series 4 Warrants		September 12, 2025	$	28.09	2,000,000	2,362,667
Series 6 Warrants		February 2, 2018	$	12.50	—	1,269,333

Summary of activities related to company's equity investment

	For the Six Months Ended
(in thousands)	July 31, 2015
Balance at January 31, 2015	$	64,411
Capital contributions		—
Distributions		—
Equity investment share of net income before intra-company profit eliminations		1,902
Change in fair value of warrants		4,516
Gain on Caliber capital transactions		2,880
Balance at July 31, 2015	$	73,709
Fair value of warrants at July 31, 2015	$	5,020

XML

Share-Based Compensation (Details) - USD ($) $ in Thousands, shares in Millions	3 Months Ended		6 Months Ended
	Jul. 31, 2015	Jul. 31, 2014	Jul. 31, 2015	Jul. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense before capitalized amount	$ 4,015	$ 2,117	$ 6,843	$ 4,464
Less amounts capitalized to oil and natural gas properties	(389)	(310)	(709)	(649)
Stock-based compensation, net	$ 3,626	1,807	$ 6,134	3,815
Series B Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares reserved under Plan	6.0		6.0
2014 Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares reserved under Plan	6.0		6.0
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense before capitalized amount	$ 2,584	1,503	$ 4,663	3,274
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense before capitalized amount	1,347	487	2,045	973
RockPile Stock Based Compensation Related to Series [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense before capitalized amount	$ 84	$ 127	$ 135	$ 217

XML

Hedging And Commodity Derivative Financial Instruments - Notional - (Details) $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	Aug. 31, 2015 USD ($) bbl / item $ / bbl	Jul. 31, 2015 USD ($) bbl / item $ / bbl	Jul. 31, 2014 USD ($)	Jul. 31, 2015 USD ($) bbl / item $ / bbl	Jul. 31, 2014 USD ($)
Derivative [Line Items]
Quantity, (bbls)	2,000
Notional Disclosures [Abstract]
Realized commodity derivative gains (losses) | $	$ 9,300	$ 17,016	$ (2,954)	$ 36,484	$ (3,772)
Notional amount per day (in Bbl)	2,000
Average fixed price | $ / bbl	60.34
Fiscal 2016 Collar [Member]
Derivative [Line Items]
End date				August 1, 2015 to January 31, 2016
Contract type				Collar
Basis				NYMEX
Quantity, (bbls)		2,739		2,739
Put strike price | $ / bbl		85.45		85.45
Call strike price | $ / bbl		98.20		98.20
Notional Disclosures [Abstract]
Notional amount per day (in Bbl)		2,739		2,739
Fiscal 2016 Swap [Member]
Derivative [Line Items]
End date				August 1, 2015 to January 31, 2016
Contract type				Swap
Basis				NYMEX
Quantity, (bbls)		1,755		1,755
Weighted average price | $ / bbl		60.22		60.22
Notional Disclosures [Abstract]
Notional amount per day (in Bbl)		1,755		1,755
Fiscal 2017 Swap [Member]
Derivative [Line Items]
End date				February 1, 2016 to January 31, 2017
Contract type				Swap
Basis				NYMEX
Quantity, (bbls)		2,746		2,746
Weighted average price | $ / bbl		60.23		60.23
Notional Disclosures [Abstract]
Notional amount per day (in Bbl)		2,746		2,746

XML

Long-Term Debt - Convertible note- (Details) - USD ($) $ / shares in Units, $ in Thousands	Jul. 31, 2015	Jan. 31, 2015
Debt Instrument [Line Items]
Accrued interest	$ 1,725	$ 2,250
Convertible Notes [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	5.00%	5.00%
Debt instrument, face amount	$ 120,000
Convertible note, conversion price	$ 8.00
Accrued interest	$ 19,300

XML

Share-Based Compensation - Stock options - (Details) - Jul. 31, 2015 - USD ($) $ / shares in Units, $ in Millions	Total
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options forfeited	0
Employee Stock Option [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options granted	0
Options exercised	0
Outstanding options	6,700,000
Number of shares exercisable	1,200,000
Weighted average exercise price per share	$ 11.54
Weighted average remaining contractual life (years)	7 years 10 months 6 days
Weighted average exercise price per share (exercisable)	$ 11.25
Weighted average remaining contractual life (years) (exercisable)	7 years 11 months 5 days
Unrecognized compensation cost related to awards	$ 16.5
Unrecognized compensation, recognition period	2 years 9 months 18 days
Employee Stock Option [Member] | $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	7 years 11 months 5 days
Outstanding options	750,000
Number of shares exercisable	150,000
Employee Stock Option [Member] | $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	7 years 11 months 5 days
Outstanding options	750,000
Number of shares exercisable	150,000
Employee Stock Option [Member] | $10.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price per share	$ 10.00
Remaining contractual life	7 years 11 months 5 days
Outstanding options	1,500,000
Number of shares exercisable	300,000
Employee Stock Option [Member] | $12.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price per share	$ 12.00
Remaining contractual life	7 years 11 months 5 days
Outstanding options	1,500,000
Number of shares exercisable	300,000
Employee Stock Option [Member] | $15.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price per share	$ 15.00
Remaining contractual life	7 years 11 months 5 days
Outstanding options	1,500,000
Number of shares exercisable	300,000
Employee Stock Option [Member] | $12.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price per share	$ 12.00
Remaining contractual life	6 years 1 month 13 days
Outstanding options	233,333
Employee Stock Option [Member] | $14.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price per share	$ 14.00
Remaining contractual life	6 years 1 month 13 days
Outstanding options	233,333
Employee Stock Option [Member] | $16.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Exercise price per share	$ 16.00
Remaining contractual life	9 years 1 month 13 days
Outstanding options	233,334

XML

Equity Investment And Equity Investment Derivatives - Equity investment holdings summary - (Details) - Caliber Midstream Partners, L.P. [Member] - USD ($)	Jul. 31, 2015	Jan. 31, 2015
Class A Units [Member]
Schedule of Equity Method Investments [Line Items]
Warrants held	$ 7,000,000	$ 7,000,000
Series 1 Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Strike price	$ 12.78
Warrants held	$ 6,615,467	5,600,000
Series 2 Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Strike price	$ 22.09
Warrants held	$ 2,835,200	2,400,000
Series 3 Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Strike price	$ 22.09
Warrants held	$ 3,544,000	3,000,000
Series 4 Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Strike price	$ 28.09
Warrants held	$ 2,362,667	$ 2,000,000
Series 6 Warrants [Member]
Schedule of Equity Method Investments [Line Items]
Strike price	$ 12.50
Warrants held	$ 1,269,333

XML

Segment Reporting

6 Months Ended

Jul. 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 and its subsidiaries, is responsible for a variety of oilfield and complementary well completion services for both TUSA-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 three months ended July 31, 2015 and 2014.

	For the Three Months Ended July 31, 2015
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	55,263	$	—	$	—	$	—	$	55,263
Oilfield services for third parties		—		54,830		—		(360)		54,470
Intersegment revenues		—		14,601		—		(14,601)		—
Total revenues		55,263		69,431		—		(14,961)		109,733
Expenses:
Lease operating and production taxes		16,818		—		—		—		16,818
Gathering, transportation and processing		6,641		—		—		—		6,641
Depreciation and amortization		24,527		8,718		407		(1,408)		32,244
Impairment of oil and natural gas properties		206,000		—		—		—		206,000
Accretion of asset retirement obligations		90		—		—		—		90
Cost of oilfield services		—		56,353		(1,238)		(8,396)		46,719
General and administrative, net of amounts capitalized:
Salaries and benefits		584		3,940		3,045		—		7,569
Stock-based compensation		375		84		3,167		—		3,626
Other general and administrative		349		1,034		2,011		—		3,394
Total operating expenses		255,384		70,129		7,392		(9,804)		323,101
Income (loss) from operations		(200,121)		(698)		(7,392)		(5,157)		(213,368)
Other income (expense), net		18,290		(845)		3,116		(539)		20,022
Income (loss) before income taxes	$	(181,831)	$	(1,543)	$	(4,276)	$	(5,696)	$	(193,346)

	For the Three Months Ended July 31, 2014
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	80,506	$	—	$	—	$	—	$	80,506
Oilfield services for third parties		—		64,093		—		(2,610)		61,483
Intersegment revenues		—		37,962		—		(37,962)		—
Total revenues		80,506		102,055		—		(40,572)		141,989
Expenses:
Lease operating and production taxes		15,375		—		—		—		15,375
Gathering, transportation and processing		3,733		—		—		—		3,733
Depreciation and amortization		26,287		4,690		186		(4,456)		26,707
Accretion of asset retirement obligations		40		—		—		—		40
Cost of oilfield services		—		68,867		—		(25,313)		43,554
General and administrative, net of amounts capitalized:
Salaries and benefits		1,560		2,922		2,051		—		6,533
Stock-based compensation		343		127		1,337		—		1,807
Other general and administrative		2,882		2,329		540		—		5,751
Total operating expenses		50,220		78,935		4,114		(29,769)		103,500
Income (loss) from operations		30,286		23,120		(4,114)		(10,803)		38,489
Other income (expense), net		(4,267)		(667)		(7,752)		(912)		(13,598)
Net income (loss) before income taxes	$	26,019	$	22,453	$	(11,866)	$	(11,715)	$	24,891

The following tables present selected financial information for our operating segments for the six months ended July 31, 2015 and 2014.

	For the Six Months Ended July 31, 2015
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	103,041	$	—	$	—	$	—	$	103,041
Oilfield services for third parties		—		125,920		—		(940)		124,980
Intersegment revenues		—		24,105		—		(24,105)		—
Total revenues		103,041		150,025		—		(25,045)		228,021
Expenses:
Lease operating and production taxes		32,514		—		—		—		32,514
Gathering, transportation and processing		12,989		—		—		—		12,989
Depreciation and amortization		53,826		18,207		732		(2,715)		70,050
Impairment of oil and natural gas properties		398,000		—		—		—		398,000
Accretion of asset retirement obligations		147		—		—		—		147
Cost of oilfield services		—		126,939		—		(14,756)		112,183
General and administrative, net of amounts capitalized:
Salaries and benefits		925		8,769		6,298		—		15,992
Stock-based compensation		696		135		5,303		—		6,134
Other general and administrative		756		2,831		3,735		—		7,322
Total operating expenses		499,853		156,881		16,068		(17,471)		655,331
Income (loss) from operations		(396,812)		(6,856)		(16,068)		(7,574)		(427,310)
Other income (expense), net		(2,712)		(1,720)		5,802		(1,046)		324
Income (loss) before income taxes	$	(399,524)	$	(8,576)	$	(10,266)	$	(8,620)	$	(426,986)
As of July 31, 2015:
Net oil and natural gas properties	$	871,169	$	—	$	—	$	(83,402)	$	787,767
Oilfield services equipment - net	$	—	$	79,997	$	—	$	—	$	79,997
Other property and equipment - net	$	9,194	$	21,759	$	17,872	$	—	$	48,825
Total assets	$	1,023,660	$	159,486	$	130,445	$	(103,634)	$	1,209,957
Total liabilities	$	770,143	$	130,685	$	151,669	$	(20,232)	$	1,032,265

	For the Six Months Ended July 31, 2014
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	141,340	$	—	$	—	$	—	$	141,340
Oilfield services for third parties		—		103,650		—		(3,219)		100,431
Intersegment revenues		—		59,837		—		(59,837)		—
Total revenues		141,340		163,487		—		(63,056)		241,771
Expenses:
Lease operating and production taxes		26,449		—		—		—		26,449
Gathering, transportation and processing		7,535		—		—		—		7,535
Depreciation and amortization		46,440		8,280		362		(7,088)		47,994
Accretion of asset retirement obligations		65		—		—		—		65
Cost of oilfield services		—		112,578		—		(41,314)		71,264
General and administrative, net of amounts capitalized:
Salaries and benefits		2,801		5,660		4,333		—		12,794
Stock-based compensation		738		217		2,860		—		3,815
Other general and administrative		4,419		4,688		1,776		—		10,883
Total operating expenses		88,447		131,423		9,331		(48,402)		180,799
Income (loss) from operations		52,893		32,064		(9,331)		(14,654)		60,972
Other income (expense), net		(10,834)		(1,174)		1,746		(1,266)		(11,528)
Income (loss) before income taxes	$	42,059	$	30,890	$	(7,585)	$	(15,920)	$	49,444

Certain income statement reclassifications were made as previously noted, as well as changes 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 defer recognition of oilfield services income (intersegment revenues less cost of oilfield services and related depreciation) for wells that we operate and this deferred income is credited to proved oil and natural gas properties. In addition, we eliminate our non-operating partners’ share of oilfield services income for well completion activities on properties we operate. We also defer Caliber gross profit from our share of its income associated with services it provided that 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. For the three months ended July 31, 2015 and 2014, $0.1 and $2.9 million, respectively, of the depreciation and amortization elimination relates to the Exploration and Production segment and the balance relates to the Oilfield Services segment. For the six months ended July 31, 2015 and 2014,$0.6 and $4.3 million, respectively, of the depreciation and amortization elimination relates to the Exploration and Production segment and the balance relates to the Oilfield Services segment.

These differences, as well as differing amounts for impairments, result in basis differences between the net oil and gas property amounts presented in Triangle’s financial statements compared to those presented in TUSA’s standalone financial statements.

XML

Hedging And Commodity Derivative Financial Instruments - Fair values of commodity derivatives - (Details) - USD ($) $ in Thousands	Jul. 31, 2015	Jan. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Assets	$ 29,366	$ 54,775
Crude Oil Derivative Contract [Member] | Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets	26,677	$ 54,775
Crude Oil Derivative Contract [Member] | Long-Term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Assets	$ 2,689

XML

Description of Business - (Details)	6 Months Ended
	Jul. 31, 2015 item
Basis Of Presentation [Abstract]
Number of major focus lines of business	3

XML

Supplemental Disclosures of Cash Flow Information (Tables)

6 Months Ended

Jul. 31, 2015

Supplemental Disclosures of Cash Flow Information [Abstract]

Schedule of Supplemetal Cash Flow Disclosures

	For the Six Months Ended July 31,
(in thousands)	2014		2015
Cash paid during the period for:
Interest expense	$	4,717	$	16,078
Income taxes	$	550	$	—
Non-cash investing activities:
Additions to oil and natural gas properties through:
Increase (decrease) in accounts payable and accrued liabilities	$	37,151	$	(15,770)
Capitalized stock based compensation	$	649	$	709
Change in asset retirement obligations	$	1,106	$	425
Non-cash financing activities:
Notes payable issued for redemption of RockPile Series B Units	$	1,041	$	—

XML

Related Party Transactions (Details) - Jul. 31, 2015 $ in Thousands	USD ($) item
Related Party Transaction [Line Items]
Term of gathering services agreements	5 years
Number of salt water disposal wells sold | item	1
Proceeds from sale of salt water disposal wells	$ 6,000
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
Remaining commitment	$ 336,300

XML

Oil And Natural Gas Properties - (Details) - Jun. 30, 2014 - Marathon Oil Company [Member] $ in Millions	USD ($) a
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Number of acres purchased | a	41,100
Total consideration for acquisition	$ 90.4
Net downward adjustment included in the purchase price consideration	$ 9.6

XML

Summary of Significant Accounting Policies - Consolidation (Details) $ in Thousands	3 Months Ended		6 Months Ended	12 Months Ended
	Jul. 31, 2015 USD ($)	Apr. 30, 2015 $ / MMBTU $ / bbl	Jul. 31, 2015 USD ($) $ / MMBTU $ / bbl	Jan. 31, 2015 $ / MMBTU $ / bbl
Impairment charges
Impairment of oil and natural gas properties | $	$ 206,000		$ 398,000
Minimum [Member]
Equity Method Investment, Summarized Financial Information [Abstract]
Equity method ownership percentage	20.00%		20.00%
Maximum [Member]
Equity Method Investment, Summarized Financial Information [Abstract]
Equity method ownership percentage	50.00%		50.00%
Crude Oil Reserves [Member]
Trailing 12 month simple average spot prices:
Trailing 12 Month simple average spot prices		78.58	67.65	91.22
Natural Gas Reserves [Member]
Trailing 12 month simple average spot prices:
Trailing 12 Month simple average spot prices | $ / MMBTU		3.69	3.23	4.20
Natural Gas Liquids Reserves [Member]
Trailing 12 month simple average spot prices:
Trailing 12 Month simple average spot prices		41.96	34.98	50.07

XML

Summary of Significant Accounting Policies - Oilfield Services Equipment Schedule (Details) - USD ($) $ in Thousands	Jul. 31, 2015	Jan. 31, 2015
Property, Plant and Equipment [Line Items]
Total Depreciable Assets	$ 179,435	$ 168,858
Accumulated depreciation	(54,121)	(35,189)
Depreciable assets, net	125,314	133,669
Assets not placed in service	3,508	1,247
Total oilfield service equipment and other property and equipment, net	128,822	134,916
Land [Member]
Property, Plant and Equipment [Line Items]
Total Depreciable Assets	7,888	7,888
Building And Leasehold Improvements [Member]
Property, Plant and Equipment [Line Items]
Total Depreciable Assets	35,506	33,625
Oilfield Service Equipment [Member]
Property, Plant and Equipment [Line Items]
Total Depreciable Assets	122,946	116,354
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Total Depreciable Assets	5,761	4,811
Software, Computers And Office Equipment [Member]
Property, Plant and Equipment [Line Items]
Total Depreciable Assets	6,481	5,327
Capital Leases [Member]
Property, Plant and Equipment [Line Items]
Total Depreciable Assets	$ 853	$ 853

XML

Summary Of Significant Accounting Policies

6 Months Ended

Jul. 31, 2015

Summary Of Significant Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation. These unaudited condensed 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.

Certain information and footnote disclosures normally included in our annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to SEC rules and regulations. We believe the disclosures made are adequate to make the information not misleading. We recommend that these unaudited condensed consolidated financial statements be read in conjunction with our audited consolidated financial statements and notes included in our Annual Report on Form 10-K for the fiscal year ended January 31, 2015, as filed with the SEC (“Fiscal 2015 Form 10-K”). In the opinion of management, all material adjustments considered necessary for a fair presentation of the Company’s interim results have been reflected. All such adjustments are considered to be of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results.

No condensed 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 condensed 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 unproved 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 expenses and related 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 condensed consolidated financial statements.

Principles of Consolidation. The accounts of Triangle and its wholly-owned subsidiaries are presented in the accompanying condensed consolidated financial statements. All significant 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. The investment in Caliber is accounted for utilizing the equity method of accounting.  

Oil and Natural Gas Properties. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the amortizable pool of proved properties or in unproved properties, collectively, the full cost pool. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations.

At the end of each quarterly period, we must compute a limitation on capitalized costs, which is equal to the sum of the present value of estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC (unweighted arithmetic average of commodity prices in effect on the first day of each of the previous twelve months), less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects. We then conduct a “ceiling test” that compares the net book value of the full cost pool, after taxes, to the full cost ceiling limitation. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record an impairment of our oil and natural gas properties.  

The ceiling test for each period presented was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing 12 month simple average spot prices at the first of the month for natural gas at Henry Hub (“HH”) and West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation.

	Trailing 12 Month Simple Average Spot Prices
	January 31, 2015		April 30, 2015		July 31, 2015
Oil (per Bbl)	$	91.22	$	78.58	$	67.65
Natural gas (per MMbtu)	$	4.20	$	3.69	$	3.23
Natural gas liquids (per Bbl)	$	50.07	$	41.96	$	34.98

We recognized impairments to our proved oil and natural gas properties of $206.0 million and $398.0 million for the three and six months ended July 31, 2015, respectively, primarily due to the decline in oil, natural gas and natural gas liquids prices. We did not recognize impairments to our proved oil and natural gas properties for the three and six months ended July 31, 2014. We will incur additional impairments to our oil and natural gas properties in future quarters if prices stay at current levels or decline further.  The amount of any future impairment is difficult to predict, and will depend, in part, upon future oil, natural gas and natural gas liquids prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs. The ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results.  Impairment charges do not affect cash flow from operating activities but do adversely affect our net income and stockholders’ equity.  Any recorded impairment of oil and natural gas properties is not reversible at a later date.

The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.

Oilfield Services Equipment and Other Property and Equipment.  Oilfield services equipment and other property and equipment consisted of the following as of:

(in thousands)	January 31, 2015		July 31, 2015
Land	$	7,888	$	7,888
Building and leasehold improvements		33,625		35,506
Oilfield service equipment		116,354		122,946
Vehicles		4,811		5,761
Software, computers and office equipment		5,327		6,481
Capital leases		853		853
Total depreciable assets		168,858		179,435
Accumulated depreciation		(35,189)		(54,121)
Depreciable assets, net		133,669		125,314
Assets not placed in service		1,247		3,508
Total oilfield service equipment and other property & equipment, net	$	134,916	$	128,822

Income Taxes.  The Company computes its quarterly tax provision using the effective tax rate method based on applying the anticipated annual effective rate to its year-to-date income or loss, except for discrete items. Income tax on discrete items is computed and recorded in the period in which the specific transaction occurs.

As noted above, the carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation resulting in an impairment of $398.0 million for the six months ended July 31, 2015. This impairment results in Triangle having three years of cumulative historical pre-tax losses and a net deferred tax asset position. Additionally, Triangle will likely be required to recognize additional impairments of its oil and natural gas properties in future periods if oil and natural gas prices remain at current levels or continue to decline and such impairments will likely be material. Triangle also had net operating loss carryovers (“NOLs”) for federal income tax purposes of $136.9 million at January 31, 2015. These losses and expected future losses were a key consideration that led Triangle to provide a valuation allowance against its net deferred tax assets as of April 30 and July 31, 2015 since it cannot conclude that it is more likely than not that its net deferred tax assets will be fully realized in future periods.

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. At each reporting period, 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. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

In the first quarter of fiscal year 2016 the Company recorded the benefit of reversing its net deferred tax liability. As long as the Company concludes that it will continue to have a need for a valuation allowance against its net deferred tax assets, the Company likely will not have any additional income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims or for state income taxes.

As of July 31, 2015, the Company had no unrecognized tax benefits. The Company’s management does not believe that there are any new items or changes in facts or judgments that should impact the Company’s position during the first six months of fiscal year 2016. Given the substantial net operating loss carryforwards at both the federal and state levels, neither significant interest expense nor penalties charged for any examining agents’ tax adjustments of income tax returns are anticipated, as any such adjustments would very likely only adjust net operating loss carryforwards.

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:

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
	2014		2015		2014		2015
Dilutive		17,602,373		—		17,447,130		—
Anti-dilutive shares		4,500,000		10,888,828		4,500,000		10,888,828

The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the periods presented:

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
(in thousands, except per share data)	2014		2015		2014		2015
Net income (loss) attributable to common stockholders	$	14,552	$	(193,346)	$	29,094	$	(373,545)
Effect of 5% convertible note conversion		996		—		1,983		—
Net income (loss) attributable to common stockholders after effect of 5% convertible note conversion	$	15,548	$	(193,346)	$	31,077	$	(373,545)
Basic weighted average common shares outstanding		86,172		75,410		86,064		75,334
Effect of dilutive securities		17,602		—		17,447		—
Diluted weighted average common shares outstanding		103,774		75,410		103,511		75,334
Basic net income (loss) per share	$	0.17	$	(2.56)	$	0.34	$	(4.96)
Diluted net income (loss) per share	$	0.15	$	(2.56)	$	0.30	$	(4.96)

Reclassifications.  Certain amounts in our unaudited condensed consolidated statement of operations for the three and six months ended July 31, 2014 have been reclassified to conform to the financial statement presentation for the periods ended July 31, 2015. The unaudited condensed consolidated 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 that 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.

XML

Summary of Significant Accounting Policies - Income Taxes (Details) - USD ($) $ in Thousands	6 Months Ended
	Jul. 31, 2015	Jan. 31, 2015
Summary Of Significant Accounting Policies [Abstract]
Period of pre-tax losses	3 years
Domestic net losses carried forward		$ 136,900
Unrecognized tax benefits	$ 0

XML

Long-term Debt - TUSA 6.75% Note - (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Jul. 31, 2015	Jul. 31, 2015	Jan. 31, 2015	Jul. 18, 2014
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt	$ 1,156	$ 1,156
TUSA 6.75% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, face amount				$ 450,000
Debt instrument, interest rate	6.75%	6.75%	6.75%	6.75%
Offering costs		$ 10,500
Face value of notes repurchased			$ 20,500
Repurchased amount	$ 2,500	$ 2,500	13,900
Gain (loss) on extinguishment of debt			$ 6,600
TUSA 6.75% 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 6.75% Notes [Member] | Redemption Due to Change in Control Events [Member]
Debt Instrument [Line Items]
Redemption price, percentage		101.00%

XML

Share-Based Compensation - Rockpile share based compensation - (Details) - Jul. 31, 2015 - USD ($) $ in Millions	Total
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance	5,302,000
Units forfeited	(170,000)
Outstanding, Number of Units, Ending Balance	5,132,000
Grants, Number of Vested Units	3,419,600
Grants, Number of Unvested Units	1,712,400
Series B Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum shares reserved under Plan	6,000,000
Unrecognized compensation	$ 2.3
Series B-1 Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance	2,920,000
Outstanding, Number of Units, Ending Balance	2,920,000
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
Outstanding, Number of Units, Ending Balance	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
Units forfeited	(96,000)
Outstanding, Number of Units, Ending Balance	814,000
Grants, Number of Vested Units	352,000
Grants, Number of Unvested Units	462,000
Series B-4 Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance	1,412,000
Units forfeited	(74,000)
Outstanding, Number of Units, Ending Balance	1,338,000
Grants, Number of Vested Units	117,600
Grants, Number of Unvested Units	1,220,400
Rockpile Series A Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred return on investment	8.00%
Minimum [Member] | Series B Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based awards vesting period	1 month
Maximum [Member] | Series B Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based awards vesting period	46 months

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Jul. 31, 2015	Jan. 31, 2015
CURRENT ASSETS
Cash and equivalents	$ 45,870	$ 67,871
Accounts receivable	116,159	171,911
Commodity derivatives	26,677	54,775
Other current assets	8,947	14,952
Total current assets	197,653	309,509
Oil and natural gas properties, at cost, full cost method of accounting:
Proved properties	1,302,145	1,159,584
Unproved properties and properties under development, not being amortized	112,918	142,896
Total oil and natural gas properties	1,415,063	1,302,480
Accumulated amortization	(627,296)	(176,390)
Net oil and natural gas properties	787,767	1,126,090
Oilfield services equipment - net	79,997	87,549
Other property and equipment, net	48,825	47,367
Net property, plant and equipment	916,589	1,261,006
Deferred loan costs	13,601	14,038
Equity investment	73,709	64,411
Commodity derivatives	2,689
Other	5,716	5,906
Total other assets	95,715	84,355
Total assets	1,209,957	1,654,870
CURRENT LIABILITIES
Accounts payable and accrued capital expenditures	130,698	176,182
Other accrued liabilities	57,667	73,440
Current portion of long-term debt	677	503
Interest payable	1,725	2,250
Deferred income taxes		19,467
Total current liabilities	190,767	271,842
LONG-TERM LIABILITIES
5% convertible note	139,295	135,877
Borrowings on credit facilities	259,192	224,159
TUSA 6.75% notes	425,889	429,500
Other notes and mortgages payable	12,687	10,102
Deferred income taxes		33,974
Other	4,435	4,398
Total liabilities	$ 1,032,265	$ 1,109,852
COMMITMENT AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Common stock, $0.00001 par value, 140,000,000 shares authorized; 75,174,442 and 75,327,056 shares issued and outstanding at January 31, 2015 and April 30, 2015, respectively	$ 1	$ 1
Additional paid-in capital	551,236	545,017
Retained earnings (accumulated deficit)	(373,545)
Total stockholders' equity	177,692	545,018
Total liabilities and stockholders' equity	$ 1,209,957	$ 1,654,870

XML

Oil And Natural Gas Properties - Proforma Financial Information - (Details) - Jul. 31, 2014 - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Total	Total
Acquisitions [Abstract]
Operating revenue	$ 146,559	$ 253,206
Net income (loss)	$ 15,427	$ 31,341
Earnings (loss) per common share, basic	$ 0.18	$ 0.36
Earnings (loss) per common share, diluted	$ 0.16	$ 0.32
Weighted average common shares outstanding, basic	86,172	86,064
Weighted average common shares outstanding, diluted	103,774	103,511
Pro forma depreciation, amortization and accretion expense	$ 1,300	$ 3,300

XML

Consolidated Statement of Stockholders' Equity - 6 months ended Jul. 31, 2015 - USD ($) $ in Thousands	Common Stock [Member]	Additional Paid-In Capital [Member]	Accumulated Deficit [Member]	Total
Balance at Jan. 31, 2015	$ 1	$ 545,017		$ 545,018
Balance, shares at Jan. 31, 2015	75,174,442			75,174,442
Vesting of restricted stock units (net of shares surrendered for taxes)		(624)		$ (624)
Vesting of restricted stock units (net of shares surrendered for taxes), shares	314,429
Share-based compensation		6,843		6,843
Net income (loss) for the year			$ (373,545)	(373,545)
Balance at Jul. 31, 2015	$ 1	$ 551,236	$ (373,545)	$ 177,692
Balance, shares at Jul. 31, 2015	75,488,871			75,488,871

XML

Segment Reporting - (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jul. 31, 2015 USD ($)	Jul. 31, 2014 USD ($)	Jul. 31, 2015 USD ($) segment	Jul. 31, 2014 USD ($)
Number of reportable segments | segment			2
Depreciation, Depletion and Amortization	$ 32,244	$ 26,707	$ 70,050	$ 47,994
TUSA [Member]
Depreciation, Depletion and Amortization	$ 100	$ 2,900	$ 600	$ 4,300

XML

Long-Term Debt (Tables)

6 Months Ended

Jul. 31, 2015

Long-Term Debt [Abstract]

Schedule Of Debt

(in thousands)	January 31, 2015		July 31, 2015
5% convertible note	$	135,877	$	139,295
TUSA credit facility due October 2018		119,272		172,272
RockPile credit facility due March 2019		104,887		86,920
TUSA 6.75% notes due July 2022		429,500		425,889
Other notes and mortgages payable		10,605		13,364
Total debt		800,141		837,740
Less current portion of debt:
Other notes and mortgages payable		(503)		(677)
Total long-term debt	$	799,638	$	837,063

XML

Long-Term Debt - Schedule of long term debt- (Details) - USD ($) $ in Thousands	Jul. 31, 2015	Jan. 31, 2015	Jul. 18, 2014
Debt Instrument [Line Items]
5% Convertible Note	$ 139,295	$ 135,877
Credit facility	259,192	224,159
Other notes and mortgages payable	13,364	10,605
TUSA 6.75% notes	425,889	429,500
Total debt	837,740	800,141
Other notes and mortgages payable	(677)	(503)
Total long-term debt	$ 837,063	$ 799,638
TUSA 6.75% Notes [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	6.75%	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	$ 172,272	$ 119,272
Rockpile [Member]
Debt Instrument [Line Items]
Credit facility	$ 86,920	$ 104,887

XML

Oil And Natural Gas Properties (Tables)

6 Months Ended

Jul. 31, 2015

Oil And Natural Gas Properties [Abstract]

Proforma Schedule For Oil And Natural Gas Acquisition

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

	For the Three Months Ended		For the Six Months Ended
(in thousands, except per share data)	July 31, 2014		July 31, 2014
Operating revenues	$	146,559	$	253,206
Net income (loss)	$	15,427	$	31,341
Earnings (loss) per common share
Basic	$	0.18	$	0.36
Diluted	$	0.16	$	0.32
Weighted average common shares outstanding:
Basic		86,172		86,064
Diluted		103,774		103,511

XML

Description Of Business

6 Months Ended

Jul. 31, 2015

Basis Of Presentation [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 predominantly located 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. 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.

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	Jul. 31, 2015	Jan. 31, 2015
Common stock, par value	$ 0.00001	$ 0.00001
Common stock, shares authorized	140,000,000	140,000,000
Common stock, shares issued	75,488,871	75,174,442
Common stock, shares outstanding	75,488,871	75,174,442
Convertible Notes [Member]
Debt instrument, interest rate	5.00%	5.00%
TUSA 6.75% Notes [Member]
Debt instrument, interest rate	6.75%	6.75%

XML

Related Party Transactions

6 Months Ended

Jul. 31, 2015

Related Party Transactions [Abstract]

Related Party Transactions

11.  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 in 2014. The aggregate minimum revenue commitment over the term of the agreements is $405.0 million, of which $336.3 million was outstanding at July 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.

During the six months ended July 31, 2015, TUSA sold one salt water disposal well to an affiliate of Caliber for net proceeds of $6.0 million.

XML

Document And Entity Information - shares	6 Months Ended
	Jul. 31, 2015	Sep. 03, 2015
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jul. 31, 2015
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2016
Entity Registrant Name	Triangle Petroleum Corp
Entity Central Index Key	0001281922
Current Fiscal Year End Date	--01-31
Entity Filer Category	Accelerated Filer
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		75,504,924

XML

Supplemental Disclosures Of Cash Flow Information

6 Months Ended

Jul. 31, 2015

Supplemental Disclosures of Cash Flow Information [Abstract]

Supplemental Disclosures of Cash Flow Information

12.  SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION

	For the Six Months Ended July 31,
(in thousands)	2014		2015
Cash paid during the period for:
Interest expense	$	4,717	$	16,078
Income taxes	$	550	$	—
Non-cash investing activities:
Additions to oil and natural gas properties through:
Increase (decrease) in accounts payable and accrued liabilities	$	37,151	$	(15,770)
Capitalized stock based compensation	$	649	$	709
Change in asset retirement obligations	$	1,106	$	425
Non-cash financing activities:
Notes payable issued for redemption of RockPile Series B Units	$	1,041	$	—

XML

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jul. 31, 2015	Jul. 31, 2014	Jul. 31, 2015	Jul. 31, 2014
REVENUES
Oil and natural gas liquids sales	$ 55,263	$ 80,506	$ 103,041	$ 141,340
Oilfield services	54,470	61,483	124,980	100,431
Total revenues	109,733	141,989	228,021	241,771
EXPENSES:
Lease operating expenses	11,369	6,698	22,278	11,424
Gathering, transportation and processing	6,641	3,733	12,989	7,535
Production taxes	5,449	8,677	10,236	15,025
Depreciation and amortization	32,244	26,707	70,050	47,994
Impairment of oil and natural gas properties	206,000		398,000
Accretion of asset retirement obligations	90	40	147	65
Oilfield services	46,719	43,554	112,183	71,264
General and administrative, net of amounts capitalized	14,589	14,091	29,448	27,492
Total operating expenses	323,101	103,500	655,331	180,799
INCOME FROM OPERATIONS	(213,368)	38,489	(427,310)	60,972
OTHER INCOME (EXPENSE):
Interest expense, net	(9,866)	(4,218)	(18,972)	(6,890)
Amortization of deferred loan costs	(731)	(1,167)	(1,347)	(1,359)
Gain on extinguishment of debt	1,156		1,156
Realized commodity derivative gains (losses)	17,016	(2,954)	36,484	(3,772)
Unrealized commodity derivative gains (losses)	8,033	2,033	(25,409)	(2,605)
Equity investment income (loss)	1,210	190	1,398	64
Gain on equity investment derivatives	4,516	(7,534)	4,516	2,920
Gain on Caliber capital transactions			2,880
Other income	(1,312)	52	(382)	114
Total other income (expense)	20,022	(13,598)	324	(11,528)
INCOME (LOSS) BEFORE INCOME TAXES	(193,346)	24,891	(426,986)	49,444
Income tax provision		10,339	(53,441)	20,350
NET INCOME (LOSS)	(193,346)	14,552	(373,545)	29,094
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (193,346)	$ 14,552	$ (373,545)	$ 29,094
Earnings (loss) per common share outstanding:
Basic	$ (2.56)	$ 0.17	$ (4.96)	$ 0.34
Diluted	$ (2.56)	$ 0.15	$ (4.96)	$ 0.30
Weighted average common shares outstanding:
Basic	75,410	86,172	75,334	86,064
Diluted	75,410	103,774	75,334	103,511

XML

Oil And Natural Gas Properties

6 Months Ended

Jul. 31, 2015

Oil And Natural Gas Properties [Abstract]

Oil And Natural Gas Properties

6.  ACQUISITIONS

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.

The acquisition was 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 unaudited pro forma financial information represents the combined results for the Company and the properties acquired from Marathon, in June of 2014, as if the acquisitions had occurred on February 1, 2014.

	For the Three Months Ended		For the Six Months Ended
(in thousands, except per share data)	July 31, 2014		July 31, 2014
Operating revenues	$	146,559	$	253,206
Net income (loss)	$	15,427	$	31,341
Earnings (loss) per common share
Basic	$	0.18	$	0.36
Diluted	$	0.16	$	0.32
Weighted average common shares outstanding:
Basic		86,172		86,064
Diluted		103,774		103,511

The pro forma information includes the effects of adjustments for depreciation and amortization expense of $1.3 million and $3.3 million, respectively, for the three and six month periods ended July 31, 2014. 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 as of the beginning of the period, nor are they necessarily indicative of future results.

XML

Hedging And Commodity Derivative Financial Instruments

6 Months Ended

Jul. 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 or reduce 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 four 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:

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
(in thousands)	2014		2015		2014		2015
Realized commodity derivative gains (losses)	$	(2,954)	$	17,016	$	(3,772)	$	36,484
Unrealized commodity derivative gains (losses)		2,033		8,033		(2,605)		(25,409)
Commodity derivative gains (losses), net	$	(921)	$	25,049	$	(6,377)	$	11,075

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

	Contract		Quantity	Weighted Average		Weighted Average		Weighted Average
	Type	Basis (1)	(Bbl/d)	Put Strike		Call Strike		Price
August 1, 2015 to January 31, 2016	Collar	NYMEX	2,739	$	85.45	$	98.20
August 1, 2015 to January 31, 2016	Swap	NYMEX	1,755					$	60.22
February 1, 2016 to January 31, 2017	Swap	NYMEX	2,746					$	60.23

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

In August 2015, the Company unwound certain commodity derivative swap contracts and realized a gain of $9.3 million.  The early settled contracts were for 2,000 barrels of oil per day at an average fixed price of $60.34 for the period from January 1, 2016 to December 31, 2016.

The estimated fair values of commodity derivatives included in the consolidated balance sheets at January 31, 2015 and July 31, 2015 are summarized below. 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)	January 31, 2015		July 31, 2015
Current Assets:
Crude oil derivative contracts	$	54,775	$	26,677
Other Long-Term Assets:
Crude oil derivative contracts		—		2,689
Total derivative asset	$	54,775	$	29,366

XML

Hedging And Commodity Derivative Financial Instruments (Tables)

6 Months Ended

Jul. 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:

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
(in thousands)	2014		2015		2014		2015
Realized commodity derivative gains (losses)	$	(2,954)	$	17,016	$	(3,772)	$	36,484
Unrealized commodity derivative gains (losses)		2,033		8,033		(2,605)		(25,409)
Commodity derivative gains (losses), net	$	(921)	$	25,049	$	(6,377)	$	11,075

Summary Of Derivative Instruments

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

	Contract		Quantity	Weighted Average		Weighted Average		Weighted Average
	Type	Basis (1)	(Bbl/d)	Put Strike		Call Strike		Price
August 1, 2015 to January 31, 2016	Collar	NYMEX	2,739	$	85.45	$	98.20
August 1, 2015 to January 31, 2016	Swap	NYMEX	1,755					$	60.22
February 1, 2016 to January 31, 2017	Swap	NYMEX	2,746					$	60.23

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

In August 2015, the Company unwound certain commodity derivative swap contracts and realized a gain of $9.3 million.  The early settled contracts were for 2,000 barrels of oil per day at an average fixed price of $60.34 for the period from January 1, 2016 to December 31, 2016.

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)	January 31, 2015		July 31, 2015
Current Assets:
Crude oil derivative contracts	$	54,775	$	26,677
Other Long-Term Assets:
Crude oil derivative contracts		—		2,689
Total derivative asset	$	54,775	$	29,366

XML

Summary Of Significant Accounting Policies (Policies)

6 Months Ended

Jul. 31, 2015

Summary Of Significant Accounting Policies [Abstract]

Use of Estimates

Use of Estimates. In the course of preparing its condensed 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 unproved 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 expenses and related 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 condensed consolidated financial statements.

Principles of Consolidation

Principles of Consolidation. The accounts of Triangle and its wholly-owned subsidiaries are presented in the accompanying condensed consolidated financial statements. All significant 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. The investment in Caliber is accounted for utilizing the equity method of accounting

Oil And Natural Gas Properties

Oil and Natural Gas Properties. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the amortizable pool of proved properties or in unproved properties, collectively, the full cost pool. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations.

At the end of each quarterly period, we must compute a limitation on capitalized costs, which is equal to the sum of the present value of estimated future net revenues from our proved reserves by applying the average price as prescribed by the SEC (unweighted arithmetic average of commodity prices in effect on the first day of each of the previous twelve months), less estimated future expenditures (based on current costs) to develop and produce the proved reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects. We then conduct a “ceiling test” that compares the net book value of the full cost pool, after taxes, to the full cost ceiling limitation. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record an impairment of our oil and natural gas properties.  

The ceiling test for each period presented was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing 12 month simple average spot prices at the first of the month for natural gas at Henry Hub (“HH”) and West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices between each of the periods and have a significant impact on our ceiling test limitation.

	Trailing 12 Month Simple Average Spot Prices
	January 31, 2015		April 30, 2015		July 31, 2015
Oil (per Bbl)	$	91.22	$	78.58	$	67.65
Natural gas (per MMbtu)	$	4.20	$	3.69	$	3.23
Natural gas liquids (per Bbl)	$	50.07	$	41.96	$	34.98

We recognized impairments to our proved oil and natural gas properties of $206.0 million and $398.0 million for the three and six months ended July 31, 2015, respectively, primarily due to the decline in oil, natural gas and natural gas liquids prices. We did not recognize impairments to our proved oil and natural gas properties for the three and six months ended July 31, 2014. We will incur additional impairments to our oil and natural gas properties in future quarters if prices stay at current levels or decline further.  The amount of any future impairment is difficult to predict, and will depend, in part, upon future oil, natural gas and natural gas liquids prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs. The ceiling limitation is not intended to be indicative of the fair market value of our proved reserves or future results.  Impairment charges do not affect cash flow from operating activities but do adversely affect our net income and stockholders’ equity.  Any recorded impairment of oil and natural gas properties is not reversible at a later date.

The evaluation of impairment of our oil and natural gas properties includes estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.

Oilfield Services Equipment and Other Property And Equipment

Oilfield Services Equipment and Other Property and Equipment.  Oilfield services equipment and other property and equipment consisted of the following as of:

(in thousands)	January 31, 2015		July 31, 2015
Land	$	7,888	$	7,888
Building and leasehold improvements		33,625		35,506
Oilfield service equipment		116,354		122,946
Vehicles		4,811		5,761
Software, computers and office equipment		5,327		6,481
Capital leases		853		853
Total depreciable assets		168,858		179,435
Accumulated depreciation		(35,189)		(54,121)
Depreciable assets, net		133,669		125,314
Assets not placed in service		1,247		3,508
Total oilfield service equipment and other property & equipment, net	$	134,916	$	128,822

Income Taxes

Income Taxes.  The Company computes its quarterly tax provision using the effective tax rate method based on applying the anticipated annual effective rate to its year-to-date income or loss, except for discrete items. Income tax on discrete items is computed and recorded in the period in which the specific transaction occurs.

As noted above, the carrying value of our oil and natural gas properties exceeded the calculated value of the ceiling limitation resulting in an impairment of $398.0 million for the six months ended July 31, 2015. This impairment results in Triangle having three years of cumulative historical pre-tax losses and a net deferred tax asset position. Additionally, Triangle will likely be required to recognize additional impairments of its oil and natural gas properties in future periods if oil and natural gas prices remain at current levels or continue to decline and such impairments will likely be material. Triangle also had net operating loss carryovers (“NOLs”) for federal income tax purposes of $136.9 million at January 31, 2015. These losses and expected future losses were a key consideration that led Triangle to provide a valuation allowance against its net deferred tax assets as of April 30 and July 31, 2015 since it cannot conclude that it is more likely than not that its net deferred tax assets will be fully realized in future periods.

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. At each reporting period, 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. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

In the first quarter of fiscal year 2016 the Company recorded the benefit of reversing its net deferred tax liability. As long as the Company concludes that it will continue to have a need for a valuation allowance against its net deferred tax assets, the Company likely will not have any additional income tax expense or benefit other than for federal alternative minimum tax expense, a release of a portion of the valuation allowance for net operating loss carryback claims or for state income taxes.

As of July 31, 2015, the Company had no unrecognized tax benefits. The Company’s management does not believe that there are any new items or changes in facts or judgments that should impact the Company’s position during the first six months of fiscal year 2016. Given the substantial net operating loss carryforwards at both the federal and state levels, neither significant interest expense nor penalties charged for any examining agents’ tax adjustments of income tax returns are anticipated, as any such adjustments would very likely only adjust net operating loss carryforwards.

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:

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
	2014		2015		2014		2015
Dilutive		17,602,373		—		17,447,130		—
Anti-dilutive shares		4,500,000		10,888,828		4,500,000		10,888,828

The table below sets forth the computations of net income (loss) per common share (basic and diluted) for the periods presented:

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
(in thousands, except per share data)	2014		2015		2014		2015
Net income (loss) attributable to common stockholders	$	14,552	$	(193,346)	$	29,094	$	(373,545)
Effect of 5% convertible note conversion		996		—		1,983		—
Net income (loss) attributable to common stockholders after effect of 5% convertible note conversion	$	15,548	$	(193,346)	$	31,077	$	(373,545)
Basic weighted average common shares outstanding		86,172		75,410		86,064		75,334
Effect of dilutive securities		17,602		—		17,447		—
Diluted weighted average common shares outstanding		103,774		75,410		103,511		75,334
Basic net income (loss) per share	$	0.17	$	(2.56)	$	0.34	$	(4.96)
Diluted net income (loss) per share	$	0.15	$	(2.56)	$	0.30	$	(4.96)

Reclassifications

Reclassifications.  Certain amounts in our unaudited condensed consolidated statement of operations for the three and six months ended July 31, 2014 have been reclassified to conform to the financial statement presentation for the periods ended July 31, 2015. The unaudited condensed consolidated 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 that 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

XML

Share-Based Compensation

6 Months Ended

Jul. 31, 2015

Share-Based Compensation [Abstract]

Share-Based Compensation

9.  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 issuable under the 2014 Plan is 6.0 million shares, subject to adjustment for certain transactions.

For the three and six months ended July 31, 2014 and 2015, the Company recorded share-based compensation related to restricted stock units, stock options and RockPile Series B Units as follows:

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
(in thousands)	2014		2015		2014		2015
Restricted stock units	$	1,503	$	2,584	$	3,274	$	4,663
Stock options		487		1,347		973		2,045
RockPile Series B Units		127		84		217		135
		2,117		4,015		4,464		6,843
Less amounts capitalized to oil and natural gas properties		(310)		(389)		(649)		(709)
Compensation expense	$	1,807	$	3,626	$	3,815	$	6,134

Restricted Stock Units. During the six months ended July 31, 2015, the Company granted 1,773,343 restricted stock units as compensation to employees, officers, and directors which generally vest over one to five years. As of July 31, 2015, there was approximately $23.2 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 3.3 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 activity for our restricted stock units during the six months ended July 31, 2015:  

		Weighted
		Average
	Number of	Award Date
	Shares	Fair Value
Restricted stock units outstanding - January 31, 2015	2,914,045	$	7.92
Units granted	1,773,343	$	4.93
Units forfeited	(63,588)	$	8.62
Units vested	(434,971)	$	7.79
Restricted stock units outstanding - July 31, 2015	4,188,829	$	6.66

Stock Options. There were nogrants,  exercises or forfeitures of stock options during the six months ended July 31, 2015. The following table summarizes the stock options outstanding at July 31, 2015:

		Remaining
Exercise Price		Contractual Life	Number of Shares
per Share		(years)	Outstanding		Exercisable
$	7.50	7.93		750,000		150,000
$	8.50	7.93		750,000		150,000
$	10.00	7.93		1,500,000		300,000
$	12.00	7.93		1,500,000		300,000
$	15.00	7.93		1,500,000		300,000
$	12.00	6.12		233,333		—
$	14.00	6.12		233,333		—
$	16.00	9.12		233,334		—
				6,700,000		1,200,000
Weighted average exercise price per share			$	11.54	$	11.25
Weighted average remaining contractual life				7.85		7.93

As of July 31, 2015, there was approximately $16.5 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 2.8 years.

RockPile Share-Based Compensation. RockPile currently has two classes of equity; Series A Units, which are voting units with an 8% preference, and Series B Units, which are non-voting 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 following table summarizes the activity for RockPile’s Series B Units for the six months ended July 31, 2015:

	Series	Series	Series	Series
	B-1units	B-2 units	B-3 units	B-4 units	Total
Units outstanding - January 31, 2015	2,920,000	60,000	910,000	1,412,000	5,302,000
Units redeemed	—	—	—	—	—
Units granted	—	—	—	—	—
Units forfeited	—	—	(96,000)	(74,000)	(170,000)
Units outstanding - July 31, 2015	2,920,000	60,000	814,000	1,338,000	5,132,000
Vested	2,920,000	30,000	352,000	117,600	3,419,600
Unvested	—	30,000	462,000	1,220,400	1,712,400

Series B Units currently have a 1 to 46 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. As of July 31, 2015, there was approximately $2.3 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’ remaining vesting schedule.

XML

Equity Investment And Equity Investment Derivatives

6 Months Ended

Jul. 31, 2015

Equity Investment [Abstract]

Equity Investment

7.  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”), a wholly-owned subsidiary of First Reserve Energy Infrastructure Fund. 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.

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, which is 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 recognized a gain in the first six months of fiscal year 2016 of $2.9 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 (Series 5) 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 Class A (Series 1 through 4) Warrants at strike prices and expiration dates noted below and 1,269,333 Class A (Series 6) Warrants with a strike price of $12.50 and an expiration date of February 2, 2018.

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

	Expiration		Strike Price at		As of	As of
	Date		July 31, 2015		January 31, 2015	July 31, 2015
Class A Units		—	$	—	7,000,000	7,000,000
Series 1 Warrants		October 1, 2024	$	12.78	5,600,000	6,615,467
Series 2 Warrants		October 1, 2024	$	22.09	2,400,000	2,835,200
Series 3 Warrants		September 12, 2025	$	22.09	3,000,000	3,544,000
Series 4 Warrants		September 12, 2025	$	28.09	2,000,000	2,362,667
Series 6 Warrants		February 2, 2018	$	12.50	—	1,269,333

The following summarizes the activities related to the Company’s equity investment in Caliber for the six months ended July 31, 2015:

	For the Six Months Ended
(in thousands)	July 31, 2015
Balance at January 31, 2015	$	64,411
Capital contributions		—
Distributions		—
Equity investment share of net income before intra-company profit eliminations		1,902
Change in fair value of warrants		4,516
Gain on Caliber capital transactions		2,880
Balance at July 31, 2015	$	73,709
Fair value of warrants at July 31, 2015	$	5,020

Equity Investment Derivatives.  At January 31, 2015 and July 31, 2015, the Company held Class A (Series 1 through Series 4 and Series 6) Warrants to acquire additional ownership in Caliber. These instruments are considered to be equity investment derivatives and are valued at each reporting period using valuation techniques for which the inputs are generally less observable than from objective sources.

XML

Capital Stock

6 Months Ended

Jul. 31, 2015

Capital Stock [Abstract]

Capital Stock

8.  CAPITAL STOCK

The Company had 106.7 million shares of common stock issued or reserved for issuance at July 31, 2015. At July 31, 2015, the Company had 75.5 million shares of common stock issued and outstanding. The Company also had 1.8 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2011 Omnibus Incentive Plan and 3.1 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2014 Equity Incentive Plan (the “2014 Plan”). The Company also had 2.9 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 17.4 million shares of common stock reserved for issuance pursuant to the Convertible Note at July 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 of common stock 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. There were no common stock repurchases for the three and six months ended July 31, 2015. As of July 31, 2015, the number of shares of common stock remaining available for repurchase under the Board approved program was 5,374,890 shares.

XML

Fair Value Measurements

6 Months Ended

Jul. 31, 2015

Fair Value Measurements [Abstract]

Fair Value Measurements

10.  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 July 31, 2015, by level within the fair value hierarchy:

	As of January 31, 2015
(in thousands)	Level 1		Level 2		Level3		Total
Assets:
Commodity derivative assets	$	—	$	54,775	$	—	$	54,775
Equity investment derivative assets	$	—	$	—	$	504	$	504
Liabilities:
RockPile earn-out liability	$	—	$	(1,825)	$	—	$	(1,825)

	As of July 31, 2015
(in thousands)	Level1		Level 2		Level 3		Total
Assets:
Commodity derivative assets	$	—	$	29,366	$	—	$	29,366
Equity investment derivative assets	$	—	$	—	$	5,020	$	5,020
Liabilities:
RockPile earn-out liability	$	—	$	(1,242)	$	—	$	(1,242)

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 July 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 and Series 6) Warrants. The Company determines its estimate of the fair value of Caliber Class A Warrants using a Monte Carlo Simulation (“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. At July 31, 2015, the fair value of the underlying Class A Units was estimated employing an income approach using a MCS model and discounted cash flows,and a market approach based on observed valuation multiples for comparable public companies.  Key inputs into these valuation approaches are generally less observable than those from objective sources. Therefore, 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 Service, Inc. 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.

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 values of the other notes and mortgages payable is not significantly different than their carrying 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.

The carrying values and fair values of the Company’s debt instruments are as follows:

	January 31, 2015				July 31, 2015
	Carrying		Estimated		Carrying		Estimated
(in thousands)	Value		FairValue		Value		Fair Value
5% convertible note	$	135,877	$	137,790	$	139,295	$	136,361
Revolving credit facilities		224,159		224,159		259,192		259,192
TUSA 6.75% notes		429,500		303,871		425,889		317,293
Other notes and mortgages payable		10,605		10,605		13,364		13,364

XML

Segment Reporting - Selected Financial Information - (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jul. 31, 2015	Jul. 31, 2014	Jul. 31, 2015	Jul. 31, 2014	Jan. 31, 2015
REVENUES
Oil and natural gas liquids sales	$ 55,263	$ 80,506	$ 103,041	$ 141,340
Oilfield services for third parties	54,470	61,483	124,980	100,431
Total revenues	109,733	141,989	228,021	241,771
EXPENSES:
Lease operating and production taxes	16,818	15,375	32,514	26,449
Gathering, transportation and processing	6,641	3,733	12,989	7,535
Depreciation and amortization	32,244	26,707	70,050	47,994
Impairment of oil and natural gas properties	206,000		398,000
Accretion of asset retirement obligations	90	40	147	65
Cost of oilfield services	46,719	43,554	112,183	71,264
Salaries and benefits	7,569	6,533	15,992	12,794
Stock-based compensation	3,626	1,807	6,134	3,815
Other general and administrative	3,394	5,751	7,322	10,883
Total operating expenses	323,101	103,500	655,331	180,799
INCOME FROM OPERATIONS	(213,368)	38,489	(427,310)	60,972
Other income (expense), net	20,022	(13,598)	324	(11,528)
INCOME (LOSS) BEFORE INCOME TAXES	(193,346)	24,891	(426,986)	49,444
Net oil and natural gas properties	787,767		787,767		$ 1,126,090
Oilfield services equipment, net	79,997		79,997		87,549
Other property and equipment, net	48,825		48,825		47,367
Total assets	1,209,957		1,209,957		1,654,870
Total liabilities	1,032,265		1,032,265		$ 1,109,852
Eliminations And Other [Member]
REVENUES
Oilfield services for third parties	(360)	(2,610)	(940)	(3,219)
Total revenues	(14,961)	(40,572)	(25,045)	(63,056)
EXPENSES:
Depreciation and amortization	(1,408)	(4,456)	(2,715)	(7,088)
Cost of oilfield services	(8,396)	(25,313)	(14,756)	(41,314)
Total operating expenses	(9,804)	(29,769)	(17,471)	(48,402)
INCOME FROM OPERATIONS	(5,157)	(10,803)	(7,574)	(14,654)
Other income (expense), net	(539)	(912)	(1,046)	(1,266)
INCOME (LOSS) BEFORE INCOME TAXES	(5,696)	(11,715)	(8,620)	(15,920)
Net oil and natural gas properties	(83,402)		(83,402)
Total assets	(103,634)		(103,634)
Total liabilities	(20,232)		(20,232)
Intersegment Revenues [Member] | Eliminations And Other [Member]
REVENUES
Total revenues	(14,601)	(37,962)	(24,105)	(59,837)
Exploration and Production [Member]
REVENUES
Oil and natural gas liquids sales	55,263	80,506	103,041	141,340
Total revenues	55,263	80,506	103,041	141,340
EXPENSES:
Lease operating and production taxes	16,818	15,375	32,514	26,449
Gathering, transportation and processing	6,641	3,733	12,989	7,535
Depreciation and amortization	24,527	26,287	53,826	46,440
Impairment of oil and natural gas properties	206,000		398,000
Accretion of asset retirement obligations	90	40	147	65
Salaries and benefits	584	1,560	925	2,801
Stock-based compensation	375	343	696	738
Other general and administrative	349	2,882	756	4,419
Total operating expenses	255,384	50,220	499,853	88,447
INCOME FROM OPERATIONS	(200,121)	30,286	(396,812)	52,893
Other income (expense), net	18,290	(4,267)	(2,712)	(10,834)
INCOME (LOSS) BEFORE INCOME TAXES	(181,831)	26,019	(399,524)	42,059
Net oil and natural gas properties	871,169		871,169
Other property and equipment, net	9,194		9,194
Total assets	1,023,660		1,023,660
Total liabilities	770,143		770,143
Oilfield Services [Member]
REVENUES
Oilfield services for third parties	54,830	64,093	125,920	103,650
Total revenues	69,431	102,055	150,025	163,487
EXPENSES:
Depreciation and amortization	8,718	4,690	18,207	8,280
Cost of oilfield services	56,353	68,867	126,939	112,578
Salaries and benefits	3,940	2,922	8,769	5,660
Stock-based compensation	84	127	135	217
Other general and administrative	1,034	2,329	2,831	4,688
Total operating expenses	70,129	78,935	156,881	131,423
INCOME FROM OPERATIONS	(698)	23,120	(6,856)	32,064
Other income (expense), net	(845)	(667)	(1,720)	(1,174)
INCOME (LOSS) BEFORE INCOME TAXES	(1,543)	22,453	(8,576)	30,890
Oilfield services equipment, net	79,997		79,997
Other property and equipment, net	21,759		21,759
Total assets	159,486		159,486
Total liabilities	130,685		130,685
Oilfield Services [Member] | Intersegment Revenues [Member]
REVENUES
Total revenues	14,601	37,962	24,105	59,837
Corporate And Other [Member]
EXPENSES:
Depreciation and amortization	407	186	732	362
Cost of oilfield services	(1,238)
Salaries and benefits	3,045	2,051	6,298	4,333
Stock-based compensation	3,167	1,337	5,303	2,860
Other general and administrative	2,011	540	3,735	1,776
Total operating expenses	7,392	4,114	16,068	9,331
INCOME FROM OPERATIONS	(7,392)	(4,114)	(16,068)	(9,331)
Other income (expense), net	3,116	(7,752)	5,802	1,746
INCOME (LOSS) BEFORE INCOME TAXES	(4,276)	$ (11,866)	(10,266)	$ (7,585)
Other property and equipment, net	17,872		17,872
Total assets	130,445		130,445
Total liabilities	$ 151,669		$ 151,669

XML

Share-Based Compensation - Restricted stock units - (Details) - Jul. 31, 2015 - Restricted Stock Units (RSUs) [Member] - USD ($) $ / shares in Units, $ in Millions	Total
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation	$ 23.2
Unrecognized compensation, recognition period	3 years 3 months 18 days
Number of shares per vesting unit	1
Outstanding, Unvested Beginning Balance	2,914,045
Outstanding, Weighted-Average Award Date Fair Value, Beginning Balance	$ 7.92
Units granted, number of units	1,773,343
Units granted, Weighted Average Award Date Fair Value	$ 4.93
Units forfeited, Number of Shares	(63,588)
Units forfeited, Weighted Average Award Date Fair Value	$ 8.62
Units that vested, Number of Shares	(434,971)
Units that vested, Weighted Average Award Date Fair Value	$ 7.79
Outstanding, Unvested Ending Balance	4,188,829
Outstanding, Weighted-Average Grant Date Fair Value, Ending Balance	$ 6.66
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based awards vesting period	1 year
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based awards vesting period	5 years

XML

Segment Reporting (Tables)

6 Months Ended

Jul. 31, 2015

Segment Reporting [Abstract]

Schedule Of Segment Reporting

The following tables present selected financial information for our operating segments for the three months ended July 31, 2015 and 2014.

	For the Three Months Ended July 31, 2015
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	55,263	$	—	$	—	$	—	$	55,263
Oilfield services for third parties		—		54,830		—		(360)		54,470
Intersegment revenues		—		14,601		—		(14,601)		—
Total revenues		55,263		69,431		—		(14,961)		109,733
Expenses:
Lease operating and production taxes		16,818		—		—		—		16,818
Gathering, transportation and processing		6,641		—		—		—		6,641
Depreciation and amortization		24,527		8,718		407		(1,408)		32,244
Impairment of oil and natural gas properties		206,000		—		—		—		206,000
Accretion of asset retirement obligations		90		—		—		—		90
Cost of oilfield services		—		56,353		(1,238)		(8,396)		46,719
General and administrative, net of amounts capitalized:
Salaries and benefits		584		3,940		3,045		—		7,569
Stock-based compensation		375		84		3,167		—		3,626
Other general and administrative		349		1,034		2,011		—		3,394
Total operating expenses		255,384		70,129		7,392		(9,804)		323,101
Income (loss) from operations		(200,121)		(698)		(7,392)		(5,157)		(213,368)
Other income (expense), net		18,290		(845)		3,116		(539)		20,022
Income (loss) before income taxes	$	(181,831)	$	(1,543)	$	(4,276)	$	(5,696)	$	(193,346)

	For the Three Months Ended July 31, 2014
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	80,506	$	—	$	—	$	—	$	80,506
Oilfield services for third parties		—		64,093		—		(2,610)		61,483
Intersegment revenues		—		37,962		—		(37,962)		—
Total revenues		80,506		102,055		—		(40,572)		141,989
Expenses:
Lease operating and production taxes		15,375		—		—		—		15,375
Gathering, transportation and processing		3,733		—		—		—		3,733
Depreciation and amortization		26,287		4,690		186		(4,456)		26,707
Accretion of asset retirement obligations		40		—		—		—		40
Cost of oilfield services		—		68,867		—		(25,313)		43,554
General and administrative, net of amounts capitalized:
Salaries and benefits		1,560		2,922		2,051		—		6,533
Stock-based compensation		343		127		1,337		—		1,807
Other general and administrative		2,882		2,329		540		—		5,751
Total operating expenses		50,220		78,935		4,114		(29,769)		103,500
Income (loss) from operations		30,286		23,120		(4,114)		(10,803)		38,489
Other income (expense), net		(4,267)		(667)		(7,752)		(912)		(13,598)
Net income (loss) before income taxes	$	26,019	$	22,453	$	(11,866)	$	(11,715)	$	24,891

The following tables present selected financial information for our operating segments for the six months ended July 31, 2015 and 2014.

	For the Six Months Ended July 31, 2015
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	103,041	$	—	$	—	$	—	$	103,041
Oilfield services for third parties		—		125,920		—		(940)		124,980
Intersegment revenues		—		24,105		—		(24,105)		—
Total revenues		103,041		150,025		—		(25,045)		228,021
Expenses:
Lease operating and production taxes		32,514		—		—		—		32,514
Gathering, transportation and processing		12,989		—		—		—		12,989
Depreciation and amortization		53,826		18,207		732		(2,715)		70,050
Impairment of oil and natural gas properties		398,000		—		—		—		398,000
Accretion of asset retirement obligations		147		—		—		—		147
Cost of oilfield services		—		126,939		—		(14,756)		112,183
General and administrative, net of amounts capitalized:
Salaries and benefits		925		8,769		6,298		—		15,992
Stock-based compensation		696		135		5,303		—		6,134
Other general and administrative		756		2,831		3,735		—		7,322
Total operating expenses		499,853		156,881		16,068		(17,471)		655,331
Income (loss) from operations		(396,812)		(6,856)		(16,068)		(7,574)		(427,310)
Other income (expense), net		(2,712)		(1,720)		5,802		(1,046)		324
Income (loss) before income taxes	$	(399,524)	$	(8,576)	$	(10,266)	$	(8,620)	$	(426,986)
As of July 31, 2015:
Net oil and natural gas properties	$	871,169	$	—	$	—	$	(83,402)	$	787,767
Oilfield services equipment - net	$	—	$	79,997	$	—	$	—	$	79,997
Other property and equipment - net	$	9,194	$	21,759	$	17,872	$	—	$	48,825
Total assets	$	1,023,660	$	159,486	$	130,445	$	(103,634)	$	1,209,957
Total liabilities	$	770,143	$	130,685	$	151,669	$	(20,232)	$	1,032,265

	For the Six Months Ended July 31, 2014
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	141,340	$	—	$	—	$	—	$	141,340
Oilfield services for third parties		—		103,650		—		(3,219)		100,431
Intersegment revenues		—		59,837		—		(59,837)		—
Total revenues		141,340		163,487		—		(63,056)		241,771
Expenses:
Lease operating and production taxes		26,449		—		—		—		26,449
Gathering, transportation and processing		7,535		—		—		—		7,535
Depreciation and amortization		46,440		8,280		362		(7,088)		47,994
Accretion of asset retirement obligations		65		—		—		—		65
Cost of oilfield services		—		112,578		—		(41,314)		71,264
General and administrative, net of amounts capitalized:
Salaries and benefits		2,801		5,660		4,333		—		12,794
Stock-based compensation		738		217		2,860		—		3,815
Other general and administrative		4,419		4,688		1,776		—		10,883
Total operating expenses		88,447		131,423		9,331		(48,402)		180,799
Income (loss) from operations		52,893		32,064		(9,331)		(14,654)		60,972
Other income (expense), net		(10,834)		(1,174)		1,746		(1,266)		(11,528)
Income (loss) before income taxes	$	42,059	$	30,890	$	(7,585)	$	(15,920)	$	49,444

XML

Share-Based Compensation (Tables)

6 Months Ended

Jul. 31, 2015

Share-Based Compensation [Abstract]

Non-Cash Stock-Based Compensation Cost

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
(in thousands)	2014		2015		2014		2015
Restricted stock units	$	1,503	$	2,584	$	3,274	$	4,663
Stock options		487		1,347		973		2,045
RockPile Series B Units		127		84		217		135
		2,117		4,015		4,464		6,843
Less amounts capitalized to oil and natural gas properties		(310)		(389)		(649)		(709)
Compensation expense	$	1,807	$	3,626	$	3,815	$	6,134

Restricted Stock Units Outstanding

The following table summarizes the activity for our restricted stock units during the six months ended July 31, 2015:  

		Weighted
		Average
	Number of	Award Date
	Shares	Fair Value
Restricted stock units outstanding - January 31, 2015	2,914,045	$	7.92
Units granted	1,773,343	$	4.93
Units forfeited	(63,588)	$	8.62
Units vested	(434,971)	$	7.79
Restricted stock units outstanding - July 31, 2015	4,188,829	$	6.66

Stock Options Outstanding By Exercise Price

The following table summarizes the stock options outstanding at July 31, 2015:

		Remaining
Exercise Price		Contractual Life	Number of Shares
per Share		(years)	Outstanding		Exercisable
$	7.50	7.93		750,000		150,000
$	8.50	7.93		750,000		150,000
$	10.00	7.93		1,500,000		300,000
$	12.00	7.93		1,500,000		300,000
$	15.00	7.93		1,500,000		300,000
$	12.00	6.12		233,333		—
$	14.00	6.12		233,333		—
$	16.00	9.12		233,334		—
				6,700,000		1,200,000
Weighted average exercise price per share			$	11.54	$	11.25
Weighted average remaining contractual life				7.85		7.93

Summary Of Series B Unit Activity

	Series	Series	Series	Series
	B-1units	B-2 units	B-3 units	B-4 units	Total
Units outstanding - January 31, 2015	2,920,000	60,000	910,000	1,412,000	5,302,000
Units redeemed	—	—	—	—	—
Units granted	—	—	—	—	—
Units forfeited	—	—	(96,000)	(74,000)	(170,000)
Units outstanding - July 31, 2015	2,920,000	60,000	814,000	1,338,000	5,132,000
Vested	2,920,000	30,000	352,000	117,600	3,419,600
Unvested	—	30,000	462,000	1,220,400	1,712,400

XML

Capital Stock (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jul. 31, 2015	Jul. 31, 2015	Jan. 31, 2015
Common stock issued or reserved		106,700,000
Common stock, shares issued	75,488,871	75,488,871	75,174,442
Common stock, shares outstanding	75,488,871	75,488,871	75,174,442
Stock Repurchase authorized (Tranche 1)	$ 25.0	$ 25.0
Common stock repurchased (in shares)	0	0
Authorized shares remaining repurchase	5,374,890	5,374,890
2011 Omnibus Incentive Plan
Shares reserved for issuance	1,800,000	1,800,000
2014 Plan
Shares reserved for issuance	3,100,000	3,100,000
Shares reserved for future grants	2,900,000	2,900,000
CEO Stand-Alone Stock Option Agreement
Shares reserved for issuance	6,000,000	6,000,000
Convertible Notes Payable [Member]
Shares reserved for issuance	17,400,000	17,400,000

XML

Hedging And Commodity Derivative Financial Instruments - (Details) $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	Aug. 31, 2015 USD ($)	Jul. 31, 2015 USD ($)	Jul. 31, 2014 USD ($)	Jul. 31, 2015 USD ($) item	Jul. 31, 2014 USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Number of counterparties | item				4
Realized commodity derivative gains (losses)	$ 9,300	$ 17,016	$ (2,954)	$ 36,484	$ (3,772)
Unrealized commodity derivative gains (losses)		8,033	2,033	(25,409)	(2,605)
Commodity derivatives gains (losses)				$ 11,075	$ (6,377)
Crude Oil Derivative Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized commodity derivative gains (losses)		17,016	(2,954)
Unrealized commodity derivative gains (losses)		8,033	2,033
Commodity derivatives gains (losses)		$ 25,049	$ (921)

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jul. 31, 2015	Jul. 31, 2014	Jul. 31, 2015	Jul. 31, 2014	Jan. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (193,346)	$ 14,552	$ (373,545)	$ 29,094
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	32,244	26,707	70,050	47,994
Impairment of oil and natural gas properties	206,000		398,000
Share-based compensation			6,134	3,815
Interest expense not paid in cash			3,418	3,252
Amortization of deferred loan costs	731	1,167	1,347	1,359
Gain on extinguishment of debt	(1,156)		(1,156)
Accretion of asset retirement obligations	90	40	147	65
Unrealized commodity derivative (gains) losses	(8,033)	(2,033)	25,409	2,605
Equity investment income (loss)	(1,210)	(190)	(1,398)	(64)
Gain on equity investment derivatives			(4,516)	(2,920)
Gain on Caliber capital transactions			(2,880)
Deferred income taxes			(53,441)	19,800
Changes in related current assets and current liabilities:
Accounts receivable			55,752	(44,363)
Other current assets			6,005	(581)
Accounts payable and accrued liabilities			(48,345)	2,994
Asset retirement expenditures			(377)	(136)
Other			(559)	(1,068)
Cash provided by operating activities			80,045	61,846
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas expenditures			(128,734)	(149,479)
Acquisitions of oil and natural gas properties			(243)	(131,368)
Purchase of oil field services equipment			(8,657)	(24,579)
Purchase of other property and equipment			(4,208)	(3,080)
Sale of oil and natural gas properties			6,000
Other			15	58
Cash used in investing activities			(135,827)	(308,448)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities			110,810	245,116
Repayments of credit facilities			(75,777)	(410,015)
Proceeds from notes payable			3,035	450,000
Repayments of other notes and mortgages payable			(298)	(199)
Early extinguishment of repurchased debt			(2,455)
Debt issuance costs			(910)	(10,331)
Payments to settle tax on vested restricted stock units			(624)	(2,192)
Cash provided by financing activities			33,781	272,379
NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS			(22,001)	25,777
CASH AND EQUIVALENTS, BEGINNING OF PERIOD			67,871	81,750	$ 81,750
CASH AND EQUIVALENTS, END OF PERIOD	$ 45,870	$ 107,527	$ 45,870	$ 107,527	$ 67,871

XML

Long-Term Debt

6 Months Ended

Jul. 31, 2015

Long-Term Debt [Abstract]

Long-term Debt

4.  LONG-TERM DEBT

The Company’s long-term debt consisted of the following as of January 31, 2015 and July 31, 2015:

(in thousands)	January 31, 2015		July 31, 2015
5% convertible note	$	135,877	$	139,295
TUSA credit facility due October 2018		119,272		172,272
RockPile credit facility due March 2019		104,887		86,920
TUSA 6.75% notes due July 2022		429,500		425,889
Other notes and mortgages payable		10,605		13,364
Total debt		800,141		837,740
Less current portion of debt:
Other notes and mortgages payable		(503)		(677)
Total long-term debt	$	799,638	$	837,063

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 September 30, 2017, the Company has the option to make such interest payments in cash. As of July 31, 2015, $19.3 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. The TUSA credit facility has a maturity date of October 16, 2018.

On April 30, 2015, TUSA entered into Amendment No. 1 to its Second Amended and Restated Credit Agreement (“Amendment No. 1”) to, among other things, replace the existing total funded debt leverage ratio with a senior secured leverage ratio, add an interest coverage ratio, and add an equity cure right for non-compliance with financial covenants. The May 2015 semi-annual redetermination of the borrowing base was conducted concurrently with the execution of Amendment No. 1, and the borrowing base was adjusted from $435.0 million to $350.0 million.

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 1.0%), 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 May 1 and November 1. 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 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 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, consolidated senior secured debt to consolidated EBITDAX, and interest to consolidated EBITDAX. As of July 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 pays a commitment fee that ranges between 0.375% and 0.50% per annum on the unused availability under the RockPile credit facility. RockPile also pays 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. The obligations under the RockPile credit facility are guaranteed by RockPile’s subsidiaries, but Triangle is not a guarantor.

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 July 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 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 a price equal to 105% of the principal amount of the notes redeemed (103% after July 15, 2018, 102% after July 15, 2019 and 100% after July 15, 2020), 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, immediately retired the repurchased notes, and recognized a gain on extinguishment of debt of $6.6 million.  During the three months ended July 31, 2015, TUSA repurchased additional TUSA 6.75% Notes with a face value of $3.6 million for $2.5 million, immediately retired the repurchased notes, and recognized a gain on extinguishment of debt of $1.1 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 July 31, 2015, TUSA was in compliance with all covenants under the TUSA 6.75% Notes.

XML

Fair Value Measurements (Tables)

6 Months Ended

Jul. 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		Level3		Total
Assets:
Commodity derivative assets	$	—	$	54,775	$	—	$	54,775
Equity investment derivative assets	$	—	$	—	$	504	$	504
Liabilities:
RockPile earn-out liability	$	—	$	(1,825)	$	—	$	(1,825)

	As of July 31, 2015
(in thousands)	Level1		Level 2		Level 3		Total
Assets:
Commodity derivative assets	$	—	$	29,366	$	—	$	29,366
Equity investment derivative assets	$	—	$	—	$	5,020	$	5,020
Liabilities:
RockPile earn-out liability	$	—	$	(1,242)	$	—	$	(1,242)

Summary Of Fair Value Of Financial Instruments

The carrying values and fair values of the Company’s debt instruments are as follows:

	January 31, 2015				July 31, 2015
	Carrying		Estimated		Carrying		Estimated
(in thousands)	Value		FairValue		Value		Fair Value
5% convertible note	$	135,877	$	137,790	$	139,295	$	136,361
Revolving credit facilities		224,159		224,159		259,192		259,192
TUSA 6.75% notes		429,500		303,871		425,889		317,293
Other notes and mortgages payable		10,605		10,605		13,364		13,364

XML

Long-term Debt - TUSA credit facility - (Details) - USD ($) $ in Millions	6 Months Ended
	Jul. 31, 2015	Apr. 30, 2015	Nov. 25, 2014	Apr. 30, 2014
Line of Credit Facility [Line Items]
Credit agreement borrowing base		$ 350.0		$ 435.0
TUSA [Member]
Line of Credit Facility [Line Items]
Credit facility, maximum borrowing capacity			$ 1,000.0
Letter of credit sublimit			$ 15.0
Percentage of Oil and Gas Interests Used For Collateral	80.00%
Minimum [Member] | TUSA [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Credit facility, commitment fee percentage	0.375%
Maximum [Member] | TUSA [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Credit facility, commitment fee percentage	0.50%
Federal Funds Rate [Member] | TUSA [Member]
Line of Credit Facility [Line Items]
Credit facility, basis spread on interest rate	0.50%
Eurodollar Rate Plus 1% [Member] | TUSA [Member]
Line of Credit Facility [Line Items]
Credit facility, margin on dollar amount based on usage	1.00%
Eurodollar Rate Plus 1% [Member] | Minimum [Member] | TUSA [Member]
Line of Credit Facility [Line Items]
Credit facility, basis spread on interest rate	0.50%
Eurodollar Rate Plus 1% [Member] | Maximum [Member] | TUSA [Member]
Line of Credit Facility [Line Items]
Credit facility, basis spread on interest rate	1.50%
Eurodollar [Member] | Minimum [Member] | TUSA [Member]
Line of Credit Facility [Line Items]
Credit facility, basis spread on interest rate	1.50%
Eurodollar [Member] | Maximum [Member] | TUSA [Member]
Line of Credit Facility [Line Items]
Credit facility, basis spread on interest rate	2.50%

XML

Summary Of Significant Accounting Policies (Tables)

6 Months Ended

Jul. 31, 2015

Summary Of Significant Accounting Policies [Abstract]

Schedule of 12 month simple avgerage spot prices

	Trailing 12 Month Simple Average Spot Prices
	January 31, 2015		April 30, 2015		July 31, 2015
Oil (per Bbl)	$	91.22	$	78.58	$	67.65
Natural gas (per MMbtu)	$	4.20	$	3.69	$	3.23
Natural gas liquids (per Bbl)	$	50.07	$	41.96	$	34.98

Schedule of Oilfield services equipment and other property and equipment

Oilfield services equipment and other property and equipment consisted of the following as of:

(in thousands)	January 31, 2015		July 31, 2015
Land	$	7,888	$	7,888
Building and leasehold improvements		33,625		35,506
Oilfield service equipment		116,354		122,946
Vehicles		4,811		5,761
Software, computers and office equipment		5,327		6,481
Capital leases		853		853
Total depreciable assets		168,858		179,435
Accumulated depreciation		(35,189)		(54,121)
Depreciable assets, net		133,669		125,314
Assets not placed in service		1,247		3,508
Total oilfield service equipment and other property & equipment, net	$	134,916	$	128,822

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:

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
	2014		2015		2014		2015
Dilutive		17,602,373		—		17,447,130		—
Anti-dilutive shares		4,500,000		10,888,828		4,500,000		10,888,828

Schedule of computations of net income(loss) per common share (basic and diluted)

	For the Three Months Ended				For the Six Months Ended
	July 31,				July 31,
(in thousands, except per share data)	2014		2015		2014		2015
Net income (loss) attributable to common stockholders	$	14,552	$	(193,346)	$	29,094	$	(373,545)
Effect of 5% convertible note conversion		996		—		1,983		—
Net income (loss) attributable to common stockholders after effect of 5% convertible note conversion	$	15,548	$	(193,346)	$	31,077	$	(373,545)
Basic weighted average common shares outstanding		86,172		75,410		86,064		75,334
Effect of dilutive securities		17,602		—		17,447		—
Diluted weighted average common shares outstanding		103,774		75,410		103,511		75,334
Basic net income (loss) per share	$	0.17	$	(2.56)	$	0.34	$	(4.96)
Diluted net income (loss) per share	$	0.15	$	(2.56)	$	0.30	$	(4.96)