Triangle Petroleum (TPLMQ) 10-Q 2014 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended April 30, 2013

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGEACT 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	(I.R.S. Employer
Incorporation or Organization)	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  x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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).    x  Yes  o No

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

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

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

As of May 31, 2013, there were 56,415,404 shares of the registrant’s common stock outstanding.

TRIANGLE PETROLEUM CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTERLY PERIOD ENDED APRIL 30, 2013

PART I.  FINANCIAL INFORMATION
	ITEM 1.	Financial Statements
		Condensed Consolidated Balance Sheets — April 30, 2013 and January 31, 2013	3
		Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) — Three months ended April 30, 2013 and 2012	4
		Condensed Consolidated Statements of Cash Flows — Three months ended April 30, 2013 and 2012	5
		Condensed Consolidated Statement of Stockholders’ Equity — Three months ended April 30, 2013	6
		Notes to Condensed Consolidated Financial Statements	7
	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	32
	ITEM 4.	Controls and Procedures	35
PART II. OTHER INFORMATION
	ITEM 1.	Legal Proceedings	36
	ITEM 1A.	Risk Factors	36
	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36
	ITEM 3.	Defaults Upon Senior Securities	36
	ITEM 4.	Mine Safety Disclosures	36
	ITEM 5.	Other Information	36
	ITEM 6.	Exhibits	37
	SIGNATURES		39

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Triangle Petroleum Corporation

Condensed Consolidated Balance Sheets

(In thousands, except share data)

(Unaudited)

	April 30,			January 31,
	2013			2013
ASSETS
CURRENT ASSETS
Cash and equivalents	$	54,448		$	33,117
Deposits and prepaid expenses	1,497			904
Accounts receivable:
Oil and natural gas sales	11,888			10,625
Trade	37,978			28,541
Other	854			955
Investment in marketable securities	5,474			5,065
Derivative asset	1,160			603
Inventory	1,657			1,403
Total current assets	114,956			81,213
LONG-TERM ASSETS
Oil and natural gas properties at cost, using the full cost method of accounting:
Unproved properties and properties under development, not being amortized	97,020			94,529
Proved properties	281,276			220,894
	378,296			315,423
Less: accumulated amortization	(23,273		)	(16,666		)
Net oil and natural gas properties	355,023			298,757
Pressure pumping equipment (less accumulated depreciation of $3.5 million and $2.5 million, respectively)	27,934			18,878
Other property and equipment (less accumulated depreciation of $1.2 million and $0.9 million, respectively)	18,761			15,779
Equity investment	21,364			11,768
Derivative asset	363			—
Deposits on equipment	—			182
Other long-term assets	2,178			1,745
Total assets	$	540,579		$	428,322
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	18,512		$	37,043
Accrued liabilities:
Exploration and development	44,324			30,433
Other	9,374			7,486
Notes payable	5,876			—
Short-term borrowings on Credit Facilities	2,450			—
Asset retirement obligations	2,783			2,949
Total current liabilities	83,319			77,911
LONG-TERM LIABILITIES
Long-term borrowings on Credit Facilities	68,812			25,000
5% Convertible Note	124,561			123,023
Asset retirement obligations	394			473
Derivative liability	—			292
Total liabilities	277,086			226,699
COMMITMENTS AND CONTINGENCIES (Note 11)
STOCKHOLDERS’ EQUITY
Common stock, $0.00001 par value, 140,000,000 shares authorized; 56,414,709 and 46,733,011 shares issued and outstanding at April 30, 2013 and January 31, 2013, respectively	—			—
Additional paid-in capital	380,302			323,643
Accumulated deficit	(116,809		)	(122,020		)
Accumulated other comprehensive income	—			—
Total stockholders’ equity	263,493			201,623
Total liabilities and stockholders’ equity	$	540,579		$	428,322

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

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Triangle Petroleum Corporation

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

(In thousands, except share data)

(Unaudited)

	For the three months ended April 30,
	2013			2012
REVENUES:
Oil and natural gas sales	$	21,060		$	5,172
Pressure pumping services	13,120			—
Other	114			69
Total revenues	34,294			5,241
EXPENSES:
Production taxes	2,444			592
Other lease operating expenses	2,216			243
Gathering, transportation and processing	37			10
Depletion, depreciation and amortization	7,473			2,173
Accretion of asset retirement obligations	8			83
Pressure pumping	11,186			186
General and administrative:
Stock-based compensation	1,595			1,365
Salaries and benefits	3,125			2,166
Other general and administrative	1,784			1,759
Total operating expenses	29,868			8,577
INCOME (LOSS) FROM OPERATIONS	4,426			(3,336		)
OTHER INCOME (EXPENSE):
Income from derivative activities	1,212			—
Interest expense	(1,472		)	(10		)
Income from equity investment	596			—
Interest income	37			13
Other income (loss)	412			9
Total other income (expense)	785			12
NET INCOME (LOSS) BEFORE INCOME TAXES	5,211			(3,324		)
Income tax provision	—			—
NET INCOME (LOSS)	5,211			(3,324		)
Less: net (income) loss attributable to noncontrolling interest in subsidiary	—			296
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	5,211		$	(3,028	)
Net income (loss) per common share outstanding - basic	$	0.10		$	(0.07	)
Net income (loss) per common share outstanding - diluted	$	0.10		$	(0.07	)
Weighted average common shares outstanding - basic	52,605,152			44,057,927
Weighted average common shares outstanding - diluted	53,003,901			44,057,927
COMPREHENSIVE INCOME (LOSS):
Net income (loss) attributable to common stockholders	$	5,211		$	(3,028	)
Other comprehensive income (loss)	—			—
Total comprehensive income (loss)	$	5,211		$	(3,028	)

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

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Triangle Petroleum Corporation

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

	For the three months ended April 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	5,211		$	(3,324	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	7,473			2,173
Stock-based compensation	1,595			1,704
Interest expense not paid in cash	1,625			—
Accretion of asset retirement obligations	8			83
Unrealized income on derivatives	(1,212		)	—
Unrealized income on equity investment	(596		)	—
Unrealized income on securities held for investment	(409		)	—
Changes in related current assets and liabilities:
Prepaid expenses and deposits	(403		)	(414		)
Accounts receivable:
Oil and natural gas sales	(1,263		)	(2,231		)
Trade	(9,437		)	941
Other	101			421
Inventory	(254		)	—
Accounts payable and accrued liabilities	6,008			3,175
Asset retirement expenditures	(165		)	(73		)
Cash provided by (used in) operating activities	8,282			2,455
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and natural gas property expenditures	(70,933		)	(19,921		)
Sale of oil and natural gas properties	—			2,712
Purchase of pressure pumping equpment	(10,113		)	(16,829		)
Purchase of other property and equipment	(3,117		)	428
Investment in Caliber Midstream Partners, L.P.	(9,000		)	—
Cash used in investing activities	(93,163		)	(33,610		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common stock	55,800			—
Proceeds from credit facilities	46,638			—
Repayments to credit facility	(5,000		)	—
Proceeds from RockPile note payable	10,500			—
Debt issuance costs	(709		)	—
Cash paid to settle tax on vested restricted stock units	(1,017		)	(1,406		)
Issuance of common stock for exercise of options	—			13
Cash provided by (used in) financing activities	106,212			(1,393		)
NET INCREASE (DECREASE) IN CASH	21,331			(32,548		)
CASH, BEGINNING OF PERIOD	33,117			68,815
CASH, END OF PERIOD	$	54,448		$	36,267

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

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Triangle Petroleum Corporation

Condensed Consolidated Statement of Stockholders’ Equity

For the Three Months Ended April 30, 2013

(in thousands, except share data)

(Unaudited)

	Shares of Common Stock	Common Stock at Par Value		Additional Paid-in Capital			Accumulated Deficit			Total Equity
Balance - January 31, 2013	46,733,011	$	0.467	$	323,643		$	(122,020	)	$	201,623
Shares issued at $6.00/share	9,300,000	0.093		55,800			—			55,800
Vesting of restricted stock units (net of shares surrendered for taxes)	381,698	0.004		(1,017		)	—			(1,017		)
Stock-based compensation	—	—		1,876			—			1,876
Net income for the period	—	—		—			5,211			5,211
Balance - April 30, 2013	56,414,709	$	0.564	$	380,302		$	(116,809	)	$	263,493

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

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Triangle Petroleum Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

1.  Organization and Nature of Operations

Triangle Petroleum Corporation (“Triangle” or the “Company” or “we” or “our”) is an oil and natural gas exploration and development company currently focused on the acquisition and development of unconventional shale oil resources in the Bakken Shale and Three Forks formations in the Williston Basin of North Dakota and Montana.

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

The Company also holds leasehold interests in acreage in the Maritimes Basin of Nova Scotia, which we fully impaired as of January 31, 2012.

2.  Basis of Presentation and Significant Accounting Policies

The accompanying condensed consolidated balance sheet as of January 31, 2013 has been derived from our audited financial statements.  The accompanying unaudited condensed interim consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) and are expressed in U.S. dollars.  These condensed consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries: (i) Triangle USA Petroleum Corporation (“TUSA”), incorporated in the State of Colorado, and its wholly-owned subsidiaries, (ii) RockPile Energy Services, LLC (“RockPile”), organized in the state of Delaware, and its wholly-owned subsidiaries, (iii) Elmworth Energy Corporation, incorporated in the Province of Alberta, Canada, (iv) Leaf Minerals, LLC, organized in the State of Colorado, (v) Integrated Operating Solutions, LLC, organized in the State of Colorado, (vi) Caliber Midstream, LLC, organized in the State of Delaware, and (vii) Triangle Caliber Holdings, LLC, organized in the State of Delaware.  All significant intercompany balances and transactions have been eliminated.  The Company accounts for its 30% voting interest in Caliber Midstream Partners, L.P. and 50% voting interest in Caliber Midstream GP LLC under the equity method.  The Company’s fiscal year-end is January 31.

Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“U.S. 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 condensed consolidated financial statements be read in conjunction with our audited financial statements and notes included in our Annual Report on Form 10-K for the fiscal year ended January 31, 2013, filed with the SEC on May 1, 2013 and amended on May 31, 2013 to incorporate the Part III information (“Fiscal 2013 Form 10-K”).

In the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for the interim period. The results of operations for the three month period ended April 30, 2013 are not necessarily indicative of the operating results for the entire fiscal year ending January 31, 2014.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, including contingent assets and liabilities at the date of the financial statements, and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.  Estimates of oil and natural gas reserve quantities provide the basis for the calculation of depletion, depreciation, amortization and the full cost ceiling test, each of which represents a significant component of the consolidated financial statements.  Management estimated the proved reserves as of April 30, 2013 with consideration of (1) the proved reserve estimates for the prior fiscal year-end prepared by independent engineering consultants and

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(2) any significant new discoveries and changes during the interim period in production, ownership, and other factors underlying reserve estimates.

RockPile’s July 2012 Change in Fiscal Year-end to January 31

With the start of RockPile operations in July 2012, RockPile changed in July 2012 to a January 31 fiscal year-end, as further discussed in Note 2 — Basis of Presentation in our audited financial statements included in our Fiscal 2013 Form 10-K.  The accompanying Statements of Operations and Comprehensive Income (Loss) and Cash Flows for the three months ended April 30, 2012 have been adjusted to reflect the change in RockPile’s year-end, whereby for that period Triangle’s net loss attributable to common stockholders increased by $0.1 million (with no change in reported loss per share), and net cash flow changed from a $35.4 million decrease to a $37.8 million decrease (primarily due to $2.7 million additional RockPile expenditures for equipment).

Significant Accounting Policies

For descriptions of the Company’s significant accounting policies, see Note 3 — Summary of Significant Accounting Policies in our audited financial statements included in our Fiscal 2013 Form 10-K.

Amortization of oil and natural gas property costs is computed on a closed quarter basis, using the estimated proved reserves as of the end of the quarter.  Amortization for the fiscal year is the sum of the four quarterly amortization amounts.

Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board issued Accounting Standards Update 2011-11 (“ASU 2011-11”), Balance Sheet: Disclosures about Offsetting Assets and Liabilities which applies to certain items in the statement of financial position (balance sheet), and was further clarified in January 2013 by ASU 2013-01, Balance Sheet: Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarified the scope of ASU 2011-11 to derivative instruments, repurchase agreements and securities lending transactions.  The effective date for the amendments is for annual periods beginning after January 1, 2013, and interim periods within those annual periods.  ASU 2011-11 requires disclosures of the gross and net amounts for items eligible for offset in the balance sheet.  The Company records its derivative financial instruments on a net basis by contract.  The gross amounts are disclosed in Note 9 — Commodity Derivative Instruments.  The adoption of this standard had no impact on the Company’s financial position or results of operations.

Reclassifications

Certain amounts in the condensed consolidated statements of operations and comprehensive income (loss) and cash flows for the quarter ended April 30, 2012 have been reclassified to conform to the financial statement presentation for the quarter ended April 30, 2013.  Such reclassifications had no impact on the consolidated net loss nor the net change in cash previously reported.

8

Asset Retirement Obligations

The following table reflects the change in asset retirement obligations for the periods ended April 30, 2013 and 2012 (in thousands):

	For the three months ended
	April 30, 2013			April 30, 2012
Balance, beginning of period	$	3,422		$	1,623
Liabilities incurred	100			4
Revision of estimates	(187		)	—
Sale of assets	—			(8		)
Liabilities settled	(166		)	(73		)
Accretion	8			83
Balance, end of period	3,177			1,629
Less current portion of obligations	(2,783		)	(1,548		)
Long-term asset retirement obligations	$	394		$	81

The $187,000 favorable revision is primarily a result of a change in the timing of plugging and abandoning wells from 30 years to 50 years after a well is placed on production.

The $2.8 million current liability at April 30, 2013 consists of (a) an estimated $1.4 million for (i) reclamation in the current fiscal year of man-made “ponds” holding produced formation water and (ii) the plugging and abandonment in the current fiscal year of well bores in the Maritimes Basin of Canada, and (b) $1.4 million for the estimated remaining costs to plug and abandon in the current year several producing (but marginally economic) vertical wells drilled years ago on North Dakota leases we acquired in the second half of fiscal year 2013.  These North Dakota leases are “held by production”, i.e., continue in force by production.  We intend to drill, complete and produce horizontal wells on the leases in fiscal year 2014, allowing us to plug and abandon the marginally economic vertical wells and still hold the leases by production.

Investment in Marketable Securities

At April 30, 2013, our $5,473,955 investment in marketable securities consisted of 851,315 shares of Emerald Oil Inc. (“Emerald”) common stock (NYSE symbol EOX), acquired in the January 9, 2013 sale of oil and gas leases to Emerald.  These marketable securities are classified as available-for-sale securities and are included as a current asset in the consolidated balance sheets.  We have elected the fair value option for this investment in equity securities and are therefore recording the change in fair value during the period in the statement of operations.  The cost basis of the Company’s available-for-sale securities as of April 30, 2013 was $4.9 million.  We recorded an unrealized gain of $408,631 for the three months ended April 30, 2013 which was included in other income (loss) on the consolidated statements of operations and comprehensive income (loss) for that period.

3.  Segment Reporting

In accordance with accounting guidance for disclosures about segments of an enterprise and related information, we have two reportable operating segments.  The Company 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 all operations are in the United States.  The exploration and production operating segment is responsible for finding and producing oil and natural gas.  The pressure pumping services operating segment is responsible for pressure pumping for both Triangle-operated wells and wells operated by third-parties.

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Management evaluates the performance of our segments based upon income (loss) before income taxes.  The following table presents selected financial information for Triangle’s operating segments for the first quarter of fiscal year 2014 (in thousands).

	Corporate and Other (1)			Exploration and Production		RockPile’s Pressure Pumping and Other Services			Eliminations and Other			Consolidated Total
Revenues
Oil and natural gas sales	$	—		$	21,060	$	—		$	—		$	21,060
Pressure pumping services for third parties	—			—		15,030			(1,910		)	13,120
Intersegment revenues	—			—		11,739			(11,739		)	—
Other	276			—		114			(276		)	114
Total revenues	276			21,060		26,883			(13,925		)	34,294
Expenses
Production taxes and other lease operating	—			4,660		—			—			4,660
Gathering, transportation and processing	—			37		—			—			37
Depletion, depreciation and amortization	123			6,618		1,239			(507		)	7,473
Accretion of asset retirement obligations	—			8		—			—			8
Pressure pumping	—			—		19,121			(7,935		)	11,186
General and Administrative:												—
Stock-based compensation	1,062			322		211			—			1,595
Other general and administrative	1,466			1,464		1,979			—			4,909
Total operating expenses	2,651			13,109		22,550			(8,442		)	29,868
Income (loss) from operations	(2,375		)	7,951		4,333			(5,483		)	4,426
Other income (expense)	(415		)	1,353		(153		)	—			785
Net income (loss) before income taxes	$	(2,790	)	$	9,304	$	4,180		$	(5,483	)	$	5,211
Total Assets	$	406,324		$	424,252	$	66,379		$	(356,376	)	$	540,579
Net oil and natural gas properties	$	—		$	360,506	$	—		$	(5,483	)	$	355,023
Pressure pumping equipment	$	—		$	—	$	27,934		$	—		$	27,934
Other property and equipment - net	$	1,654		$	1,619	$	15,488		$	—		$	18,761
Total Liabilities	$	127,537		$	151,344	$	30,165		$	(31,960	)	$	277,086

(1)Corporate and other includes our corporate office and several subsidiaries that management does not consider in the exploration and production or pressure pumping segments.  These subsidiaries have limited activity.

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4.  Property and Equipment

Property and equipment at April 30, 2013 and January 31, 2013, consisted of the following (in thousands):

	April 30,			January 31,
	2013			2013
Oil and natural gas properties, full cost method:
Unproved properties and properties under development, not being amortized	$	97,020		$	94,529
Proved properties	281,276			220,894
	378,296			315,423
Less accumulated amortization	(23,273		)	(16,666		)
Net carrying value of oil and natural gas properties	355,023			298,757
Pressure pumping equipment	31,455			21,332
Other property and equipment	19,953			16,664
Deposits on equipment under construction	—			182
Less accumulated depreciation and amortization	(4,713		)	(3,339		)
Net property and equipment	$	401,718		$	333,596

During the three months ended April 30, 2013, we acquired oil and natural gas properties and participated in the drilling and/or completion of wells, for total consideration of approximately $70.9 million ($1.4 million for the acquisition of undeveloped leaseholds) in cash.

In the three months ended April 30, 2013, we capitalized $0.7 million of internal land, geology and operations department costs directly associated with property acquisition, exploration (including lease record maintenance) and development.  The internal land and geology department costs were capitalized to unevaluated costs.

Pressure pumping equipment consists primarily of costs for two frac spreads.  Of the $31.5 million, $21.3 million is currently in service and $10.1 million is expected to be placed into service in the third quarter of fiscal year 2014.

Other property and equipment is located in the U.S. and consists of the following:

·$7.2 million for a RockPile administrative and services facility and residential living facilities that are being constructed in North Dakota,

·$1.7 million for RockPile wireline and pressure pumping equipment,

·$3.7 million for a RockPile sand plant in North Dakota, and

·$7.4 million which is primarily vehicles and office equipment and furniture for RockPile and the Corporate office.

The Company recorded an out-of-period adjustment to increase both proved property costs, and accumulated depreciation and amortization, by $1.721 million.  This adjustment relates to the period as of January 31, 2013.  Management does not believe that the out-of-period adjustment is material to the period affected or the periods presented in this Form 10-Q.

Ceiling-Test Impairments

The Company uses the full-cost accounting method, which requires recognition of an impairment of oil and natural gas properties when the total net carrying value of oil and natural gas properties exceeds a ceiling as described in Note 3 — Summary of Significant Accounting Policies in our audited financial statements included in our Fiscal 2013 Form 10-K.  The Company did not have such impairments for the three-month periods ended April 30, 2013 and 2012, respectively.

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5. Investment in Unconsolidated Affiliate

On October 1, 2012, Triangle Caliber Holdings, LLC (“Triangle Caliber Holdings”), a wholly owned subsidiary of Triangle, entered into a joint venture with FREIF Caliber Holdings LLC (“FREIF Caliber Holdings”), a wholly owned subsidiary of First Reserve Energy Infrastructure Fund, L.P. The newly formed joint venture entity, Caliber Midstream Partners, L.P. (“Caliber”), plans to provide crude oil, natural gas and water transportation and processing services to the Company and third parties primarily within the Williston Basin of North Dakota and Montana. For further discussion of the Caliber agreements, see Note 7 — Investment in Unconsolidated Affiliate in our Fiscal 2013 Form 10-K.

We use the equity method of accounting for our investment in Caliber, with earnings or losses reported in “Income from equity investment” line on the condensed consolidated statement of operations and comprehensive income (loss).

As of April 30, 2013, the balance of Triangle’s investment was $21.4 million. The investment balance was increased by $9.0 million from additional contributions by TPC and by $0.6 million which was Triangle’s share of Caliber’s net income for the three months ended April 30, 2013.

6. Stockholders’ Equity

Common Stock

The following transactions occurred during the three months ended April 30, 2013 with regard to shares of the Company’s common stock:

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

·We issued 381,698 shares of common stock (net of shares surrendered for taxes) for restricted stock units that vested during the period.

Restricted Stock Units

During the three months ended April 30, 2013, the Company granted 349,133 restricted stock units as compensation to officers, directors and employees. The restricted stock units vest over one to five years. As of April 30, 2013, there was approximately $13.3 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 2.4 years. When restricted stock units vest, the holder has the right to receive one share of the Company’s common stock per vesting unit. The following table summarizes the status of restricted stock units outstanding:

	Number of Shares		Weighted- Average Award Date Fair Value
Restricted stock units outstanding - January 31, 2012	2,488,342		$	7.02
Units granted in fiscal year 2013	1,041,400		$	6.37
Units forfeited in fiscal year 2013	(105,600	)	$	7.59
Units that vested in fiscal year 2013	(1,000,057	)	$	6.90
Restricted stock units outstanding - January 31, 2013	2,424,085		$	6.68
Units granted during the three months ended April 30, 2013	349,133		$	6.40
Units forfeited during the three months ended April 30, 2013	(13,146	)	$	6.41
Units that vested during the three months ended April 30, 2013	(539,213	)	$	7.47
Restricted stock units outstanding - April 30, 2013	2,220,859		$	6.44

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For the three months ended April 30, 2013, the Company recorded stock-based compensation related to restricted stock units of $1.4 million in general and administrative expenses. An additional $0.3 million of stock based compensation was capitalized to oil and natural gas properties.

Stock Options

The following table summarizes the status of stock options outstanding under the Rolling Plan (for a discussion of the Rolling Plan, see Note 10 — Share-Based Compensation in our audited financial statements included in our Fiscal 2013 Form 10-K):

	Number of Shares		Weighted Average Exercise Price
Options outstanding - January 31, 2012 (142,500 exercisable)	235,833		$	1.50
Less: options exercised	(4,167	)	$	3.00
Options outstanding - January 31, 2013 (231,666 exercisable)	231,666		$	1.48
Less: options exercised	—
Options outstanding - April 30, 2013 (231,666 exercisable)	231,666		$	1.48

The following table presents additional information related to the stock options outstanding at April 30, 2013:

		Remaining
Exercise price		contractual life	Number of shares
per share		(years)	Outstanding		Exercisable
$	3.00	0.75	30,000		30,000
$	1.25	1.59	201,666		201,666
			231,666		231,666
Weighted average exercise price per share			$	1.48	$	1.48
Weighted average remaining contractual life (years)			1.5		1.5

As of April 30, 2013, there is no remaining unrecognized compensation expense related to stock options. All options became fully vested in fiscal year 2013. The aggregate intrinsic value of the options as of April 30, 2013 and 2012 was $0.9 million and $0.9 million, respectively.

RockPile Share Based Compensation

At April 30, 2013, RockPile (a LLC) had 30,000,000 Series A Units authorized by the LLC Agreement (as defined below) with 25,543,210 Series A Units outstanding, all of which are owned by Triangle. Series A Units were issued to the three parties who had contributed the initial $24,000,000 in RockPile’s paid-in capital prior to October 31, 2011.  Triangle had contributed $20,000,000 and received 20,000,000 Series A Units by October 31, 2011.  On December 28, 2012, Triangle acquired an aggregate of 4,000,000 Series A Units from the other two original owners of Series A units. On February 15, 2013, Triangle made an additional capital contribution of $5,000,000 to acquire an 1,543,210 authorized Series A Units.

Effective October 22, 2012, RockPile’s Board of Directors approved the Second Amended and Restated Limited Liability Company Agreement (“LLC Agreement”) which includes provisions allowing RockPile to make equity grants in

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the form of restricted units (“Series B Units”) pursuant to Equity Grant Agreements. The LLC Agreement, which was formally executed by RockPile and its members on October 31, 2012, authorizes RockPile to issue an aggregate of up to 6,000,000 Series B Units in multiple series designated by a sequential number (i.e., Series B-1, Series B-2, etc.) with the right to re-issue forfeited or redeemed Series B Units. As of April 30, 2013, RockPile had granted 3,160,000 Series B Units, of which 1,501,667 were unvested at that date. The grants were made to several RockPile employees in key positions at RockPile.

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

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

Series B Units currently have an 8 to 28 month vesting period. Compensation costs are determined using a Black-Scholes option pricing model based upon the grant date calculated fair market value of the award and is recognized ratably over the applicable vesting period.

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

A summary of RockPile’s Series B Unit activity and vesting for the fiscal quarter ended April 30, 2013 is as follows:

	Series B-1 Units			Series B-2 Units
Balance, February 1, 2012	—			—
Units granted	3,100,000			60,000
Units vested	(1,658,333		)	—
Units unvested at January 31, 2013	1,441,667			60,000
Units granted	—			—
Units vested	—			—
Units unvested at April 30, 2013	1,441,667			60,000
Weighted average award date unit fair value	$	0.44		$	0.29
Remaining vesting period (years)	1.18			2.33

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Non-cash compensation cost related to the Series B Units was $211,253 for the fiscal quarter ended April 30, 2013.

As of April 30, 2013, there was $537,019 of unrecognized compensation cost related to non-vested Series B Units. We expect to recognize such cost on a pro-rata basis on the Series B Units vesting schedule during the next three fiscal years.

7. Earnings Per Share

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. Diluted net income per common share reflects increases in average shares outstanding from the potential dilution that could occur upon (i) exercise of options to acquire common stock and (ii) vesting of restricted stock units, both computed using the treasury stock method. That method 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) cash equaling the foregone future compensation expense of hypothetical early vesting of the RSUs outstanding, adjusted for certain assumed income tax effects.

The table below sets forth the computations of net loss per common share (basic and diluted) for the three months ended April 30, 2013 and 2012 (in thousands, except share data).

	For the three months ended April 30,
	2013		2012
Net income (loss) attributable to common shareholders	$	5,211	$	(3,028	)
Basic weighted average common shares outstanding	52,605,152		44,057,927
Effect of dilutive securities	398,749		—
Diluted weighted average common shares outstanding	53,003,901		44,057,927
Basic net income (loss) per share	$	0.10	$	(0.07	)
Diluted net income (loss) per share	$	0.10	$	(0.07	)

8. Notes Payable and Credit Facilities

As of the dates indicated, the Company’s debt consisted of the following (in thousands):

	April 30, 2013			January 31, 2013
TUSA Credit Facility	$	60,762		$	25,000
5% Convertible Note	124,561			123,023
RockPile Credit Facility	10,500			—
RockPile Notes Payable	5,876			—
Total debt	201,699			148,023
Less: Current portion	(8,326		)	—
Total debt, net of current portion	$	193,373		$	148,023

The weighted average effective interest rates of the loans were 4.1% at April 30, 2013 and 4.6% at January 31, 2013.

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TUSA Credit Facility

On April 12, 2012, TUSA entered into a Credit Agreement (the “TUSA Credit Facility”) with Wells Fargo Bank, National Association, as administrative agent and issuing lender and with other banks and financial institutions party thereto, as co-lenders (see Note 12 — Long-Term Debt in our audited financial statements included in our Fiscal 2013 Form 10-K).

On April 11, 2013, the TUSA Credit Facility was amended and restated to increase the maximum credit availability to $500 million, and the facility’s borrowing base was increased to $110 million. As of April 30, 2013, TUSA, as borrower, had borrowings of $61 million outstanding under the TUSA Credit Facility.

The borrowing base under the TUSA Credit Facility is subject to redetermination on a quarterly basis in July, October, January and April of each year. In addition, TUSA has the option to request one unscheduled interim redetermination prior to May 1, 2014 during any year and two additional redeterminations after May 1, 2014 during any year. With a five-year term, all borrowings under the TUSA Credit Facility mature on April 11, 2018.

Convertible Note

On July 31, 2012, the Company sold to NGP a $120,000,000 Convertible Note (the”Convertible Note”) that became convertible after November 16, 2012 into Company common stock at a conversion rate of one share per $8.00 of note principal (see Note 12 — Long-Term Debt in our audited financial statements included in our Fiscal 2013 Form 10-K).

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 will be paid-in-kind by adding to the principal balance of the Convertible Note; provided that, following the fifth anniversary of closing, the Company has the option to make such interest payments in cash. As of April 30, 2013, $1.6 million of accrued interest has been added to the principal balance of the Convertible Note.

RockPile Credit Facility

On February 25, 2013, RockPile entered into a Credit and Security Agreement (the “RockPile Credit Agreement”) between RockPile, as borrower, and Wells Fargo Bank, National Association, as lender (the “Lender”).  The RockPile Credit Agreement provides for a maximum borrowing of $20,000,000.  Borrowings under the RockPile Credit Agreement are available to: (i) provide for the working capital and general corporate requirements of RockPile, (ii) purchase equipment, (iii) pay any fees and expenses in connection with the Credit Agreement, and (iv) support letters of credit.   The maturity date of the RockPile Credit Agreement is February 25, 2016, unless sooner terminated as provided in the credit agreement. The RockPile Credit Agreement has three components:

i)Equipment Term Loan: The equipment term loan has a maximum borrowing of $10,500,000. The loan bears interest at the daily three month LIBOR plus 4.50%. Payments on this loan are interest only until September 2013 at which time monthly principle payments of $350,000 plus monthly accrued and unpaid interest will be due. At April 30, 2013, the full $10,500,000 was outstanding, the interest rate was 4.875% and accrued and unpaid interest was $42,656.

ii)Discretionary Capex Term Loan: The discretionary capex term loan has a maximum borrowing of $2,000,000. As of April 30, 2013, there have been no draws on this loan. This loan will bear interest at the daily three month LIBOR plus 4.50%. Payments on this loan will be interest only for the first six months after which it will convert to equal monthly principle and interest installments in an amount that will satisfy the obligation by the maturity date.

iii)Revolving Loan: The revolving loan has a maximum borrowing of $7,500,000. RockPile can draw down on this facility from time to time in amounts not to exceed the maximum borrowing or an amount supported by a borrowing base certificate, whichever is less. As of April 30, 2013, there have been no draws on this loan. This loan will bear interest at the daily three month LIBOR plus 4.00%. Amounts outstanding under this loan may be repaid and reborrowed at any time.

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At April 30, 2013, there were no letters of credit outstanding.

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

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

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

RockPile Notes Payable to Dacotah Bank

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

At April 30, 2013, both loans were fully drawn with accrued and unpaid interest of $16,823.

9. Commodity Derivative Instruments

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

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

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

The Company’s commodity derivative contracts as of April 30, 2013 are summarized below:

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

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

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The following tables detail the fair value of the derivatives recorded in the applicable condensed consolidated balance sheet, by category (in thousands):

		As of April 30, 2013
Underlying Commodity	Location on Consolidated Balance Sheet	Gross Amount of Recognized Assets (Liabilities)		Gross Amount of Offset in the Consolidated Balance Sheets			Net Amount of Assets (Liabilities) Presented in the Consolidated Balance Sheet
Crude oil derivative contract	Current assets	$	1,708	$	(548	)	$	1,160
Crude oil derivative contract	Long-term assets	$	1,055	$	(692	)	$	363

		As of January 31, 2013
Underlying Commodity	Location on Consolidated Balance Sheet	Gross Amount of Recognized Assets (Liabilities)			Gross Amount of Offset in the Consolidated Balance Sheets			Net Amount of Assets (Liabilities) Presented in the Consolidated Balance Sheet
Crude oil derivative contract	Current assets	$	2,349		$	(1,747	)	$	602
Crude oil derivative contract	Long-term liabilities	$	(1,705	)	$	1,413		$	(292	)

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

	Three Months Ended April 30,
	2013		2012
Unrealized gain (loss) on derivative contracts	$	1,212	$	—
Realized gain (loss) on derivative contracts	—		—
Total gain on derivative contracts	$	1,212	$	—

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

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10.  Fair Value Measurements

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

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

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

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

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

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of April 30, 2013 by level within the fair value hierarchy (in thousands):

	Level 1		Level 2		Level 3		Total
Assets:
Investment in marketable securities	$	5,474	$	—	$	—	$	5,474
Derivative assets	$	—	$	1,523	$	—	$	1,523

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating.  In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments.  The Company considers its counterparty to be of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.  At April 30, 2013, derivative instruments utilized by the Company consist of both costless collars and single-day puts.  The crude oil derivative markets are highly active.  Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange.  As such, the Company has classified these instruments as Level 2.

The Convertible Note (carried at $124.6 million at April 30, 2013) has an estimated fair value at April 30, 2013 of $125.1 million, based on discounted cash flow analysis and option pricing (Level 3).  The decrease in fair value from January 31, 2013 is largely due to a decrease in option value for Triangle common stock’s closing price being $5.49/share at April 30, 2013 compared with $6.29/share at January 31, 2013.

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The following table presents the rollforward of Level 3 financial liabilities (in thousands):

Ending balance, January 31, 2012	$	—
Sale of Convertible Notes	120,000
Interest paid in-kind	3,023
Total net unrecognized loss	9,877
Ending balance, January 31, 2013	132,900
Interest paid in-kind	1,538
Total net unrecognized gain	(9,388		)
Ending balance, April 30, 2013	$	125,050

11.  Commitments and Contingencies

At April 30, 2013, there were no known environmental or other regulatory matters related to the Company’s operations that were reasonably expected to result in a material liability other than asset retirement obligations which are reflected on the balance sheet.  Compliance with environmental laws and regulations has not had, and is not expected to have, a material adverse effect on the Company’s financial position, results of operations or cash flows.

As of April 30, 2013 the Company was subject to commitments on several drilling rig contracts. The contracts expire in May 2013, September 2013, and April 2014. In the event of early termination of the contracts, the Company would be obligated to pay an aggregate amount of approximately $9.6 million as of April 30, 2013 as required under the terms of the contract.

12.  Supplemental Disclosures of Cash Flow Information

	For the three months ended April 30,
	(in thousands)
	2013			2012
Cash paid during the period for:
Interest expense	$	237		$	—
Non-cash investing activities:
Additions (reductions) to oil and natural gas properties through:
Increased (decreased) accrued liabilities and decreased prepaid well costs	$	(8,763	)	$	4,384
Issuance of common stock	$	—		$	1,204
Change in asset retirement obligations	$	(87	)	$	4
Capitalized stock-based compensation	$	282		$	—

13.  Income Taxes

The Company has net deferred tax assets as of April 30, 2013 primarily due to accumulated net operating losses.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.  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, projected future taxable income and tax planning strategies 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, (i) cumulative historical pre-tax earnings, (ii) consistent and sustained pre-tax earnings, (iii) sustained or continued improvements in oil and natural gas commodity prices, and (iv)

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continued increases in production and proved reserves. The Company will continue to evaluate whether a valuation allowance is needed in future reporting periods.  As of April 30, 2013 and 2012, a full valuation allowance was placed against net deferred tax assets.  As a result, no income tax expense or benefit was recorded for the three months ended April, 2013 and 2012.

Given the substantial net operating loss carry forwards 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 likely adjust net operating loss carry forwards.  As such, as of April 30, 2013, the Company has not recognized any interest or penalties related to uncertain tax benefits.

14.  Related Party Transactions

On October 1, 2012, TUSA entered into two midstream services agreements with Caliber North Dakota LLC (“Caliber North Dakota”).  Caliber North Dakota LLC is a wholly owned subsidiary of Caliber,LP in which TPLM has a 30% ownership.  The two agreements were as follows:  one for crude oil gathering, stabilization, treating and redelivery, and one for (i) natural gas compression, gathering, dehydration, processing and redelivery; (ii) produced water transportation and disposal services; and (iii) fresh water transportation for TUSA’s oil and natural gas drilling and production operations.  Under the agreements, TUSA committed to deliver minimum monthly revenues derived from the fees paid by TUSA to Caliber North Dakota for volumes of oil, natural gas, produced water, and fresh water for a primary term of 15 years beginning on the in-service date of the Caliber North Dakota facilities (the date on which the Caliber North Dakota central facility has been substantially completed and has commenced commercial operation, estimated to occur between July 31, 2013 and September 1, 2013).  As of April 30, 2013, no significant services had been provided to TUSA by Caliber North Dakota

Except for the Caliber North Dakota agreement discussed in the preceding paragraph, the Company had no reportable related party transactions in the three months ended April 30, 2013.

15.  Subsequent Events

We have evaluated subsequent events and are not aware of any significant events that occurred subsequent to April 30, 2013 but prior to the filing with the SEC of this Form 10-Q that would have a material impact on our consolidated financial statements, except for those items listed below.

On May 3, 2013 we entered into an 18-month, one-rig drilling contract with Pioneer Drilling Services Ltd, with an effective date of September 1, 2013.  The contract has a term of 548 days with a contracted day rate of $30,000 per day.  The minimum drilling commitment over the term of the contract is estimated to be $8.2 million.

On May 6, 2013, the Company purchased zero cost collars on the price of West Texas Intermediate crude oil at Cushing, buying puts to set a floor price and selling calls to set a ceiling price for the period from May 1, 2013 to December 31, 2013.  The collars have an $87.50 floor and a $100.00 ceiling and the contract is for 100 barrels of oil per day (“bopd”).

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16. Significant Changes in Proved Oil and Natural Gas Reserves

Our proved oil and natural gas reserves at April 30, 2013 significantly increased from our proved oil and natural gas reserves at January 31, 2013, as summarized in the table below (in thousands of barrels of oil equivalent, “Mboe”).   The proved reserves are in the Bakken or Three Forks formations in the North Dakota counties of McKenzie, Williams or Dunn.

Proved Oil and Natural Gas Reserves (Mboe):	January 31, 2013	April 30, 2013	Change		% Change
Proved producing	5,969	7,650	1,681		28	%
Proved undeveloped	8,668	8,400	(268	)	-3	%
Total proved	14,637	16,050	1,413		10	%

The primary reason for the increases in proved reserves is the drilling and completion of wells in the first three months of fiscal year 2014, whereby our net interest in producing wells increased 30% from 16 net wells at January 31, 2013 to 20.8 net wells at April 30, 2013, and our net interest in proved undeveloped locations decreased 3% from 19.8 net future development wells at January 31, 2013 to 19.2 net future development wells at April 30, 2013.   During the three months ended April 30, 2013, we drilled wells on 16 gross (2.7 net) of our January 31, 2013 proved undeveloped locations and reclassified their proved reserves from proved undeveloped to proved producing.

Our proved oil and natural gas reserves at January 31, 2013 have been derived from the reserve data in our Fiscal 2013 Form 10-K.  Our proved oil and natural gas reserves at April 30, 2013 were estimated by our in-house senior reservoir engineer, who has been a Registered Professional Engineer in Colorado since 1984 and has over 30 years’ experience as a petroleum engineer.

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

Forward-Looking Statements

We or our representatives may make forward-looking statements, oral or written, including statements in this Quarterly Report on Form 10-Q, press releases and filings with the Securities and Exchange Commission (“SEC”), regarding, among other things, estimated future net revenues from oil and natural gas reserves and the present value thereof, planned capital expenditures (including the amount and nature thereof), increases in oil and natural gas production, the number of wells we anticipate drilling in the future, the potential number of operated drill spacing units and well locations on our acreage, the timing of anticipated drilling, our financial position, business strategy and other plans and objectives for future operations. Although we believe that the expectations reflected in these forward-looking statements are reasonable, there can be no assurance that the actual results or developments anticipated by us will be realized or, even if substantially realized, that they will have the expected effects on our business or operations.  Among the factors that could cause actual results to differ materially from our expectations are general economic conditions, inherent uncertainties in interpreting engineering data, operating hazards, delays or cancellations of drilling operations for a variety of reasons, competition, fluctuations in oil and natural gas prices, availability of sufficient capital resources to us or our project participants, government regulations and other factors, including but not limited to, those set forth among the Risk Factors noted in our Fiscal 2013 Form 10-K and in this Quarterly Report on Form 10-Q under the heading “Item 1A.  Risk Factors”.  All subsequent oral and written forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors.  We assume no obligation to update any of these statements.

Overview

Triangle Petroleum Corporation (“Triangle” or the “Company” or “we” or “our”) is an independent energy company focused on the exploration, development and production of unconventional shale oil and natural gas resources in the United States.  Our oil and natural gas reserves and operations are primarily concentrated in the Bakken Shale and Three Forks formations of the Williston Basin in North Dakota and Montana.  As of April 30, 2013, we held leasehold interests in approximately 86,000 net acres primarily in McKenzie and Williams Counties of North Dakota and Roosevelt and Sheridan Counties of Montana.  Having identified an area of focus in the Bakken Shale and Three Forks formations that we believe will generate attractive returns on invested capital, we are continuing to explore further opportunities in the region.  Our proved oil and natural gas reserves as of April 30, 2013 totaled 16,050 MBoe.  We conduct our U.S. exploration and production operations through our wholly-owned subsidiary Triangle USA Petroleum Corporation (“TUSA”).

Our daily production for first quarter of fiscal year 2014 averaged approximately 2,714 Boepd of which 1,908 Boepd is net to our interests in wells we operate (“operated wells”) and 806 Boepd is from wells operated by third-parties (“non-operated wells”).  All production in fiscal year 2014 is from wells in North Dakota, primarily from the Bakken Shale formation and, to a lesser extent, the Three Forks formation.

As of May 31, 2013, we have completed a total of 23 (13.88 net) operated wells since entering the Williston Basin.  During fiscal year 2014, we anticipate drilling approximately 33 (15.7 net) operated wells and completing approximately 29 (13.2 net) operated wells in North Dakota or eastern Montana.  Of the 29 wells expected to be completed in fiscal year 2014, we have completed seven gross wells and have an additional eight gross wells in progress as of May 31, 2013.  Twenty-seven of the wells are planned to be in the Bakken Shale and two are planned for the Three Forks formation.  We also have economic interests in approximately 200 (8.55 net) non-operated wells.

In our core area of North Dakota and eastern Montana, Triangle is directing resources toward its operated program to develop its approximately 36,000 net acres, primarily in McKenzie and Williams County, North Dakota.  In Roosevelt County, Montana, our “Station Prospect” is a largely contiguous position within the thermally mature area of the Williston Basin. Our approximate 50,000 net acre position in the Station Prospect is predominantly operated acreage with an average remaining lease term of two and one half years and provides us with a development area that we believe is scalable for the future.

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With a focus on establishing an efficient development model, the Company is utilizing pad drilling, which expedites our operated program while controlling costs and minimizing environmental impact.  We also endeavor to use completion, collection and production techniques that optimize reservoir production while also reducing costs.  With the completion capacity of RockPile Energy Services, LLC (“RockPile”), our wholly-owned subsidiary, we are positioned to lower our well completion costs and have greater control over drilling and completion schedules.  Integrated solutions for water, oil and natural gas transportation and processing are to be provided by our 30% owned affiliate, Caliber Midstream Partners, L.P. (“Caliber”).  We expect to reduce the cost and environmental impacts of trucking, reduce or eliminate the emissions generated by the flaring of produced natural gas, and improve the efficiency and reduce the costs of winter and spring operations.

Summary of first quarter fiscal 2014 operating and financial results:

·Production volumes averaged 2,714 Boe per day, up 289% from 697 Boe per day for the first quarter of fiscal year 2013.

·Oil and natural gas sales were $21.1 million, compared to $5.2 million for the first fiscal quarter of fiscal year 2013.

·Our average realized oil price increased to $89.69 per barrel compared to $87.27 per barrel in the first quarter of fiscal year 2013.

·Proved reserves were 16,050 Mboe at April 30, 2013 compared to 2,000 Mboe at April 30, 2012.

·Net income of $5.2 million increased from net loss of $3.3 million in the first quarter of fiscal year 2013.

·Cash flow provided by operating activities was $8.3 million compared to cash used by operating activities of $2.4 million for the fiscal quarter ended April 30, 2012.

·Syndicated TUSA’s credit facility with an increased maximum credit availability of $500 million and a borrowing base of $110 million.

·Drilled and completed 5 gross (2.66 net) operated wells in the first quarter of fiscal year 2014.

Recent Events

RockPile Credit Facility

On February 25, 2013, RockPile entered into a Credit and Security Agreement (the “Credit Agreement”) by and between RockPile, as borrower, and Wells Fargo Bank, National Association, as lender (the “Lender”). The Credit Agreement provides for a $7,500,000 revolving loan facility, a $10,500,000 equipment term loan facility and a $2,000,000 capex term loan facility.  The $10,500,000 equipment term loan facility was fully drawn at closing and is the only amount outstanding under the Credit Agreement at April 30, 2013.

NGP Common Stock Purchase

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

TUSA Amended and Restated Credit Facility

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

Properties, Plan of Operations and Capital Expenditures

Williston Basin

We own operated and non-operated leasehold positions in the Williston Basin.  As of May 31, 2013, we have completed a total of 23 (13.88 net) operated wells and have economic interests in 201 (8.55 net) non-operated wells in the

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Williston Basin.  During fiscal year 2014, we anticipate drilling and completing an additional 29 (13.2 net) operated wells in North Dakota or eastern Montana for completion in the Bakken Shale or Three Forks formations.

Triangle is currently running a four-rig drilling program.  We anticipate continuing a four-rig program until late in the second quarter or early in the third quarter of fiscal year 2014 at which time we will cut back to a three-rig program for the remainder of fiscal year 2014.  The focus of our drilling program is on our core North Dakota acreage in McKenzie and Williams Counties.

Our non-operated leasehold positions are primarily conducted through agreements with major operators in the Williston Basin, including Hess Corporation (“Hess”), Continental Resources, Inc. (“Continental”), Statoil (formerly Brigham Exploration Company) (“Statoil”), Newfield Production Co. (“Newfield”), EOG Resources, Inc. (“EOG”), XTO Energy Inc. (now a part of ExxonMobil) (“XTO”), Whiting Petroleum Corporation (“Whiting”), Slawson Exploration, Inc. (“Slawson”), and Kodiak Oil and Gas Corporation (“Kodiak”).  These companies are experienced operators in the development of the Bakken Shale and Three Forks formations.  As of May 31, 2013, we have participated in the drilling of approximately 209 gross non-operated wells, including 160 producing wells and 49 wells in various stages of permitting, drilling or completion.

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

Our oil and natural gas property expenditures are summarized in the following tables for the periods indicated (in thousands):

	Three Months Ended April 30,
	2013		2012
Leasehold acquisitions	$	2,180	$	6,804
Drilling and Completion
Operated	42,898		10,060
Non-operated	16,768		5,818
Facilities and Infrastructure	1,115		—
	$	62,961	$	22,682

Other Properties

We have an 87% working interest in approximately 474,625 gross acres (approximately 412,924 net acres) of Nova Scotia oil and natural gas leases in the Windsor Sub-Basin of the Maritimes Basin.  The leases are to expire in 2019, but can be extended pending agreement of further development plans with the Nova Scotia regulators.  As of January 31, 2012, we fully impaired and expensed the carrying value of our oil and natural gas leases in the Maritimes Basin.

Results of Operations for the Three Months Ended April 30, 2013 Compared to the Three Months Ended April 30, 2012

For the fiscal quarter ended April 30, 2013, we recorded net income attributable to common stockholders of $5.2 million ($0.10 per share of common stock, basic and diluted) as compared to a net loss attributable to common stockholders of $3.0 million ($0.07 per share of common stock, basic and diluted) for the fiscal quarter ended April 30, 2012.

Oil and Natural Gas Operations

For the three months ended April 30, 2013, we had total oil and natural gas revenues of $21.1 million compared with $5.2 million for the three months ended April 30, 2012.  Oil and natural gas sales and production costs are summarized in the following table.  Oil and natural gas sales revenues for the three months ended April 30, 2013 increased by approximately 307% compared to the three months ended April 30, 2012.  The increases were substantially due to our

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operated wells placed on production in fiscal year 2013.

	Three months ended April 30,
(in thousands or as indicated)	2013			2012
U.S. oil and natural gas operations
Oil sold (barrels)	232,253			56,122
Average oil price per barrel	$	89.69		$	87.27
Oil revenue	$	20,831		$	4,897
Natural gas sold (mcf)	47,451			34,790
Average natural gas price per mcf	$	3.81		$	6.80
Natural gas revenue	$	181		$	237
Natural gas liquids sold (gallons)	57,249			32,758
Average natural gas liquids price per gallon	$	0.84		$	1.17
Natural gas liquids revenue	$	48		$	38
Total oil, natural gas and natural gas liquids revenues	$	21,060		$	5,172
Less production taxes	(2,444		)	(592		)
Less lease operating expense (excluding production taxes)	(2,216		)	(243		)
Less gathering, transportation and processing expense	(37		)	(10		)
Less oil and natural gas amortization expense	(6,607		)	(2,111		)
Less accretion of asset retirement obligations	(8		)	(2		)
Income (loss) from U.S. oil and natural gas production	$	9,748		$	2,214
Gross profit from pressure pumping services	1,934			(186		)
Other revenues	—			69
Income (loss) from U.S. operations	$	11,682		$	2,097
Canadian oil and natural gas operations
Accretion of asset retirement obligations	—			(82		)
Loss from Canadian oil and natural gas operations	—			(82		)
Income (loss) from operations	11,682			2,015
U.S. and Canadian other income (expense)
Income from derivative activities	1,212			—
Other income (expense)	1,159			13
Interest expense	(1,472		)	—
Less depreciation of furniture and equipment	(866		)	(62		)
Less general and administrative expenses	(6,504		)	(5,290		)
Net income (loss)	$	5,211		$	(3,324	)
Total U.S. barrels of oil equivalent (“boe”) sold	241,525			62,700
U.S. oil and natural gas revenue per boe sold	$	87.20		$	82.49
U.S. production tax per boe sold	$	10.12		$	9.44
U.S. other lease operating expense per boe sold	$	9.18		$	3.88
U.S. gathering, transportation and processing expense per boe sold	$	0.15		$	0.16
U.S. amortization expense per boe sold	$	27.36		$	33.67

Pressure Pumping Services

RockPile commenced operations in July 2012.  We formed RockPile with strategic objectives to have both greater control over our largest cost center as well as to provide locally-sourced, high-quality completion services to Triangle and other operators in the Williston Basin.  From formation through April 30, 2013,  RockPile has been focused on procuring new pressure pumping and complementary equipment, building physical and supply chain infrastructure in North Dakota,

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recruiting and training employees, establishing third-party customers in the Williston Basin, and securing multiple credit facilities.  RockPile’s results of operations are affected by a number of variables including drilling and stimulation activity in the Williston Basin, pricing environment, service performance, equipment utilization, and the ability to secure and retain third-party customers.

For the fiscal quarter ended April 30, 2013, RockPile performed hydraulic fracturing and complementary services for Triangle and two distinct third-party customers.  This work resulted in ten total well completions: five for Triangle and five for third-parties.  All Triangle wells were completed using plug-and-perf applications.  All third-party wells were completed using a sliding sleeve application.  RockPile revenue is comprised of service revenue, which is what we charge for equipment and labor, and materials revenue, which is what we charge for chemicals and proppant.  Pressure pumping direct costs include the cost of chemicals and proppant, labor (wages and benefits), logistic expenses, insurance, repairs and maintenance and safety costs.  Cost of goods sold as a percentage of revenue will vary based upon equipment utilization.

The $1.9 million of gross profit from pressure pumping services for the first quarter of fiscal year 2014 is after  elimination of $13.6 million in intercompany gross profit.  See Note 3 — Segment Reporting in the accompanying Condensed Consolidated Financial Statements.

U.S. Production Taxes

Due primarily to the 307% increase in oil and natural gas revenues for the quarterly period ended April 30, 2013, as compared with the quarterly period ended April 30, 2012, our U.S. production taxes increased approximately 300% to $2.4 million from $0.6 million for the same respective quarterly periods.  With rare exception, North Dakota production tax rates for the past two years were 11.5% of oil revenue and approximately $0.11 per mcf of natural gas.

Lease Operating Expense

Lease operating expense for U.S. operations (“LOE”) increased to $9.18 per Boe for the three months ended April 30, 2013 from $3.88 per Boe for the three months ended April 30, 2012. The increase is primarily the result of increased lease operating expenses associated with our operated properties. LOE for our operated properties was $10.09 per Boe for the three months ended April 30, 2013.  This amount includes approximately $3.23 per Boe for water disposal costs and $1.35 per Boe related to well workover costs. LOE for non-operated properties also increased from $3.88 per Boe for the three months ended April 30, 2012 to $7.00 per Boe for the three months ended April 30, 2013.

Gathering, Transportation and Processing

Gathering, transportation and processing (“GTP”) expenses decreased to $0.15 per Boe for the three months ended April 30, 2013 from $0.16 per Boe for the three months ended April 30, 2012.  Currently, all GTP costs are associated with non-operated wells and are primarily for the gathering and transportation of oil and natural gas.  Going forward we expect GTP costs to increase as natural gas gathering, transportation and processing infrastructure becomes available for operated wells during the second half of fiscal year 2014.

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

Oil and natural gas amortization expense increased to $6.6 million for the three months ended April 30, 2013 from $2.1 million for the three months ended April 30, 2012.  The increase is primarily related to a 285% increase in production in the first quarter of  fiscal year 2014 compared to the first quarter of fiscal year 2013.  The increase in production accounted for an additional $6.0 million in DD&A expense, which was offset by a reduction of $1.6 million due to a decreased DD&A rate.

Other

Other income (expense) of $1.1 million for the three months ended April 30, 2013 consists primarily of income from equity investment of $0.6 million and a gain on marketable securities of $0.4 million.   Interest expense of $1.5 million for the three months ended April 30, 2013 is primarily related to our convertible note with NGP.  A small part of the interest

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expense is interest paid on the TUSA credit facility and amortization of the capitalized loan costs related to our credit facilities and the NGP note.

General and Administrative Expenses

The following table summarizes general and administrative expenses for the quarterly periods ended April 30, 2013 and April 30, 2012, respectively (in thousands):

	Corporate		Exploration and Production		Pressure Pumping Services		Consolidated Total
For the quarter ended April 30, 2013
Stock-based compensation	$	1,062	$	322	$	211	$	1,595
Salaries, benefits and other general and administrative	1,466		1,464		1,979		4,909
Total	$	2,528	$	1,786	$	2,190	$	6,504
Excluded costs*	$	920	$	1,105	$	—	$	2,025
For the quarter ended April 30, 2012
Stock-based compensation	$	751	$	614	$	—	$	1,365
Salaries, benefits and other general and administrative	1,136		1,191		1,598		3,925
Total	$	1,887	1,805		1,598		5,290
Excluded costs*	$	—	$	386	$	—	$	386

*Excluded costs are (i) those personnel costs which are capitalized under the full cost accounting method as direct internal costs of acquisition, exploration and development of oil and gas properties, (ii) costs equal to overhead reimbursements charged by TUSA as well operator to third parties participating in TUSA-operated wells, and (iii) general and administrative expenses recovered by corporate charges to related entities for various general and administrative services.

Total general and administrative expense increased $1.2 million to $6.5 million at April 30, 2013 compared to $5.3 million at April 30, 2012.  The increase in corporate general and administrative is primarily a result of increased compensation and benefit costs for personnel as the corporate headcount increased due to the growth of the business.  The increase in general and administrative expenses at our Pressure Pumping Services segment is primarily attributable to increased compensation and benefit costs for personnel in RockPile’s headquarters and field offices as RockPile built its team and commenced operations in July 2012.

Liquidity and Capital Resources

Overview

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

Our primary cash requirements in our exploration and production segment are for exploration, development and acquisition of oil and natural gas properties.  Based on current prices, we anticipate capital requirements for fiscal year 2014 to be approximately $245 million.  These funds will be allocated primarily towards our operated drilling program.  We expect to be able to fund these expenditures, as well as other commitments and working capital requirements, using existing capital, future cash flow from operations, our reserve-based lending facility (with a current borrowing base of

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$110.0 million), and through participation in joint ventures and/or asset sales.  We may expand or reduce our capital expenditures depending on, among other things, the results of future wells and our available capital.

In the first quarter of fiscal year 2014, our average realized price for oil was $89.69 per barrel, an increase of 3% over the realized price for the same period of fiscal year 2013.  Future prices for oil will likely continue to fluctuate due to supply and demand factors, seasonality and other geopolitical and economic factors.

We manage volatility in commodity prices by maintaining flexibility in our capital investment program.  In addition, we periodically hedge a portion of our oil production to mitigate our potential exposure to price declines and the corresponding negative impact on cash flow available for investment.

As of April 30, 2013, we had cash of approximately $54.4 million consisting primarily of cash held in bank accounts, as compared to approximately $33.1 million at January 31, 2013.  Working capital was approximately $31.6 million as of April 30, 2013, as compared to approximately $3.3 million at January 31, 2013.  Debt outstanding at April 30, 2013 was $201.7 million.  See Note 8 — Notes Payable and Credit Facilities in the accompanying Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q for further discussion of debt outstanding.

Analysis of Changes in Cash Flows

Net Cash Provided by Operating Activities

Cash flows provided by operating activities was $8.3 million for the three months ended April 30, 2013.  Cash flows used in operating activities was $2.5 million for the three months ended April 30, 2012.  The increase in operating cash flows was primarily due to increased revenue at RockPile driven by increased third party pressure pumping business and higher oil revenues driven by higher sales volumes, partially offset by increases in production expenses, production taxes, general and administrative expenses, and other expenses associated with the growth of our operations during the year.

Net Cash Used in Investing Activities

In the three months ended April 30, 2013, investing activities used $93.1 million in cash compared to $33.6 million in the three months ended April 30, 2012.  The increase in cash flows used in investing activities in the first quarter of fiscal year 2014 was primarily due to our larger capital budget and drilling program, which used $70.9 million, and to the purchase of a second frac spread, facility construction and the purchase of equipment for complimentary services at RockPile, which used $10.1 million.   In addition to capital expenditures, we had a $9.0 million increase in cash used for the investment in Caliber.

Net Cash Provided by Financing Activities

Cash flows provided by financing activities for the three months ended April 30, 2013 totaled $106.2 million.  The cash in-flow was primarily a result of the issuance of 9.3 million shares to NGP and advances from notes payable and credit facilities.

Cash flows used in financing activities in the three months ended April 30, 2012 of $1.4 million was primarily cash paid to settle taxes on vested restricted stock units.

Commodity Price Risk Management

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth.  Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.  Historically, the markets for oil and natural gas have been volatile, and our management believes these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control.

We enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to oil price volatility.  All derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end

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of each period. All realized and unrealized gains and losses are recorded to gain (loss) on derivatives on the statements of operations.

As of April 30, 2013, we had entered into derivative agreements covering 1,283,000 barrels for fiscal year 2014 and 250,500 barrels for fiscal year 2015.

See Note 9 — Commodity Derivative Instruments to the accompanying Condensed Consolidated Financial Statements included in this Quarterly Report on Form 10-Q for additional details of our derivative financial instruments. See Item 3 — Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk, for a presentation of our oil derivative contracts as of April 30, 2013.

The Company recorded an unrealized gain of $1.2 million in the derivative activities line on the condensed consolidated statements of operations and comprehensive income (loss).

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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

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

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

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

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

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The Company’s commodity derivative contracts as of April 30, 2013 are summarized below:

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

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

We determine the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third-parties, the credit rating of each counterparty, and the Company’s own credit rating.  The Company also performs an internal valuation to ensure the reasonableness of third-party quotes.  In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments.  Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

Changes in commodity futures price strips during the quarterly period ended April 30, 2013 had an overall net positive impact on the fair value of our derivative contracts.  For the fiscal quarter ended April 30, 2013, we reported unrealized non-cash mark-to-market income on derivative contracts of $1.2 million.  The fair value of our derivative instruments at April 30, 2013 was a net asset of $1.5 million.  This mark-to-market net asset relates to derivative instruments with various terms that are scheduled to be realized over the period from May 2013 through December 2016.  Over this period, actual realized derivative settlements may differ significantly, either positively or negatively, from the unrealized mark-to-market valuation at April 30, 2013.  An assumed increase of 10% in the forward commodity prices used in the year-end valuation of our derivative instruments would result in a net derivative liability of approximately $2.3 million at April 30, 2013.  Conversely, an assumed decrease of 10% in forward commodity prices would result in a net derivative asset of approximately $6.0 million at April 30, 2013.

Interest Rate Risk

At April 30, 2013, TUSA had $124.6 million outstanding under the convertible note with NGP, all of which has a fixed interest rate of 5%.

As of April 30, 2013, TUSA had $110 million available for borrowing under its credit facility, $61 million of which was drawn as of such date.  The credit facility bears interest at variable rates.  Assuming we had the maximum amount outstanding at April 30, 2013 under our credit facility of $110 million, a 1.0% interest rate increase would result in

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additional annualized interest expense of approximately $1.1 million.  For a detailed discussion of the foregoing credit arrangements, including a discussion of the applicable interest rates, please refer to Note 12 — Long-Term Debt in our audited financial statements included in our Fiscal 2013 Form 10-K.

RockPile Interest Rate Risk

As of April 30, 2013, RockPile had $20 million available for borrowing under its credit facility with $10.5 million drawn as of such date.  The credit facility bears interest at variable rates.  Assuming they had the maximum amount outstanding at April 30, 2013 under the credit facility of $20 million, a 1.0% interest rate increase would result in additional annualized interest expense of approximately $0.2 million.  For a detailed discussion of the foregoing credit arrangements, including a discussion of the applicable interest rates, please refer to Note 12 — Long-Term Debt in our audited financial statements included in our Fiscal 2013 Form 10-K.

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ITEM 4. CONTROLS AND PROCEDURES

Material Weakness in Internal Control over Financial Reporting

As previously discussed in Item 9A “Controls and Procedures” of our Fiscal 2013 Form 10-K, we reported a material weakness, related to previously recognized pressure pumping income that was not properly eliminated.

Evaluation of Disclosure Controls and Procedures

We have performed an evaluation under the supervision, and with the participation of our management, including our Chief Executive Officer, Chief Financial Officer and Principal Accounting Officer of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms.  All internal control systems, no matter how well designed, have inherent limitations.  Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to financial statement preparation and presentation.  Based on (i) the ineffectiveness of the design of controls solely related to previously recognized pressure pumping income that was not properly eliminated and (ii) the need to evaluate if the additional review procedures over service income have been operating effectively for an adequate period of time, our Chief Executive Officer, Chief Financial Officer and Principal Accounting Officer concluded that the Company’s disclosure controls and procedures were not effective as of April 30, 2013.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting, other than as described below, (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended April 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

During the three months ended April 30, 2013, we took steps to remediate the material internal control weakness related to previously recognized pressure pumping income that was not properly eliminated.

·We updated our accounting policies for pressure pumping income and similar income from services performed in connection with properties in which Triangle or an affiliate holds an economic interest.

·We designed and utilized new schedules and procedures for the proper accounting for pressure pumping income.

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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.  However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business.  We are currently not aware of any such legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse effect on our business, financial condition or results of operations.

Item 1A.  Risk Factors.

There have been no material changes to the risk factors set forth in our Fiscal 2013 Form 10-K. Those risk factors, in addition to the other information set forth in this Quarterly Report on Form 10-Q, 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 table below provides a summary of shares of our common stock surrendered to us in payment of tax liability in connection with the vesting of restricted stock units during the three months ended April 30, 2013.

	Total Number of Shares Purchased	Average Price Paid Per Share
	(1)	(2)
February 1, 2013 - February 28, 2013	43,569	$	6.52
March 1, 2013 - March 31, 2013	102,177	6.56
April 1, 2013 - April 30, 2013	11,769	5.32
	157,515	$	6.46

(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, as permitted by the Company’s 2011 Omnibus Incentive Plan. 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.

(2) No commission was paid in connection with the surrender of common stock.

Item 3.  Defaults Upon Senior Securities.

None.

Item 4.  Mine Safety Disclosures.

Not Applicable.

Item 5.  Other Information.

None.

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Item 6. Exhibits.

2.1	Agreement and Plan of Merger, dated November 29, 2012, filed as Exhibit 2.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2012 and incorporated herein by reference.
3.1	Certificate of Incorporation of Triangle Petroleum Corporation, filed as Exhibit 3.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2012 and incorporated herein by reference.
3.2	Bylaws of Triangle Petroleum Corporation, filed as Exhibit 3.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on December 3, 2012 and incorporated herein by reference.
4.1	Investment Agreement, dated July 31, 2012, among Triangle Petroleum Corporation, NGP Triangle Holdings, LLC and NGP Natural Resources X, L.P., filed as Exhibit 4.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 1, 2012 and incorporated herein by reference.
4.2	First Amendment to Investment Agreement, dated March 8, 2013, between Triangle Petroleum Corporation, NGP Triangle Holdings, LLC, NGP Natural Resources X, L.P., and NGP Natural Resources X Parallel Fund, L.P., filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 13, 2013 and incorporated herein by reference.
4.3	Amended and Restated Registration Rights Agreement, dated March 8, 2013, between Triangle Petroleum Corporation, NGP Triangle Holdings, LLC, NGP Natural Resources X, L.P., and NGP Natural Resources X Parallel Fund, L.P., filed as Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 13, 2013 and incorporated herein by reference.
10.1	Credit and Security Agreement, dated February 25, 2013, between RockPile Energy Services, LLC and Wells Fargo Bank, National Association, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 1, 2013 and incorporated herein by reference.
10.2	Stock Purchase Agreement, dated March 2, 2013, between Triangle Petroleum Corporation and NGP Triangle Holdings, LLC, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 4, 2013 and incorporated herein by reference.
10.3	Amended and Restated Credit Agreement, dated April 11, 2013, among Triangle USA Petroleum Corporation, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and Issuing Lender, and the Lenders Named Herein, as Lenders, filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 17, 2013 and incorporated herein by reference.
10.4	Employment Agreement, dated May 1, 2013, by and between Triangle Petroleum Corporation and Justin Bliffen, filed as Exhibit 10.7 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on May 1, 2013 and incorporated herein by reference.
31.1	Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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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

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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:  June 7, 2013	By:	/s/ JONATHAN SAMUELS
	Jonathan Samuels
	President and Chief Executive Officer (Principal Executive Officer)
Date:  June 7, 2013	By:	/s/ JUSTIN BLIFFEN
	Justin Bliffen
	Chief Financial Officer (Principal Financial Officer)
Date:  June 7, 2013	By:	/s/ JOSEPH FEITEN
	Joseph Feiten
	Principal Accounting Officer

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