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 October 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 December 7, 2015, there were 75,713,104 shares of the registrant’s common stock outstanding.

TRIANGLE PETROLEUM CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTERLY PERIOD ENDED OCTOBER 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	2
		CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS	4
		CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	5
		CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (DEFICIT)	6
		NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	7
	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	25
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	37
	ITEM 4.	CONTROLS AND PROCEDURES	38
PART II.  OTHER INFORMATION			39
	ITEM 1.	LEGAL PROCEEDINGS	39
	ITEM 1A.	RISK FACTORS	39
	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	39
	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	40
	ITEM 4.	MINE SAFETY DISCLOSURES	40
	ITEM 5.	OTHER INFORMATION	40
	ITEM 6.	EXHIBITS	41
SIGNATURES			42

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.

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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		October 31, 2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	67,871	$	36,250
Accounts receivable		171,911		63,494
Commodity derivatives		54,775		8,329
Other current assets		14,952		8,667
Total current assets		309,509		116,740
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and natural gas properties, full cost method of accounting
Proved properties		1,159,584		1,332,121
Unproved properties and properties under development, not being amortized		142,896		107,226
Total oil and natural gas properties		1,302,480		1,439,347
Accumulated amortization		(176,390)		(909,998)
Net oil and natural gas properties		1,126,090		529,349
Oilfield services equipment, net		87,549		64,210
Other property and equipment, net		47,367		47,924
Net property, plant and equipment		1,261,006		641,483
OTHER ASSETS
Deferred loan costs		14,038		12,782
Equity investment		64,411		73,389
Commodity derivatives		—		463
Other		5,906		5,601
Total other assets		84,355		92,235
Total assets	$	1,654,870	$	850,458

See notes to condensed consolidated financial statements.

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Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets (Unaudited)

(In thousands, except share data)

	January 31, 2015		October 31, 2015
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
CURRENT LIABILITIES
Accounts payable and accrued capital expenditures	$	176,182	$	82,670
Other accrued liabilities		73,440		46,006
Current portion of long-term debt		503		1,641
Interest payable		2,250		8,717
Deferred income taxes		19,467		—
Total current liabilities		271,842		139,034
LONG-TERM LIABILITIES
Borrowings on credit facilities		224,159		243,402
TUSA 6.75% notes		429,500		415,889
5% convertible note		135,877		141,037
Other notes and mortgages payable		10,102		12,566
Deferred income taxes		33,974		—
Commodity derivatives		—		470
Other		4,398		4,585
Total liabilities		1,109,852		956,983
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY (DEFICIT)
Common stock, $0.00001 par value, 140,000,000 shares authorized; 75,174,442 and 75,679,808 shares issued and outstanding at January 31, 2015 and October 31, 2015, respectively		1		1
Additional paid-in capital		545,017		554,018
Retained earnings (accumulated deficit)		—		(660,544)
Total stockholders' equity (deficit)		545,018		(106,525)
Total liabilities and stockholders’ equity (deficit)	$	1,654,870	$	850,458

See notes to condensed consolidated financial statements.

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Triangle Petroleum Corporation

Condensed Consolidated Statements of Operations (Unaudited)

(In thousands, except per share data)

	For the Three Months Ended				For the Nine Months Ended
	October 31,				October 31,
	2014		2015		2014		2015
REVENUES:
Oil, natural gas and natural gas liquids sales	$	80,139	$	42,871	$	221,479	$	145,912
Oilfield services		94,057		22,273		194,488		147,253
Total revenues		174,196		65,144		415,967		293,165
EXPENSES:
Lease operating expenses		7,317		10,135		18,741		32,413
Gathering, transportation and processing		4,380		6,537		11,915		19,526
Production taxes		8,637		4,052		23,662		14,288
Depreciation and amortization		32,471		28,396		80,465		98,446
Impairment of oil and natural gas properties		—		261,000		—		659,000
Accretion of asset retirement obligations		259		75		324		222
Oilfield services		70,805		21,700		142,069		133,883
General and administrative, net of amounts capitalized		16,793		18,434		44,285		47,882
Total operating expenses		140,662		350,329		321,461		1,005,660
INCOME (LOSS) FROM OPERATIONS		33,534		(285,185)		94,506		(712,495)
OTHER INCOME (EXPENSE):
Interest expense, net		(8,984)		(9,877)		(15,874)		(28,849)
Amortization of deferred loan costs		(479)		(852)		(1,838)		(2,199)
Gain on extinguishment of debt		—		4,175		—		5,331
Realized commodity derivative gains (losses)		688		27,857		(3,084)		64,341
Unrealized commodity derivative gains (losses)		19,134		(21,044)		16,529		(46,453)
Equity investment income (loss)		393		450		457		1,848
Gain (loss) on equity investment derivatives		742		(1,118)		3,662		3,398
Gain on Caliber capital transactions		—		—		—		2,880
Other income (expense), net		(330)		(1,405)		(216)		(1,787)
Total other income (expense)		11,164		(1,814)		(364)		(1,490)
INCOME (LOSS) BEFORE INCOME TAXES		44,698		(286,999)		94,142		(713,985)
INCOME TAX PROVISION (BENEFIT)		19,300		—		39,650		(53,441)
NET INCOME (LOSS)	$	25,398	$	(286,999)	$	54,492	$	(660,544)
Earnings (loss) per common share outstanding:
Basic	$	0.30	$	(3.80)	$	0.64	$	(8.76)
Diluted	$	0.26	$	(3.80)	$	0.55	$	(8.76)
Weighted average common shares outstanding:
Basic		85,242		75,588		85,769		75,419
Diluted		102,954		75,588		103,421		75,419

See notes to condensed consolidated financial statements.

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Triangle Petroleum Corporation

Condensed Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

	For the Nine Months Ended October 31,
	2014		2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	54,492	$	(660,544)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		80,465		98,446
Impairment of oil and natural gas properties		—		659,000
Share-based compensation		5,642		13,900
Interest expense paid-in-kind on 5% convertible note		4,910		5,160
Amortization of deferred loan costs		1,838		2,199
Gain on extinguishment of debt		—		(5,331)
Accretion of asset retirement obligations		324		222
Unrealized commodity derivative (gains) losses		(16,529)		46,453
Equity investment (income) loss		(457)		(1,848)
Gain on equity investment derivatives		(3,662)		(3,398)
Gain on Caliber capital transactions		—		(2,880)
Loss on sale of equipment		—		1,077
Deferred income taxes		38,823		(53,441)
Changes in related current assets and current liabilities:
Accounts receivable		(92,317)		108,417
Other current assets		(157)		6,285
Accounts payable and accrued liabilities		28,854		(69,241)
Asset retirement expenditures		(137)		(1,521)
Other		334		(481)
Cash provided by operating activities		102,423		142,474
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property expenditures		(218,313)		(182,198)
Acquisitions of oil and natural gas properties		(132,843)		(837)
Purchases of oilfield services equipment		(41,263)		(7,275)
Purchases of other property and equipment		(12,079)		(4,661)
Sale of oil and natural gas properties		1,500		6,000
Proceeds from sale of equipment		—		7,468
Other		188		—
Cash used in investing activities		(402,810)		(181,503)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities		313,616		183,367
Repayments of credit facilities		(433,515)		(164,124)
Proceeds from notes payable		450,000		4,032
Repayments of other notes and mortgages payable		(300)		(463)
Early extinguishment of repurchased debt		—		(8,280)
Debt issuance costs		(12,714)		(943)
Payments to settle tax on vested restricted stock units		(2,666)		(834)
Distributions to RockPile B unit holders		—		(4,318)
Purchase of vested RockPile B units from unit holders		—		(1,029)
Common stock repurchased and retired		(42,548)		—
Cash provided by financing activities		271,873		7,408
NET INCREASE (DECREASE) IN CASH AND EQUIVALENTS		(28,514)		(31,621)
CASH AND EQUIVALENTS, BEGINNING OF PERIOD		81,750		67,871
CASH AND EQUIVALENTS, END OF PERIOD	$	53,236	$	36,250

See notes to condensed consolidated financial statements.

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Triangle Petroleum Corporation

Condensed Consolidated Statement of Stockholders’ Equity(Deficit) (Unaudited)

For the Nine Months Ended October 31, 2015

(in thousands, except share data)

						Retained		Total
	Shares of	Common		Additional		Earnings		Stockholders'
	Common	Stock at		Paid-in		(Accumulated		Equity
	Stock	Par Value		Capital		Deficit)		(Deficit)
Balance - January 31, 2015	75,174,442	$	1	$	545,017	$	—	$	545,018
Vesting of restricted stock units (net of shares surrendered for taxes)	505,366		—		(834)		—		(834)
Share-based compensation	—		—		15,182		—		15,182
Distributions to RockPile B-Unit holders	—		—		(4,318)		—		(4,318)
Purchase of vested RockPile B units from unit holders	—		—		(1,029)		—		(1,029)
Net income (loss) for the period	—		—		—		(660,544)		(660,544)
Balance - October 31, 2015	75,679,808	$	1	$	554,018	$	(660,544)	$	(106,525)

See notes to condensed consolidated financial statements.

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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;

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(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		October 31, 2015
Oil (per Bbl)	$	91.22	$	78.58	$	67.65	$	55.37
Natural gas (per MMbtu)	$	4.20	$	3.69	$	3.23	$	2.89
Natural gas liquids (per Bbl)	$	50.07	$	41.96	$	34.98	$	26.60

We recognized impairments to our proved oil and natural gas properties of $261.0 million and $659.0 million for the three and nine months ended October 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 nine months ended October 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.

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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		October 31, 2015
Oilfield services equipment	$	105,938	$	110,703
Accumulated depreciation		(28,805)		(46,792)
Depreciable assets, net		77,133		63,911
Assets not placed in service		10,416		299
Total oilfield services equipment, net	$	87,549	$	64,210
Land	$	7,888	$	7,888
Building and leasehold improvements		33,625		36,843
Vehicles		4,811		5,036
Software, computers and office equipment		5,327		7,382
Capital leases		853		879
Accumulated depreciation		(6,384)		(10,488)
Depreciable assets, net		46,120		47,540
Assets not placed in service		1,247		384
Total other property and equipment, net	$	47,367	$	47,924

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 $659.0 million for the nine months ended October 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 $143.1 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, July 31, and October 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 or for state income taxes.

As of October 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 nine 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.

9

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 earnings 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 Nine Months Ended
	October 31,				October 31,
(in thousands)	2014		2015		2014		2015
Dilutive		17,712		—		17,652		—
Anti-dilutive shares		6,740		10,819		6,776		10,819

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 Nine Months Ended
	October 31,				October 31,
(in thousands, except per share data)	2014		2015		2014		2015
Net income (loss) attributable to common stockholders	$	25,398	$	(286,999)	$	54,492	$	(660,544)
Effect of 5% convertible note conversion		919		—		2,852		—
Net income (loss) attributable to common stockholders after effect of 5% convertible note conversion	$	26,317	$	(286,999)	$	57,344	$	(660,544)
Basic weighted average common shares outstanding		85,242		75,588		85,769		75,419
Effect of dilutive securities		17,712		—		17,652		—
Diluted weighted average common shares outstanding		102,954		75,588		103,421		75,419
Basic net income (loss) per share	$	0.30	$	(3.80)	$	0.64	$	(8.76)
Diluted net income (loss) per share	$	0.26	$	(3.80)	$	0.55	$	(8.76)

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

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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 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 October 31, 2015 and 2014.

	For the Three Months Ended October 31, 2015
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	42,871	$	—	$	—	$	—	$	42,871
Oilfield services for third parties		—		21,922		—		351		22,273
Intersegment revenues		—		3,881		—		(3,881)		—
Total revenues		42,871		25,803		—		(3,530)		65,144
Expenses:
Lease operating and production taxes		14,187		—		—		—		14,187
Gathering, transportation and processing		6,537		—		—		—		6,537
Depreciation and amortization		21,394		6,797		420		(215)		28,396
Impairment of oil and natural gas properties		261,000		—		—		—		261,000
Accretion of asset retirement obligations		75		—		—		—		75
Oilfield services		—		24,664		—		(2,964)		21,700
General and administrative, net of amounts capitalized:
Salaries and benefits		450		4,138		2,338		—		6,926
Share-based compensation		390		117		7,259		—		7,766
Other general and administrative		405		1,198		2,139		—		3,742
Total operating expenses		304,438		36,914		12,156		(3,179)		350,329
Income (loss) from operations		(261,567)		(11,111)		(12,156)		(351)		(285,185)
Other income (expense)		2,991		(2,062)		(2,298)		(445)		(1,814)
Income (loss) before income taxes	$	(258,576)	$	(13,173)	$	(14,454)	$	(796)	$	(286,999)

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	For the Three Months Ended October 31, 2014
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	80,139	$	—	$	—	$	—	$	80,139
Oilfield services for third parties		—		96,810		—		(2,753)		94,057
Intersegment revenues		—		46,665		—		(46,665)		—
Total revenues		80,139		143,475		—		(49,418)		174,196
Expenses:
Lease operating and production taxes		15,954		—		—		—		15,954
Gathering, transportation and processing		4,380		—		—		—		4,380
Depreciation and amortization		30,291		6,119		255		(4,194)		32,471
Accretion of asset retirement obligations		259		—		—		—		259
Oilfield services		—		102,710		—		(31,905)		70,805
General and administrative, net of amounts capitalized:
Salaries and benefits		1,264		3,836		2,625		—		7,725
Share-based compensation		94		146		1,587		—		1,827
Other general and administrative		2,966		3,207		1,068		—		7,241
Total operating expenses		55,208		116,018		5,535		(36,099)		140,662
Income (loss) from operations		24,931		27,457		(5,535)		(13,319)		33,534
Other income (expense)		12,126		(628)		594		(928)		11,164
Net income (loss) before income taxes	$	37,057	$	26,829	$	(4,941)	$	(14,247)	$	44,698

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

	For the Nine Months Ended October 31, 2015
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	145,912	$	—	$	—	$	—	$	145,912
Oilfield services for third parties		—		147,842		—		(589)		147,253
Intersegment revenues		—		27,986		—		(27,986)		—
Total revenues		145,912		175,828		—		(28,575)		293,165
Expenses:
Lease operating and production taxes		46,701		—		—		—		46,701
Gathering, transportation and processing		19,526		—		—		—		19,526
Depreciation and amortization		75,220		25,004		1,152		(2,930)		98,446
Impairment of oil and natural gas properties		659,000		—		—		—		659,000
Accretion of asset retirement obligations		222		—		—		—		222
Oilfield services		—		151,603		—		(17,720)		133,883
General and administrative, net of amounts capitalized:
Salaries and benefits		1,375		12,907		8,636		—		22,918
Share-based compensation		1,086		252		12,562		—		13,900
Other general and administrative		1,161		4,029		5,874		—		11,064
Total operating expenses		804,291		193,795		28,224		(20,650)		1,005,660
Income (loss) from operations		(658,379)		(17,967)		(28,224)		(7,925)		(712,495)
Other income (expense)		279		(3,782)		3,504		(1,491)		(1,490)
Income (loss) before income taxes	$	(658,100)	$	(21,749)	$	(24,720)	$	(9,416)	$	(713,985)
As of October 31, 2015:
Net oil and natural gas properties	$	613,547	$	—	$	—	$	(84,198)	$	529,349
Oilfield services equipment, net	$	—	$	64,210	$	—	$	—	$	64,210
Other property and equipment, net	$	9,072	$	21,398	$	17,454	$	—	$	47,924
Total assets	$	718,582	$	93,333	$	123,075	$	(84,532)	$	850,458
Total liabilities	$	720,821	$	82,164	$	154,332	$	(334)	$	956,983

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	For the Nine Months Ended October 31, 2014
	Exploration				Corporate
	and		Oilfield		and				Consolidated
(in thousands)	Production		Services		Other		Eliminations		Total
Revenues:
Oil, natural gas and natural gas liquids sales	$	221,479	$	—	$	—	$		$	221,479
Oilfield services for third parties		—		200,460		—		(5,972)		194,488
Intersegment revenues		—		106,502		—		(106,502)		—
Total revenues		221,479		306,962		—		(112,474)		415,967
Expenses:
Lease operating and production taxes		42,403		—		—		—		42,403
Gathering, transportation and processing		11,915		—		—		—		11,915
Depreciation and amortization		76,731		14,399		617		(11,282)		80,465
Accretion of asset retirement obligations		324		—		—		—		324
Oilfield services		—		215,288		—		(73,219)		142,069
General and administrative, net of amounts capitalized:
Salaries and benefits		4,065		9,496		6,958		—		20,519
Share-based compensation		832		363		4,447		—		5,642
Other general and administrative		7,385		7,895		2,844		—		18,124
Total operating expenses		143,655		247,441		14,866		(84,501)		321,461
Income (loss) from operations		77,824		59,521		(14,866)		(27,973)		94,506
Other income (expense)		1,292		(1,802)		2,340		(2,194)		(364)
Income (loss) before income taxes	$	79,116	$	57,719	$	(12,526)	$	(30,167)	$	94,142

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 October 31, 2015 and 2014, $(0.4)million and $2.4 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 nine months ended October 31, 2015 and 2014, $0.2million and $6.7 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.

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4.  LONG-TERM DEBT

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

(in thousands)	January 31, 2015		October 31, 2015
TUSA credit facility due October 2018	$	119,272	$	189,272
RockPile credit facility due March 2019		104,887		54,130
TUSA 6.75% notes due July 2022		429,500		415,889
5% convertible note		135,877		141,037
Other notes and mortgages payable		10,605		14,207
Total debt		800,141		814,535
Less current portion of debt:
Other notes and mortgages payable		(503)		(1,641)
Total long-term debt	$	799,638	$	812,894

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. The November 2015 semi-annual redetermination of the borrowing base was reaffirmed at $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 October 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.

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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 October 31, 2015, RockPile was in compliance with all financial covenants under the RockPile credit facility. Although it is difficult to forecast future operations in this low commodity price environment, RockPile could breach its ratio of consolidated debt to EBITDA (as defined in the credit agreement) in future quarters.  If RockPile were to breach this covenant in a future period, RockPile has a cure right to obtain a cash capital contribution from Triangle or another investor approved by Triangle (“Equity Cure”) on or before ten days following the date that its compliance certificates are due (45 days after quarter ends and 120 days after its fiscal year end) to cure such a breach. The cure amount is defined as the amount which, if added to EBITDA for the test period in which a default of the financial covenant occurred, would cause the financial covenant for such test period to be satisfied.  RockPile may exercise this cure right in no more than two of any four consecutive fiscal quarters and no more than five times during the term of the credit facility. To date, RockPile has not exercised an Equity Cure right.

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. 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 using the effective interest method over the life of the notes.

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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 nine months ended October 31, 2015, TUSA repurchased additional TUSA 6.75% Notes with a face value of $13.6 million for $8.3 million, immediately retired the repurchased notes, and recognized a gain on extinguishment of debt of $5.3 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 October 31, 2015, TUSA was in compliance with all covenants under the TUSA 6.75% Notes.

Convertible Note. On October 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, in whole or in part, into the Company’s common stock at a conversion rate of one share per $8.00 of outstanding balance.

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 October 31, 2015, $21.0 million of accrued interest has been added to the principal balance of the Convertible Note.

The Convertible Note does not have a stated maturity. Following July 31, 2017, if the trading price of the Company’s common stock exceeds $11.00 per share for 20 consecutive trading days and certain trading volume requirements are met, the Company can elect to redeem all (but not less than all) of the Convertible Note at a price equal to the outstanding principal amount plus accrued and unpaid interest, payable, at the Company’s option, in cash or common stock. Following July 31, 2020, the Company can elect to redeem all (but not less than all) of the Convertible Note at a price equal to the outstanding principal plus accrued and unpaid interest, payable in cash. Further, following July 31, 2022 or a change of control of the Company, the holder of the Convertible Note will have the right to require the Company to redeem the Convertible Note at a price equal to the outstanding principal amount plus accrued and unpaid interest, with an additional make-whole payment for scheduled interest payments remaining if such right is exercised prior to July 31, 2017.

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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 six 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. 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 Nine Months Ended
	October 31,				October 31,
(in thousands)	2014		2015		2014		2015
Realized commodity derivative gains (losses)	$	688	$	27,857	$	(3,084)	$	64,341
Unrealized commodity derivative gains (losses)		19,134		(21,044)		16,529		(46,453)
Commodity derivative gains (losses), net	$	19,822	$	6,813	$	13,445	$	17,888

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

				Weighted		Weighted		Weighted
	Contract		Quantity	Average		Average		Average
	Type	Basis (1)	(Bbl/d)	Put Strike		Call Strike		Price
November 1, 2015 to January 31, 2016	Collar	NYMEX	995	$	80.00	$	95.78		n/a
November 1, 2015 to January 31, 2016	Swap	NYMEX	1,995		n/a		n/a	$	60.19
February 1, 2016 to January 31, 2017	Swap	NYMEX	2,175		n/a		n/a	$	56.13
February 1, 2017 to January 31, 2018	Swap	NYMEX	2,745		n/a		n/a	$	53.36

(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.

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The estimated fair values of commodity derivatives included in the consolidated balance sheets at January 31, 2015 and October 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. 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		October 31, 2015
Current Assets:
Crude oil derivative contracts	$	54,775	$	8,329
Other Long-Term Assets:
Crude oil derivative contracts		—		463
Total derivative asset	$	54,775	$	8,792
Long-Term Liabilities:
Crude oil derivative contracts	$	—	$	470
Total derivative liability	$	—	$	470

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 Nine Months Ended
(in thousands, except per share data)	October 31, 2014
Operating revenues	$	427,708
Net income (loss)	$	57,110
Earnings (loss) per common share
Basic	$	0.67
Diluted	$	0.58
Weighted average common shares outstanding:
Basic		85,769
Diluted		103,421

The pro forma information includes the effects of adjustments for depreciation and amortization expense of $3.4 millionfor the nine month period ended October 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.

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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 nine 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 October31, 2015 and the strike prices for exercising warrants as of October 31, 2015:

	Expiration		Strike Price at		As of	As of
	Date		October 31, 2015		January 31, 2015	October 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 nine months ended October 31, 2015:

	For the Nine Months Ended
(in thousands)	October 31, 2015
Balance at January 31, 2015	$	64,411
Capital contributions		—
Distributions		—
Equity investment share of net income before intra-company profit eliminations		2,700
Change in fair value of warrants		3,398
Gain on Caliber capital transactions		2,880
Balance at October 31, 2015	$	73,389
Fair value of warrants at October 31, 2015	$	3,900

Equity Investment Derivatives. At January 31, 2015 and October 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.

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8.  CAPITAL STOCK

The Company had 106.8 million shares of common stock issued or reserved for issuance at October 31, 2015. At October 31, 2015, the Company had 75.7 million shares of common stock issued and outstanding. The Company also had 1.7 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2011 Omnibus Incentive Plan, 6.0 million shares of common stock reserved for issuance under its CEO Stand-Alone Stock Option Agreement, 3.1 million shares of common stock reserved for issuance pursuant to outstanding awards under its 2014 Equity Incentive Plan (the “2014 Plan”), and 2.7 million shares of reserved common stock that remained available for issuance under the 2014 Plan. Lastly, the Company had 17.6 million shares of common stock reserved for issuance pursuant to the Convertible Note.

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 nine months ended October 31, 2015. As of October 31, 2015, the number of shares of common stock remaining available for repurchase under the Board approved program was 5,591,645 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 October 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 nine months ended October 31, 2014 and 2015, the Company recorded share-based compensation as follows:

	For the Three Months Ended				For the Nine Months Ended
	October 31,				October 31,
(in thousands)	2014		2015		2014		2015
Restricted stock units	$	1,298	$	4,078	$	4,572	$	8,741
Stock options		627		4,144		1,600		6,189
RockPile Series B Units		146		117		363		252
		2,071		8,339		6,535		15,182
Less amounts capitalized to oil and natural gas properties		(244)		(573)		(893)		(1,282)
Compensation expense	$	1,827	$	7,766	$	5,642	$	13,900

Restricted Stock Units. During the nine months ended October 31, 2015, the Company granted 1,983,843 restricted stock units as compensation to employees, officers, and directors which generally vest over one to five years. As of October31, 2015, there was approximately $19.7 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 3.2 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.

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The following table summarizes the activity for our restricted stock units during the nine months ended October31, 2015:  

		Weighted
		Average
	Number of	Award Date
	Shares	Fair Value
Restricted stock units outstanding - January 31, 2015	2,914,045	$	7.92
Units granted	1,983,843	$	4.74
Units forfeited	(78,788)	$	8.07
Units vested	(700,506)	$	8.27
Restricted stock units outstanding - October 31, 2015	4,118,594	$	6.33

Stock Options. There were no grants, exercises or forfeitures of stock options during the nine months ended October31, 2015. The following table summarizes the stock options outstanding at October 31, 2015:  

		Remaining
Exercise Price		Contractual Life	Number of Shares
per Share		(years)	Outstanding		Exercisable
$	7.50	7.68		750,000		150,000
$	8.50	7.68		750,000		150,000
$	10.00	7.68		1,500,000		300,000
$	12.00	7.68		1,500,000		300,000
$	15.00	7.68		1,500,000		300,000
$	12.00	5.86		233,333		77,770
$	14.00	5.86		233,333		77,770
$	16.00	8.87		233,334		77,770
				6,700,000		1,433,310
Weighted average exercise price per share			$	11.54	$	11.70
Weighted average remaining contractual life				7.59		7.55

As of October 31, 2015, there was approximately $12.4 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 2.6 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 nine months ended October 31, 2015:

	Series	Series	Series	Series	Series	Series
	B-1units	B-2 units	B-3 units	B-4 units	B-5 units	B-6 units	Total
Units outstanding - January 31, 2015	2,920,000	60,000	910,000	1,412,000	—	—	5,302,000
Units redeemed	—	—	—	—	—	—	—
Units granted	—	—	—	—	397,500	257,500	655,000
Units forfeited	—	—	(96,000)	(74,000)	—	—	(170,000)
Units outstanding - October 31, 2015	2,920,000	60,000	814,000	1,338,000	397,500	257,500	5,787,000
Vested	2,920,000	60,000	352,000	117,600	—	—	3,449,600
Unvested	—	—	462,000	1,220,400	397,500	257,500	2,337,400

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Series B Units currently have a 1 to 44 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 October 31, 2015, there was approximately $2.5 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 October 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 October 31, 2015
(in thousands)	Level1		Level 2		Level 3		Total
Assets:
Commodity derivative assets	$	—	$	8,792	$	—	$	8,792
Equity investment derivative assets	$	—	$	—	$	3,900	$	3,900
Liabilities:
Commodity derivative liabilities	$	—	$	(470)	$	—	$	(470)
RockPile earn-out liability	$	—	$	(1,257)	$	—	$	(1,257)

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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 October 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 October 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 carrying amount of the Company’s revolving credit facilities approximated fair value because the interest rate of the facilities is variable and 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 (Level 1).  The Convertible Note’s estimated fair value is based on discounted cash flows analysis and option pricing (Level 3). 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				October 31, 2015
	Carrying		Estimated		Carrying		Estimated
(in thousands)	Value		FairValue		Value		Fair Value
Revolving credit facilities	$	224,159	$	224,159	$	243,402	$	243,402
TUSA 6.75% notes		429,500		303,871		415,889		185,537
5% convertible note		135,877		137,790		141,037		123,940
Other notes and mortgages payable		10,605		10,605		14,207		14,207

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 $315.4 million was outstanding at October 31, 2015.

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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 in March 2015. 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 nine months ended October 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 Nine Months Ended October 31,
(in thousands)	2014		2015
Cash paid during the period for:
Interest expense	$	5,672	$	17,222
Income taxes	$	550	$	-
Non-cash investing activities:
Additions (reductions) to oil and natural gas properties through:
Increase (decrease) in accounts payable and accrued liabilities	$	103,415	$	(47,554)
Capitalized stock based compensation	$	893	$	1,282
Change in asset retirement obligations	$	1,519	$	425

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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 nine months ended October 31, 2015

· Average daily production volumes were 13,656  Boe/day for the nine months ended October 31, 2015, compared to 10,330  Boe/day for the nine months ended October 31, 2014, an increase of 32%.

· TUSA spud 16 gross (12.9 net) operated wells and completed 16 gross (11.6 net) operated wells during the nine months ended October 31, 2015. As of October 31, 2015, TUSA had 18 gross (15.8 net) operated wells that have been drilled and were pending completion.

· Lower average realized prices of $39.14per Boe for the nine months ended October 31, 2015, versus $78.56 per Boe for the nine months ended October 31, 2014, resulted in oil, natural gas and natural gas liquids sales for the nine months ended October 31, 2015 of $145.9 million compared to $221.5 million for the nine months ended October 31, 2014.

· RockPile completed 16 TUSA wells and 114 third-party wells in the nine months ended October 31, 2015, as compared to 41 TUSA wells and 62 third-party wells in the nine months ended October 31, 2014.

· Oilfield services revenue for the nine months ended October 31, 2015 was $147.3 million compared to $194.5 million for the nine months ended October 31, 2014.  

· The competitive oilfield services pricing environment resulted in a negative gross profit of $8.9 million for the nine months ended October 31, 2015 compared to a gross profit of $42.6 million for the nine months ended October 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  October 31, 2015, resulting in an impairment of $659.0 million for the nine months ended October 31, 2015.

· Cash flows provided by operating activities were $142.5 million for the nine months ended October 31, 2015 compared to $102.4 million for the nine months ended October 31, 2014.

· The borrowing base for TUSA’s credit facility was reaffirmed at $350.0 million for the November 2015 redetermination.

Drilling and Completions

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

	For the Three Months Ended				For the Nine Months Ended
	October 31, 2015				October 31, 2015
	Spud		Completed		Spud		Completed
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Operated wells	—	—	2	1.7	16	12.9	16	11.6
Non-operated wells	—	—	1	0.0	4	0.1	32	0.9
	—	—	3	1.7	20	13.0	48	12.5

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 October 31, 2015, we have completed a total of 112gross  (81.6net) operated wells in the Williston Basin and have an interest in approximately 474 gross (26.4 net) non-operated wells.

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We released our last drilling rig in August 2015 and have temporarily suspended our drilling program. 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.

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

	For the Nine Months Ended
	October 31,
(in thousands)	2014		2015
Costs incurred during the period
Acquisition of properties:
Proved	$	91,075	$	770
Unproved		41,768		67
Exploration		150,985		55,358
Development		170,743		86,263
Oil and natural gas expenditures		454,571		142,458
Asset retirement obligations, net		1,519		425
	$	456,090	$	142,883

For the three and nine months ended October 31, 2015, we recorded impairments to our oil and natural gas properties of $261.0 million and $659.0 million, respectively, primarily due to the significant decline in oil, natural gas and natural gas liquids prices. The trailing twelve month reference prices at October 31, 2015 were $55.37 per Bbl of oil, $2.89 per MMbtu for natural gas and $26.60 per Bbl of natural gas liquids. For the three and nine months ended October 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 October 31, 2015 had been $50.12 per Bbl of oil, $2.48 per MMbtu for natural gas and $23.41 per Bbl of natural gas liquids and all other factors remained constant, our impairment for the nine months ended October 31, 2015 would have increased, on a pro forma basis, by approximately $108 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 November 30, 2015 and the prices for November 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.

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U.S. Leasehold

As of October 31, 2015, we have under lease approximately 234,108 gross and 104,137 net acres in the Williston Basin, with approximately 195,951 gross and 77,739 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	163,956	62,747	19,008	5,671	182,964	68,418
Montana	8,112	6,187	43,032	29,532	51,144	35,719
Total Williston Basin	172,068	68,934	62,040	35,203	234,108	104,137

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 Nine Months Ended
	October 31,				October 31,
Oil and Natural Gas Operations	2014		2015		2014		2015
Production volumes:
Crude oil (Mbbls)		947		987		2,382		3,027
Natural gas (MMcf)		654		814		1,589		2,304
Natural gas liquids (Mbbls)		69		136		173		317
Total barrels of oil equivalent (Mboe)		1,125		1,259		2,820		3,728
Average daily production volumes (Boe/d)		12,228		13,685		10,330		13,656
Average realized prices:
Crude oil ($ per Bbl)	$	79.11	$	40.74	$	86.17	$	45.31
Natural gas ($ per Mcf)	$	4.59	$	2.51	$	5.88	$	2.76
Natural gas liquids ($ per Bbl)	$	32.24	$	4.52	$	39.94	$	7.63
Total average realized price ($ per Boe)	$	71.22	$	34.05	$	78.56	$	39.14
Oil, natural gas and natural gas liquids revenues (in thousands):
Crude oil	$	74,896	$	40,210	$	205,251	$	137,142
Natural gas		3,004		2,046		9,337		6,352
Natural gas liquids		2,239		615		6,891		2,418
Total oil, natural gas and natural gas liquids revenues	$	80,139	$	42,871	$	221,479	$	145,912
Operating expenses (in thousands):
Lease operating expenses	$	7,317	$	10,135	$	18,741	$	32,413
Gathering, transportation and processing		4,380		6,537		11,915		19,526
Production taxes		8,637		4,052		23,662		14,288
Oil and natural gas amortization expense		27,876		21,728		70,015		74,634
Impairment of oil and natural gas properties		—		261,000		—		659,000
Accretion of asset retirement obligations		259		75		324		222
Total operating expenses	$	48,469	$	303,527	$	124,657	$	800,083
Operating expenses per Boe:
Lease operating expenses	$	6.50	$	8.05	$	6.65	$	8.69
Gathering, transportation and processing	$	3.89	$	5.19	$	4.23	$	5.24
Production taxes	$	7.68	$	3.22	$	8.39	$	3.83
Oil and natural gas amortization expense	$	24.78	$	17.26	$	24.83	$	20.02

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

Oil, Natural Gas and Natural Gas Liquids Revenues.  Revenues from oil, natural gas and natural gas liquids for the three months ended October 31, 2015 decreased 47% to $42.9 million from $80.1 million for the three months ended October 31, 2014. Total production increased 12% due to our drilling and completion program. This increase in production was offset by a 52% decrease in weighted average realized prices from $71.22 per Boe for the three months ended October 31, 2014 to $34.05 per Boe for the three months ended October 31, 2015.

Lease Operating Expenses. Lease operating expenses increased to $8.05 per Boe for the three months ended October 31, 2015 from $6.50 per Boe for the three months ended October 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 the remainder of fiscal year 2016 than in the prior year due to the increased workover and higher produced water disposal costs and the fewer number of newly completed wells compared to fiscal year 2015.

Gathering, Transportation and Processing. Gathering, transportation and processing expenses increased to $5.19 per Boe for the three months ended October 31, 2015 compared to $3.89 per Boe for the three months ended October 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 processing 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 53% in the third quarter of fiscal year 2016 to $4.1 million from $8.6 million for the third quarter of fiscal year 2015. The 47% decrease in oil, natural gas and natural gas liquids revenues for the three months ended October 31, 2015 versus the three months ended October 31, 2014 is the primary reason for the decrease.

Oil and Natural Gas Amortization.  Oil and natural gas amortization expense decreased 22% to $21.7 million for the three months ended October 31, 2015 from $27.9 million for the three months ended October 31, 2014. On a per Boe basis, our oil and natural gas amortization expense decreased by $7.52 from $24.78 for the three months ended October 31, 2014 to $17.26 for the three months ended October 31, 2015 primarily due to the impairments recorded in the first two quarters of fiscal year 2016.

Impairment Expense.During the third quarter of fiscal year 2016, we recorded a $261.0 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 third 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 October 31, 2015, RockPile performed hydraulic fracturing, cased-hole wireline, pressure pumping and workover services for TUSA and 13 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 76% decrease in consolidated oilfield services revenues from $94.1 million for the three months ended October 31, 2014 to $22.3 million for the three months ended October 31, 2015. Hydraulic fracturing services resulted in 27 total well completions (2 for TUSA and 25 for third-parties) for the three months ended October 31, 2015 compared to 43 total well completions (17 for TUSA and 26 for third-parties) for the three months ended October 31, 2014.

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The current competitive oilfield services pricing environment has resulted in a negative gross profit of $5.5 million for the quarter ended October 31, 2015 compared to a gross profit of $18.9 million for the quarter ended October 31, 2014, after eliminations of $(0.1) million and $15.7 million of intercompany gross profit, respectively. We expect that the oilfield services pricing environment will continue to be very challenging as long as oil and natural gas prices remain near current levels, resulting in compressed profit levels compared to the prior year.

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

	For the Three Months Ended October 31, 2014						For the Three Months Ended October 31, 2015
(inthousands)	OilfieldServices		Eliminations		Consolidated		OilfieldServices		Eliminations		Consolidated
Revenues
Oilfield services	$	143,475	$	(49,418)	$	94,057	$	25,803	$	(3,530)	$	22,273
Total revenues		143,475		(49,418)		94,057		25,803		(3,530)		22,273
Cost of sales
Oilfield services		102,710		(31,905)		70,805		24,664		(2,964)		21,700
Depreciation		6,119		(1,791)		4,328		6,797		(700)		6,097
Total cost of sales		108,829		(33,696)		75,133		31,461		(3,664)		27,797
Gross profit	$	34,646	$	(15,722)	$	18,924	$	(5,658)	$	134	$	(5,524)

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

	For the Three Months Ended October 31, 2014								For the Three Months Ended October 31, 2015
	Exploration								Exploration
	and		Oilfield				Consolidated		and		Oilfield				Consolidated
(in thousands)	Production		Services		Corporate		Total		Production		Services		Corporate		Total
Salaries and benefits	$	1,264	$	3,836	$	2,625	$	7,725	$	450	$	4,138	$	2,338	$	6,926
Share-based compensation		94		146		1,587		1,827		390		117		7,259		7,766
Other general and administrative		2,966		3,207		1,068		7,241		405		1,198		2,139		3,742
Total	$	4,324	$	7,189	$	5,280	$	16,793	$	1,245	$	5,453	$	11,736	$	18,434

Total general and administrative expenses increased $1.6 million to $18.4 million for the three months ended October 31, 2015 compared to $16.8 million for the three months ended October  31, 2014. The increase in corporate general and administrative expenses is primarily a result of higher share based compensation costspartly 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 October 31, 2015, we recognized a gain of $6.8 million on our commodity derivative positions due to decreases in underlying crude oil prices, as compared to a gain of $19.8 million for the three months ended October 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 $27.9 million in the third quarter of fiscal year 2016, as compared to a realized commodity derivative gain of $0.7 million in the third quarter of fiscal year 2015.

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.

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Income from Equity Investment. Our equity investment in Caliber consists of Class A Units and equity derivative instruments. The Company recognized a $1.1 million loss on its equity investment derivatives in the third quarter of fiscal year 2016 compared to a $0.7 million gain during the third 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 October 31, 2015, the Company recognized $0.8 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 Caliber and capitalized by the Company, resulting in recognized income of $0.5 million. During the three months ended October 31, 2014, the Company recognized $1.0 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 $0.4 million.

Interest Expense.  The $9.9 million in interest expense for the three months ended October 31, 2015 consists of (i) approximately $1.2 million in interest related to the TUSA credit facility, (ii) approximately $0.8million in interest expense associated with RockPile’s credit facility and notes payable, (iii) approximately $7.1 million in interest related to the TUSA 6.75% Notes, (iv) approximately $1.8million in accrued interest related to the Convertible Note,  and (v)approximately $0.1 million in interest expense related to our other debt, all net of approximately $1.1 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. Approximately $2.2 million of interest expense and capitalized interest was paid in cash.

The $9.0 million in interest expense for the three months ended October 31, 2014 consists of (i) approximately $0.5 million in interest related to the TUSA credit facility, (ii) approximately $0.7 million in interest expense associated with RockPile’s credit facility and notes payable (iii) approximately $7.6 million in interest related to the TUSA 6.75% Notes, (iv) approximately $1.7 million in accrued interest related to our Convertible Note, and (v)approximately $0.1million in interest expense related to our other debt, all net of approximately $1.6 million of capitalized interest. Approximately $1.0 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 October 31, 2015 compared to expense of $19.3 million for the three months ended October 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, $206.0 million for three months ended July 31, 2015 and $261.0 million for the three months ended October 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 $143.1 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, July 31, 2015 and October 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 or for state income taxes.

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Comparison of the Nine Month Period Ended October 31, 2015 to the Nine Month Period Ended October 31, 2014

Oil, Natural Gas and Natural Gas Liquids Revenues.  Revenues from oil, natural gas and natural gas liquids for the nine months ended October 31, 2015 decreased 34% to $145.9 million from $221.5 million for the nine months ended October 31, 2014. Total production increased 32% for the nine months ended October 31, 2015 compared to the nine months ended October 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 $78.56 per Boe for the nine months ended October 31, 2014 to $39.14 per Boe for the nine months ended October 31, 2015.

Lease Operating Expenses.  Lease operating expenses increased to $8.69 per Boe for the nine months ended October 31, 2015 from $6.65 per Boe for the nine months ended October 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 be higher for full fiscal year 2016 than in the prior year due to the increased workover and higher produced water disposal costs and the fewer number of newly completed wells compared to fiscal year 2015.

Gathering, Transportation and Processing. Gathering, transportation and processing expenses increased to $5.24 per Boe for the nine months ended October 31, 2015 compared to $4.23 per Boe for the nine months ended October 31, 2014. We often receive higher average realized prices by using Caliber’s facilities, partly offset by higher gathering, transportation, and processing 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 40% in the first nine months of fiscal year 2016 to $14.3 million from $23.7 million for the first nine months of fiscal year 2015. The 34% decrease in oil, natural gas and natural gas liquids revenues for the nine months ended October 31, 2015 versus the nine months ended October 31, 2014 is the primary reason for the decrease.

Oil and Natural Gas Amortization.  Oil and natural gas amortization expense increased 7% to $74.6 million for the nine months ended October 31, 2015 from $70.0 million for the nine months ended October 31, 2014. The increase is primarily related to increased production in the first nine months of fiscal year 2016 as compared to the first nine months of fiscal year 2015. On a per Boe basis, our oil and natural gas amortization expense decreased by $4.81 from $24.83 for the nine months ended October 31, 2014 to $20.02 for the nine months ended October 31, 2015 primarily due to increases in proved reserves from successful development and field extensions, and to the impairments recorded in the first two quarters of fiscal year 2016.

Impairment Expense. During the first nine months of fiscal year 2016, we recorded a $659.0 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 nine months of fiscal year 2015.

Oilfield Services Gross Profit.  For the nine months ended October 31, 2015, RockPile performed hydraulic fracturing, cased-hole wireline, pressure pumping and workover services for TUSA and 17 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 service pricing environment resulted in a24%decrease in consolidated oilfield services revenues from $194.5 million for the nine months ended October 31, 2014 to $147.3 million for the nine months ended October 31, 2015. Hydraulic fracturing services resulted in 130 total well completions (16 for TUSA and 114 for third-parties) for the nine months ended October 31, 2015 compared to 103 total well completions (41 for TUSA and 62 for third-parties) for the nine months ended October 31, 2014.

The current competitive oilfield services pricing environment has resulted in a negative gross profit of $8.9 million for the nine months ended October 31, 2015 compared to a gross profit of $42.6 million for the nine months ended October 31, 2014, after eliminations of $8.1 million and $34.7 million of intercompany gross profit, respectively. We expect that the oilfield services pricing environment will continue to be very challenging as long as oil and natural gas prices remain near current levels, resulting in compressed profit levels compared to the prior year.

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

	For the Nine Months Ended October 31, 2014						For the Nine Months Ended October 31, 2015
(in thousands)	Oilfield Services		Eliminations		Consolidated		Oilfield Services		Eliminations		Consolidated
Revenues
Oilfield services	$	306,962	$	(112,474)	$	194,488	$	175,828	$	(28,575)	$	147,253
Total revenues		306,962		(112,474)		194,488		175,828		(28,575)		147,253
Cost of sales
Oilfield services		215,288		(73,219)		142,069		151,603		(17,720)		133,883
Depreciation		14,399		(4,600)		9,799		25,004		(2,766)		22,238
Total cost of sales		229,687		(77,819)		151,868		176,607		(20,486)		156,121
Gross profit	$	77,275	$	(34,655)	$	42,620	$	(779)	$	(8,089)	$	(8,868)

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

	For the Nine Months Ended October 31, 2014								For the Nine Months Ended October 31, 2015
	Exploration								Exploration
	and		Oilfield				Consolidated		and		Oilfield				Consolidated
(in thousands)	Production		Services		Corporate		Total		Production		Services		Corporate		Total
Salaries and benefits	$	4,065	$	9,496	$	6,958	$	20,519	$	1,375	$	12,907	$	8,636	$	22,918
Share-based compensation		832		363		4,447		5,642		1,086		252		12,562		13,900
Other general and administrative		7,385		7,895		2,844		18,124		1,161		4,029		5,874		11,064
Total	$	12,282	$	17,754	$	14,249	$	44,285	$	3,622	$	17,188	$	27,072	$	47,882

Total general and administrative expenses increased $3.6 million to $47.9 million for the nine months ended October 31, 2015 compared to $44.3 million for the nine months ended October 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 nine months ended October 31, 2015, we recognized a gain of $17.9 million on our commodity derivative positions due to decreases in underlying crude oil prices, as compared to a gain of $13.4 million for the nine months ended October 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 $64.3 million in the first nine months of fiscal year 2016, as compared to a realized commodity derivative loss of $3.1 million in the first nine months of fiscal year 2015.

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.

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Income from Equity Investment.  Our equity investment in Caliber consists of Class A Units and equity derivative instruments. The Company recognized a $3.4 million gain on its equity investment derivatives in the first nine months of fiscal year 2016 compared to a $3.7 million gain during the first nine months of fiscal year 2015 related to the change in the fair value of the equity investment derivatives. In addition, during the nine months ended October 31, 2015, the Company recognized $2.7million for its share of Caliber’s net income for the period. This income was offset by $0.9 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 $1.8 million. During the nine months ended October 31, 2014, the Company recognized $2.0 million for its share of Caliber’s net income for the period. This income was offset by $1.5 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 a recognized income of $0.5 million. In addition, we recognized a gain in the first nine 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 $28.8 million in interest expense for the nine months ended October 31, 2015 consists of (i) approximately $3.2 million in interest related to the TUSA credit facility, (ii) approximately $2.3million in interest expense associated with RockPile’s credit facility and notes payable, (iii) approximately $21.7 million in interest related to the TUSA 6.75% Notes, (iv) approximately $5.2 million in accrued interest related to the Convertible Note, and (v)approximately $0.2 million in interest expense related to our other debt, all net of approximately $3.8 million of capitalized interest which is generally incurred as exploratory wells are drilled and completed. Approximately $21.0 million of interest expense and capitalized interest was paid in cash.

The $15.9 million in interest expense for the nine months ended October 31, 2014 consists of (i) approximately $3.6 million in interest related to the TUSA credit facility, (ii) approximately $1.6million in interest expense associated with RockPile’s credit facility, (iii) approximately $9.0 million in interest related to the TUSA 6.75% Notes, (iv) approximately $4.9 million in accrued interest related to our Convertible Note,  and (v)approximately $0.2 million in interest expense related to our other debt, all net of approximately $3.4 million of capitalized interest. Approximately $5.7 million of interest expense and capitalized interest was paid in cash.

Income Taxes.  As noted above, we recorded a full valuation allowance against our net deferred tax assets in the first nine months of fiscal year 2016, and we recognized a benefit of $53.4 million compared to an expense of $39.7 million for the nine months ended October 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 affect the demand for services provided by RockPile and/or Caliber.

In the first nine months of fiscal year 2016, our average realized price for oil was $45.31 per barrel, a decrease of 47% over the average realized price for the first nine 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 nine 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 seek to 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.However, our commodity derivative contracts entered into prior to the aforementioned dramatic decrease in the price of oil expire by December 31, 2015.  Although we have entered into additional commodity derivative contracts for production in fiscal years 2017 and 2018, those contracts were entered into during the depressed commodity pricing environment, and we will be exposed to continued volatility in crude oil market prices, whether favorable or unfavorable.

As of October 31, 2015, we had cash of approximately $36.3 million consisting primarily of cash held in bank accounts, as compared to approximately $67.9 million at January 31, 2015. At October 31, 2015, we also had available borrowing capacity of $160.7 million under the TUSA credit facility and $95.9 million under the RockPile credit facility.

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As of October 31, 2015, we had approximately $814.5 million of debt outstanding, consisting of $189.3 million for the TUSA credit facility, $54.1 million for the RockPile credit facility,  $415.9 million for the TUSA 6.75% Notes, $141.0 million for the Convertible Note, and $14.2 million for other notes and mortgages.

Cash Flows

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

	For the Nine Months Ended October 31,
(inthousands)	2014		2015
Net cash provided by operating activities	$	102,423	$	142,474
Net cash used in investing activities		(402,810)		(181,503)
Net cash provided by financing activities		271,873		7,408
Net increase (decrease) in cash and equivalents	$	(28,514)	$	(31,621)

Net Cash Provided by Operating Activities.  Cash flows provided by operating activities were $142.5 million for the nine months ended October 31, 2015, compared to $102.4 million for the nine months ended October 31, 2014. Cash flows from operating activities were unfavorably impacted in the nine months ended October 31, 2015 by lower realized oil prices and the competitive oilfield services pricing environment compared to the nine months ended October 31, 2014, offset by favorable changes in current assets and current liabilities in the nine months ended October 31, 2015.

Net Cash Used in Investing Activities.  During the nine months ended October 31, 2015, we used $181.5 million in cash in investing activities compared to $402.8 million during the nine months ended October 31, 2014. During the nine months ended October 31, 2015 and 2014, we used $182.2 million and $218.3 million, respectively, on oil and natural gas property expenditures and $0.8 million and $132.8 million, respectively, to acquire oil and natural gas properties. During the nine months ended October 31, 2015 and 2014, we also spent $7.3 million and $41.3 million, respectively, on purchases of oilfield services equipment and $4.7 million and $12.1 million, respectively, on other property and equipment, primarily facility construction and improvements. During the nine months ended October 31, 2015, we received net proceeds of $6.0 million from the sale of a salt water disposal well to Caliber and $7.5 million from the sale of equipment.

Net Cash Provided by Financing Activities.Cash flows provided by financing activities for the nine months ended October 31, 2015 totaled $7.4 million, as compared to $271.9 million for the nine months ended October 31, 2014. Our primary source of cash from financing activities during the nine months ended October 31, 2015 came from $19.2 million in net borrowings from our credit facilities. Our primary financing activities during the nine months ended October 31, 2014 included the issuance of $450.0 million of the TUSA 6.75% Notes and net repayments on our credit facilities of $119.9 million.

Capital Requirements Outlook

Our cash flows from operations for the first nine 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 challenging oilfield services market, will continue to limit our cash flows from operations in upcoming quarters.

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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. While we work toward cash flow neutrality in fiscal year 2017, we will likely remain dependent on borrowings under our credit facilities and, to a lesser extent, potential additional financings to fund any 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 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 achieving cash flow neutrality or 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, development costs, and the availability of third party work for RockPile. Consequently, our production volume growth is expected to flatten or decrease throughout the remainder of fiscal year 2016, and the benefit we receive from our production will 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 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 nine months of fiscal year 2016 primarily due to efforts to remain competitive in the current oil and natural gas pricing environment by significantly 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 October 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 October 31, 2015, we had $160.7 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. TUSA’s borrowing base was reaffirmed at $350.0 million in the November 2015 redetermination. We anticipate that our borrowing base will be reduced in fiscal year 2017 if oil and natural gas prices do not rebound significantly.As of October 31, 2015, our maximum credit available under the RockPile credit facility was $150.0 million, and we had $95.9 million of borrowing capacity available. Notwithstanding a potential future borrowing base reduction under the TUSA credit facility, we expect that the 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, particularly as we drive toward cash flow neutrality in fiscal year 2017.

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As of October 31, 2015, RockPile was in compliance with all financial covenants under the RockPile credit facility. Although it is difficult to forecast future operations in this low commodity price environment, RockPile could breach its ratio of consolidated debt to EBITDA (as defined in the credit agreement) in future quarters.  If RockPile were to breach this covenant in a future period, RockPile has a cure right to obtain a cash capital contribution from Triangle or another investor approved by Triangle (“Equity Cure”) on or before ten days following the date that its compliance certificates are due (45 days after quarter ends and 120 days after its fiscal year end) to cure such a breach. The cure amount is defined as the amount which, if added to EBITDA for the test period in which a default of the financial covenant occurred, would cause the financial covenant for such test period to be satisfied.  RockPile may exercise this cure right in no more than two of any four consecutive fiscal quarters and no more than five times during the term of the credit facility. To date, RockPile has not exercised an Equity Cure right.

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 a  $22.3 million deficit as of October 31, 2015, as compared to $37.7 million of working capital 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.

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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 six 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 October 31, 2015 are summarized below:

				Weighted		Weighted		Weighted
	Contract		Quantity	Average		Average		Average
	Type	Basis (1)	(Bbl/d)	Put Strike		Call Strike		Price
November 1, 2015 to January 31, 2016	Collar	NYMEX	995	$	80.00	$	95.78		n/a
November 1, 2015 to January 31, 2016	Swap	NYMEX	1,995		n/a		n/a	$	60.19
February 1, 2016 to January 31, 2017	Swap	NYMEX	2,175		n/a		n/a	$	56.13
February 1, 2017 to January 31, 2018	Swap	NYMEX	2,745		n/a		n/a	$	53.36

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

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 October 31, 2015, the fair value of our commodity derivatives was a net asset of $8.3 million.  An assumed increase of 10% in the forward commodity prices used in the October31, 2015 valuation of our derivative instruments would result in a net derivative liability of approximately $1.3 million at October 31, 2015. Conversely, an assumed decrease of 10% in forward commodity prices would result in a net derivative asset of approximately $17.9 million at October 31, 2015.

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Interest Rate Risk.  As of October 31, 2015, we had $350.0 million of borrowing availability under the TUSA credit facility, of which $189.3 million was drawn at quarter-end. The credit facility bears interest at variable rates. Assuming we had the maximum amount outstanding at October 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 October 31, 2015, RockPile had an aggregate of $150.0 million available for borrowing under its credit facility of which approximately $54.1 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 October 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 TUSA 6.75% Notes and the Convertible Note 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 October31, 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 October 31, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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 October 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
August 1, 2015 to August 31, 2015	8,647		$	3.56	—	5,374,890	(3)
September 1, 2015 to September 30, 2015	54,747			2.97	—	5,591,645	(4)
October 1, 2015 to October 31, 2015	11,204			1.50	—	5,591,645
	74,598	(1)	$	2.82	—

(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 October 31, 2015, an aggregate of 11,431,744 shares of the Company’s common stock have been repurchased under the program.

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

(4) Includes an additional 216,755 shares of common stock potentially issuable pursuant to the paid-in-kind interest added to the principal balance of the Convertible Note on September 30, 2015.

Item 3.  Defaults Upon Senior Securities.

None.

Item 4.  Mine Safety Disclosures.

Not Applicable.

Item 5.  Other Information.

On August 1, 2015, new legislation took effect in the State of Delaware that expressly authorizes a Delaware corporation to adopt bylaws that provide that the sole and exclusive forum for certain legal actions involving such corporation will be courts located within Delaware. On December 2, 2015, the Board of Directors of the Company, upon the recommendation of the Nominating and Corporate Governance Committee of the Board of Directors, approved an amendment and restatement of the Company’s Bylaws, which became effective immediately, to update the Company’s Bylaws to specify certain Delaware courts as the exclusive forum for certain legal actions (the “Forum Provisions”). With the exception of the Forum Provisions set forth in Article X, and corresponding changes to the Table of Contents, no other changes were made to the existing Bylaws.

The Company believes the Forum Provisions can greatly reduce the costs, complexities and inefficiencies associated with litigating certain types of legal actions in multiple jurisdictions. Moreover, acknowledging their expertise in adjudicating Delaware law, Delaware courts should provide greater consistency in litigation outcomes to the benefit of all the Company’s stockholders.  At the same time, the Company believes that maintaining the ability to consent to an alternative forum on a case-by-case basis offers flexibility to meet the best interest of its stockholders.

The description of the amendment and restatement of the Company’s Bylaws is qualified in its entirety by reference to the text of the Bylaws, as amended, attached hereto as Exhibit 3.3 and incorporated herein by reference.

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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*	Amended and Restated Bylaws of Triangle Petroleum Corporation.
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.

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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:  December 8,  2015	By:	/s/ JONATHAN SAMUELS
	Jonathan Samuels
	President and Chief Executive Officer

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

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