Exhibit 99.3

CORPORATE PRESENTATION May 2014

FORWARD LOOKING STATEMENTS The information presented in this presentation may contain "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These forward-looking statements are not guarantees of future performance and are subject to risks and uncertainties that could cause actual results to differ materially from the results contemplated by the forward-looking statements. Factors that could cause actual results to differ materially from the results contemplated by the forward-looking statements include, but are not limited to, the risks discussed in the Company's annual report on Form 10-K for the fiscal year ended January 31, 2014 and its other filings with the Securities and Exchange Commission. The forward-looking statements in this presentation are made as of the date of this presentation, and the Company undertakes no obligation to update any forward-looking statement as a result of new information, future developments, or otherwise.

TABLE OF CONTENTS Business Overview Financial Overview Appendix 4 14 19 Operational Overview 8

BUSINESS OVERVIEW

Gathering, transportation, treating and processing services JV with First Reserve Energy Infrastructure Fund Benefits include reducing costs and improving efficiency All segments of the system expected to be in service by Q2 FY’15 (ended July ‘14) TPC wholly owned energy services subsidiary TPC wholly owned E&P subsidiary BUSINESS OVERVIEW TRIANGLE PETROLEUM CORPORATION OVERVIEW 5 Hydraulic pressure pumping and well completion services Provides greater control over Triangle’s largest cost center ~56% of completion jobs since inception through Q4 FY’14 performed for third parties Growth oriented E&P company focused on the Williston Basin ~135,000 net acres with current production rate of ~9,575 Boepd and proved reserves of 46.5 MMBoe(1) ~92,000 net acres predominantly in core areas of McKenzie / Williams Counties (57% operated) Drilling program consists of running 4 full-time operated rigs(2) Note: TUSA information pro forma for acquisitions announced on May 14, 2014. Triangle Petroleum Corporation’s Fiscal Year 2015 (“FY2015”) ends January 31, 2015. (1) Internal reserve estimate as of April 30, 2014, pro forma for the acquisitions. (2) Transitioned from 3 full-time operated rigs to 4 full-time operated rigs during Q1 FY’15. (3) Triangle’s pro forma ownership of L.P. to increase to 32% from 30% on Phase II in-service date. TPC owns 50% of G.P. and 30% of L.P.(3)

KEY INVESTMENT HIGHLIGHTS 6 (1) Pro forma for the acquisitions announced on May 14, 2014. Internal reserve estimate, as of April 30, 2014. (2) United States Geological Survey (USGS) published on April 30, 2013. (3) Since current management turn-around beginning in 2010 through January 31, 2014. Cash deployed is net of $3.15mm cash distribution from CLBR to Triangle. (4) Pro forma for TUSA borrowing base increase to $405mm from $320mm and RPES borrowing base increase announced on March 31, 2014 to $100mm from $27.5mm. Liquidity as of April 30, 2014, pro forma for the acquisitions. (5) As of May 14, 2014. ~135,000 net acres; 46.5 MMBoe proved reserves (80% oil; 56% proved developed)(1) Focused on increasing scale through selective bolt-on acquisitions and trades in core area Contiguous acreage position above the Bakken and Three Forks Formations, which are estimated to contain ~7.4 billion barrels of recoverable oil(2) OIL-FOCUSED WILLISTON BASIN OPERATOR Reduces reliance on third-party service providers; relieves infrastructure constraints Recovers value-leakage to critical supply chain services Increasing the number of wells on each location to achieve maximum reservoir recovery Triangle has deployed ~$66mm of cash to its non-E&P subsidiaries, representing only 8% of total capital invested(3) INTEGRATED AND EFFICIENT DEVELOPMENT MODEL $505mm in total lending facilities with ~$265mm in total liquidity(4) Conservative financial approach with focus on protecting cash flow through hedging .~5,200 Bopd hedged for FY2015 and ~1,700 Bopd for FY2016(5) Top-tier private equity partners (NGP, First Reserve and TIAA Oil & Gas Investments) STRONG FINANCIAL POSITION Disciplined management approach supported by a team with a proven blend of technical, operational, commercial, financial, land, and regulatory experience Key members of the technical and operations team each have 10 to 35 years of oil and gas experience DISCIPLINED MANAGERS AND EXPERIENCED OPERATORS FY2014 production and reserves increased 295% and 175%, respectively, year over year .FY2014 SEC PV-10 increased 201% year over year Company continues to increase operated production while reducing costs SUBSTANTIAL GROWTH IN OPERATED PRODUCTION AND RESERVES BUSINESS OVERVIEW

OPERATED VS. NON-OPERATED VOLUMES 7,044 8,278 14,637 16,050 22,080 32,529 40,314 46,550 0 10,000 20,000 30,000 40,000 50,000 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 Q1 FY'15 (MBoe) 11,600 696 1,138 1,389 2,098 2,714 4,287 6,804 7,254 12,600 0 2 4 6 8 10 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 Q1 FY'13 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 2nd Half FY'15 Operated Rig Count Net Sales Volumes (Boepd) SIGNIFICANT OPERATED PRODUCTION AND RESERVES GROWTH 7 NET SOLD PRODUCTION VOLUMES (BOEPD) (1) Revised FY2015 and 2nd Half FY’15 production guidance issued on May 14, 2014. Previous guidance (FY2015 daily production guidance 9,500 – 10,500 Boepd; 2nd Half FY’15 production guidance 10,500 – 11,500 Boepd) issued on January 21, 2014. (2) Pro forma for the acquisitions announced on May 14, 2014. Internal reserve estimate, as of April 30, 2014. Actual Production Completed first operated well in May 2012 RockPile completed first well August 2012 Caliber generates first revenues BUSINESS OVERVIEW FY2015 Avg. Daily Production Guidance(1) 10,200 – 11,200 Boepd (FY2014 Production of 5,286 Boepd) PROVED RESERVES (MBOE) (42% PDP) (46% PDP) (45% PDP) (48% PDP) (41% PDP) (45% PDP) (38% PDP) (56% PDP) (1) Guidance Low Case Guidance High Case Avg. Rig Count 36% 55% 69% 70% 65% 78% 80% 100% 64% 45% 31% 30% 35% 22% 20% 0% 20% 40% 60% 80% 100% Q1 FY'13 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 % of Total Sold Volumes PDP Reserves PUD Reserves Non-Operated Volumes Operated Volumes (2)

OPERATIONAL OVERVIEW

TRIANGLE USA CORE AREA – MCKENZIE AND WILLIAMS COUNTIES 9 Note: TUSA information pro forma for acquisitions announced on May 14, 2014. (1) As of May 14, 2014, pro forma for the acquisitions. (2) Triangle’s operatorship in North Dakota has been confirmed through title. In eastern Montana, operated assumes 30% or greater working interest. (3) Gross Operated Locations Remaining assumes six Bakken and four Three Forks wells per DSU. Supported by recent density tests near Triangle’s core acreage. Figures exclude currently producing operated wells. RECENT DEVELOPMENTS 79 gross operated wells currently producing and 11 wells waiting on completion(1) Over 80% of operated producing wells currently hooked up to gas sales, as compared to 0% at the end of Q1 FY’14(1) Recent downspacing tests indicate potential for 8 – 12+ locations per DSU .Multiple operated DSUs containing middle Bakken wells spaced ~600’ apart .Nearby operators undergoing 12 and 16 well density tests in a single DSU targeting the Middle Bakken and Lower Three Forks benches OPERATIONAL OVERVIEW PRO FORMA ASSET MAP: DENSITY / THREE FORKS ACTIVITY DETAILS TPLM CORE Net Acreage ~92,000 Percent Operated (%) (2) 57% Percent Held By Production (%) 73% OPERATED DSUS(2) 69 TOTAL OPERATED LOCATIONS REMAINING(3) 611 TPLM Acreage TPLM Operated DSU Bakken & Three Forks Density Test Select Lower Three Forks Wells Select Tests 1) KOG 2) OAS 3) CLR 4) CLR 5) OAS 6) OAS 7) WLL 8) KOG 1 3 7 2 4 5 8 6 OPERATIONAL OVERVIEW ACQUISITIONS OVERVIEW 10 KEY ACQUISITION HIGHLIGHTS PRO FORMA ASSET MAP (HIGHLIGHTING ACQUISITION) (1) Net Proved Reserves are based on internal estimates as of April 30, 2014. (2) Gross Operated Locations Remaining assumes six Bakken and four Three Forks wells per DSU. Supported by recent density tests near Triangle’s core acreage. Figures exclude currently producing operated wells. Signed two separate definitive agreements (“Acquisitions”) for total consideration of ~$120mm in cash, net of estimated purchase price adjustments and sale of acquired salt water disposal well to Caliber .~46,100 net acres in a contiguous area of Williams County, North Dakota and Sheridan County, Montana .~1,175 Boepd of current production .~4,450 MBoe of net proved reserves(1) .252 gross operated locations remaining(2) Triangle, pro forma for the Acquisitions: .~91,767 net acres in the core Williston Basin .~9,575 Boepd of net production .~46,500 MBoe of net proved reserves(1) .611 gross operated locations remaining(2) Acquisitions incrementally increase current drilling inventory by an estimated 5 to 8 years NetPercentOperatedGross OperatedEst. CurrentNet Remaining(2) Production (Boepd) Reserves Triangle Core 45,667 69% 4235 98,400 42,050 Acquisitions 46,100 46% 27 252 1,175 4,450 Pro Forma 91,767 57% 69 611 9,575 46,500 Increase over Standalone 101% 70% 14% Acquisitions Operated DSUs Acquisitions Acreage TPLM Acreage TPLM Operated DSUs 28 29 27 23 23 23 0 5 10 15 20 25 30 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 Days DRILLING AND PRODUCTION PROFILE 11 (1) FY2014 net operated completions restated based on working interest as of 1/31/2014. (2) Spud to total depth drilled days excludes days when rig is batch drilling adjacent well. (3) Includes $1.1 mm average RockPile and other eliminations and effects of Triangle-RockPile master service agreement renegotiation. (4) Excludes produced volumes of natural gas and NGL’s not being sold. TUSA OPERATED WELLS COMPLETED (GROSS VS. NET)(1) AVERAGE SPUD TO TOTAL DEPTH DRILLED DAYS(2) OPERATIONAL OVERVIEW FY2014 SOLD VOLUMES PRODUCTION MIX(4) 91% 5% 4% Crude Oil Natural Gas NGLs Decreasing spud to total depth days; average of 23 days for Q4 FY’14 versus 29 days for Q4 FY’13 Targeting $9.0 - $9.5mm AFE costs(3) .Efficiencies related to pad drilling .Caliber reduces pad equipment on site .Reducing time drilling rig spends on location HIGHLIGHTS 5.0 5.0 6.0 5.0 8.0 9.0 9.0 2.5 2.7 4.7 4.3 6.2 6.4 6.7 0 2 4 6 8 10 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 Wells Completed Gross Operated Completions Net Operated Completions

OPERATIONAL OVERVIEW PRO FORMA ASSET MAP: DENSITY / THREE FORKS ACTIVITY DETAILS TPLM CORE Net Acreage ~92,000 Percent Operated (%) (2) 57% Percent Held By Production (%) 73% OPERATED DSUS(2) 69 TOTAL OPERATED LOCATIONS REMAINING(3) 611 TPLM Acreage TPLM Operated DSU Bakken & Three Forks Density Test Select Lower Three Forks Wells Select Tests 1) KOG 2) OAS 3) CLR 4) CLR 5) OAS 6) OAS 7) WLL 8) KOG 1 3 7 2 4 5 8 6 OPERATIONAL OVERVIEW ACQUISITIONS OVERVIEW 10 KEY ACQUISITION HIGHLIGHTS PRO FORMA ASSET MAP (HIGHLIGHTING ACQUISITION) (1) Net Proved Reserves are based on internal estimates as of April 30, 2014. (2) Gross Operated Locations Remaining assumes six Bakken and four Three Forks wells per DSU. Supported by recent density tests near Triangle’s core acreage. Figures exclude currently producing operated wells. Signed two separate definitive agreements (“Acquisitions”) for total consideration of ~$120mm in cash, net of estimated purchase price adjustments and sale of acquired salt water disposal well to Caliber .~46,100 net acres in a contiguous area of Williams County, North Dakota and Sheridan County, Montana .~1,175 Boepd of current production .~4,450 MBoe of net proved reserves(1) .252 gross operated locations remaining(2) Triangle, pro forma for the Acquisitions: .~91,767 net acres in the core Williston Basin .~9,575 Boepd of net production .~46,500 MBoe of net proved reserves(1) .611 gross operated locations remaining(2) Acquisitions incrementally increase current drilling inventory by an estimated 5 to 8 years NetPercentOperatedGross OperatedEst. CurrentNet Remaining(2) Production (Boepd) Reserves Triangle Core 45,667 69% 4235 98,400 42,050 Acquisitions 46,100 46% 27 252 1,175 4,450 Pro Forma 91,767 57% 69 611 9,575 46,500 Increase over Standalone 101% 70% 14% Acquisitions Operated DSUs Acquisitions Acreage TPLM Acreage TPLM Operated DSUs 28 29 27 23 23 23 0 5 10 15 20 25 30 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 Days DRILLING AND PRODUCTION PROFILE 11 (1) FY2014 net operated completions restated based on working interest as of 1/31/2014. (2) Spud to total depth drilled days excludes days when rig is batch drilling adjacent well. (3) Includes $1.1 mm average RockPile and other eliminations and effects of Triangle-RockPile master service agreement renegotiation. (4) Excludes produced volumes of natural gas and NGL’s not being sold. TUSA OPERATED WELLS COMPLETED (GROSS VS. NET)(1) AVERAGE SPUD TO TOTAL DEPTH DRILLED DAYS(2) OPERATIONAL OVERVIEW FY2014 SOLD VOLUMES PRODUCTION MIX(4) 91% 5% 4% Crude Oil Natural Gas NGLs Decreasing spud to total depth days; average of 23 days for Q4 FY’14 versus 29 days for Q4 FY’13 Targeting $9.0 - $9.5mm AFE costs(3) .Efficiencies related to pad drilling .Caliber reduces pad equipment on site .Reducing time drilling rig spends on location HIGHLIGHTS 5.0 5.0 6.0 5.0 8.0 9.0 9.0 2.5 2.7 4.7 4.3 6.2 6.4 6.7 0 2 4 6 8 10 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 Wells Completed Gross Operated Completions Net Operated Completions

DRILLING AND PRODUCTION PROFILE 11 (1) FY2014 net operated completions restated based on working interest as of 1/31/2014. (2) Spud to total depth drilled days excludes days when rig is batch drilling adjacent well. (3) Includes $1.1 mm average RockPile and other eliminations and effects of Triangle-RockPile master service agreement renegotiation. (4) Excludes produced volumes of natural gas and NGL’s not being sold. TUSA OPERATED WELLS COMPLETED (GROSS VS. NET)(1) AVERAGE SPUD TO TOTAL DEPTH DRILLED DAYS(2) OPERATIONAL OVERVIEW FY2014 SOLD VOLUMES PRODUCTION MIX(4) 91% 5% 4% Crude Oil Natural Gas NGLs Decreasing spud to total depth days; average of 23 days for Q4 FY’14 versus 29 days for Q4 FY’13 Targeting $9.0 - $9.5mm AFE costs(3) .Efficiencies related to pad drilling .Caliber reduces pad equipment on site .Reducing time drilling rig spends on location HIGHLIGHTS 5.0 5.0 6.0 5.0 8.0 9.0 9.0 2.5 2.7 4.7 4.3 6.2 6.4 6.7 0 2 4 6 8 10 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 Wells Completed Gross Operated Completions Net Operated Completions

(1) Reference “Segment Reporting” tables in company financial statements and presentation appendix. OPERATIONAL OVERVIEW 12 ROCKPILE ENERGY SERVICES Third pressure pumping spread has been delivered ahead of schedule and is currently operating for a third-party .Spread booked through June, 2014 as a result of current customer demand Increased third party well completions to 50 in FY2014 from five in FY2013 Backlog of approximately 15 wells, including eight for third party operators, at the end of Q4 FY’14 To date, completed jobs for seven third party operators Estimate cash dividends issued to Triangle totaling $25 - $30mm in FY2015 .Made a $10mm cash distribution to Triangle in April, 2014 EXPANDING CAPACITY AND CAPABILITIES GROSS WELLS COMPLETED 9 RockPile Energy Services, LLC is focused on providing “Best in Class” pressure pumping and ancillary services in the Williston Basin CONSOLIDATED ELIMINATION SINCE INCEPTION Net Income Eliminated Since Inception through Q4 FY’14 ($mm)(1) RPES-Triangle Completed Wells through Q4 FY’14 Avg. Well Cost Reduced per Triangle Well ($mm) $48.0 43 $1.1 1 5 6 5 8 9 9 1 4 5 10 19 16 6 10 10 18 28 25 0 10,000 20,000 30,000 40,000 0 10 20 30 40 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 Horsepower Wells Completed Triangle Wells Third Party Wells Horsepower

Triangle has a 30% ownership stake(2), but can earn up to 50% subject to the performance of the business(3) CONSTRUCTION UPDATE (AS OF MARCH, 2014) OPERATIONAL OVERVIEW 13 CALIBER MIDSTREAM Source: Triangle Petroleum Corporation and North Dakota Industrial Commission, 2013 (1) Transportation of residue to Northern Border. (2) Triangle pro forma ownership of L.P. to increase to 32% from 30% on Phase II in-service date. (3) Assumes all Series A warrants exercised into Class A units. CAPITAL STRUCTURE Caliber Midstream Partners, LP is focused on providing gathering, transportation and processing in the Williston Basin Alexander Market Center (Enbridge) Caliber Central Facility Lewis SWD ONEOK (NGL) Caliber System Northern Border (Dry Gas) WAWSA Enbridge (Crude) Triangle Phase I DSU’s Triangle Phase II DSU’s SERVICE LINE PIPE LAID (MILES) % COMPLETE Crude Gathering & Transportation 32 50% Natural Gas Gathering 30 100% Natural Gas Transportation(1) 3 100% Produced Water Transportation 32 53% Freshwater & Maintenance Water Delivery 36 61% Natural Gas Liquids Transportation 5 100% All business lines are currently operational, marking the end of the Phase I build out .Natural gas facility began first sales in April, 2014 Completion of Phase II by the end of Q2 FY’15 will enable crude oil to flow through to the Alexander Market Center, which will provide additional marketing optionality due to offtake via multiple pipelines and/or rail Estimate cash dividends issued to Triangle totaling $10 - $15mm in FY2015; paid $3.15mm cash distribution net to Triangle in December 2013

FINANCIAL OVERVIEW

CURRENT POSITION CURRENT POSITION LIQUIDITY PROFILE ($MM) TOTAL CURRENT AND POTENTIAL DILUTED OWNERSHIP(3) KEY HIGHLIGHTS Continue to maintain conservative leverage metrics with total debt to annualized second half FY2014 adjusted EBITDA of 1.5x(1) TUSA borrowing base recently increased to $405mm from $320mm(3) RPES borrowing base recently increased to $100mm from $27.5mm(3) Active hedging program in place, with a focus on hedging volumes in CY2015; near current max hedge volume capacity in CY2014 Total Cash (as of January 31, 2014)$82TUSA Credit Facility Availability (as of January 31, 2014)$137RPES Credit Facility Availability (as of January 31, 2014) $6 Total Liquidity$225Pro Forma Total Liquidity (as of April 30, 2014)(2)$265 E&P Operated Drilling Program ~56% E&P Non- Operated Drilling Program ~7% E&P Land Spend ~23% Station Prospect ~2% RockPile ~9% Infrastructure and Other ~4%

FINANCIAL OVERVIEW 16 REVISED STAND-ALONE CAPITAL BUDGET FOR FY2015 (ENDED JANUARY 31, 2015) Note: TUSA information pro forma for acquisitions announced on May 14, 2014. (1) Revised FY2015 capital budget issued on May 14, 2014. Previous budget of $510mm issued on January 21, 2014. (2) E&P Operated Drilling Program does not include the RockPile and other eliminations that reduce capital expenditures at the Triangle Parent Company level. Actual E&P operated incurred capex will be lower by eliminations. FY2014 eliminations of $35.2mm. (3) Capital to be allocated towards the acquisition of seismic data and to drill and complete 3 – 4 exploratory wells. BUDGET DETAIL Capital Expenses Revised FY2015 Budget ($mm)(1) E&P Operated Drilling Program(2) $360 E&P Non-Operated Drilling Program 45 Station Prospect(3) 10 E&P Land Spend 145 RockPile 55 Infrastructure and Other 25 Total $640 FY2015 BUDGET HIGHLIGHTS Drilling program consists of 3 full-time operated rigs increasing to 4 rigs in Q1 FY’15 Spud 46 to 50 gross operated wells Complete 42 to 46 gross operated wells Third RockPile pressure pumping spread delivered ahead of schedule in Q1 FY’15 RockPile budget includes the order of a fourth pressure pumping spread in late FY2015 with delivery in early FY2016

FINANCIAL OVERVIEW STAND-ALONE BUSINESS SEGMENT GUIDANCE 17 *Footnotes (1) and (2) describing segment information and non-GAAP measures are located at the back of the Appendix (1) Assumes TUSA transitions to a 4 rig operated program during Q1 FY’15 (ended April 30, 2014). (2) Revised FY2015 and 2nd Half FY’15 TUSA guidance issued on May 14, 2014. Previous guidance issued on January 21, 2014. (3) Assumes 30 stages per well. Assumes third spread fully operational in Q3 FY’15 (ended October 31, 2014). (4) FY2015 guidance net to Triangle’s 32% future ownership stake in Caliber. (5) Total estimated elimination calculated using FY2015 midpoint of TUSA gross well completions, 44, multiplied by average elimination per well to date of $1.1mm. TUSA Stand-alone(1)(2) RPES Stand-alone(3) CLBR Stand-alone(4) Period Revenue ($mm) Adj. EBITDA ($mm) Revenue ($mm) Adj. EBITDA ($mm) Revenue Adj. EBITDA ($mm) 2H FY’15 $165 - $180 $115 - $125 $170 - $200 $39 - $47 $10 - $12 $7 - $8 2H FY’15 Ann. $330 - $360 $230 - $250 $340 - $400 $78 - $94 $20 - $24 $14 - $16 FY2015 $290 - $325 $205 - $225 $300 - $340 $63 - $75 $17 - $21 $13 - $15 FY2014 Actual $161 $112 $194 $42 $5 $3 FY2015 CONSOLIDATED FINANCIALS The following items must also be considered for the consolidated financials: ITEM DESCRIPTION ($MM) Consolidated Triangle Parent Company (“TPC”) G&A Incremental corporate level G&A expense $11 - 14 Consolidated TPC Stock-Based Compensation Incremental corporate level SBC expense $8 - 11 Consolidated Book Taxes Book tax expense (cash tax expense of ~$0) $30 - 35 Intercompany Eliminations Estimated based upon historical eliminations(5) $40 - 50 Caliber EBITDA No consolidated contribution of Caliber due to intracompany eliminations -

3,716 4,021 4,952 4,440 2,660 1,500 1,500 995 2,880 1,593 332 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 Q1 FY'15 Q2 FY'15 Q3 FY'15 Q4 FY'15 Q1 FY'16 Q2 FY'16 Q3 FY'16 Q4 FY'16 Costless Collar Volume Swap Volume Q4 FY'14 Production RISK MANAGEMENT 18 Actively hedging to protect present and future cash flows through the use of zero cost collars and swaps .Ability to hedge up to 85% of expected production over next 18 – 24 months FINANCIAL OVERVIEW HEDGE POSITION CURRENT HEDGES (BOPD) KEY HIGHLIGHTS *Note: As of May 14, 2014. Q4 FY’14 Production: 7,254 Boepd ~4,600 ~1,700 ~600 - 1,500 3,000 4,500 6,000 FY2015 FY2016 Bopd Costless Collar Volume Swap Volume FY’15 Swaps ~$95 Fixed FY’15 Collars ~$100 Ceiling ~$86 Floor FY’16 Collars ~$96 Ceiling ~$82 Floor

APPENDIX a) RockPile: Vertical Integration Profile b) Caliber: Vertical Integration Profile c) Montana – Station Prospect d) Historical Financials

$27 $44 $66 $56 $6 $12 $14 $10 $4 $10 $10 $6 $0 $10 $20 $30 $40 $50 $60 $70 Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 ($mm) Control 100% of largest E&P cost center Maintain greater control over completion schedules, quality and pay cycles Third-party completions boost consolidated revenues and earnings; goal to achieve $100mm in stand-alone EBITDA and 75% third-party business Potential distributions from subsidiary back to TPC to be reinvested in highest return investments FY2014 STAND-ALONE FINANCIALS(1)(2)(3) ROCKPILE’S BENEFIT TO TRIANGLE ROCKPILE: VERTICAL INTEGRATION PROFILE 20 APPENDIX ROCKPILE ELIMINATIONS PER WELL FY2014 (1) Does not match consolidated financials. Reference “Segment Reporting and Non-GAAP Measures” tables in company financial statements and presentation appendix. (2) Since inception, RockPile has not made a meaningful contribution to net income on a consolidated basis. (3) RockPile FY2014 Adjusted-EBITDA restated to be calculated as per methodology from recently upsized credit facility, which closed on March 25, 2014. (4) Peer Group: BAS, CDI-T, CFW-T, CJES, ESI-T, FES, HP, KEG, NBR, NR, PDS, PES, PTEN, RES, SPN, SVY-T, TDG-T, WRG-V, XDC-T. (5) As of May 14, 2014. Source: Bloomberg. Net Income Revenue Adj. EBITDA $5.2 $9.9 $11.2 $5.5 $1.0 $1.2 $1.2 $0.6 $0.5 $1.0 $1.5 $2.0 $0.0 $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 Elimination / Well ($mm) ($mm) Net Income Elimination Capex Reduction / Well ROCKPILE IMPLIED VALUATION Peer Average 2015E EV / EBITDA(4)(5) 6.6x RPES 2H FY’15 Ann. EBITDA Midpoint(1) $86mm RPES Valuation $572mm Basic Shares Outstanding (mm) 85.9 Valuation Per TPC Share $6.66

Secured long term gas and crude oil gathering and takeaway capacity at market rates in the Williston Basin Potential to i) capture value for gas previously flared, ii) increase realized prices by increasing optionality and iii) improve differential Potential distributions from subsidiary back to TPC to be reinvested in highest return investments CALIBER: VERTICAL INTEGRATION PROFILE 21 APPENDIX CALIBER’S BENEFIT TO TRIANGLE (1) See “Use of Segment Information and Non-GAAP Measures” in the Appendix. (2) Peer Group: ACMP, AMID, APL, BKEP, CMLP, DPM, HEP, MMLP, MWE, NGLS, RGP, RRMS, SMLP, SXE, TCP, TLLP, TLP, WES, XTEX. (3) Data as of May 14, 2014. Source: Bloomberg. (4) Please reference Note 10 – Fair Value Measurements and Note 11 – Equity Investment in our FY2014 Form 10-K for additional details. CALIBER IMPLIED VALUATION Peer Average 2014E EV / EBITDA(1)(2)(3) 14.1x CLBR 2H FY’15 Ann. EBITDA Midpoint(1) $15mm CLBR Valuation $212mm Basic Shares Outstanding (mm) 85.9 Valuation Per TPC Share $2.47 IMPACT ON CONSOLIDATED FINANCIALS In FY2015, anticipate no gain from equity investment due to elimination, and no debt consolidation due to equity method accounting Fair value ownership of trigger units, trigger unit warrants, and warrants reevaluated quarterly(4)

APPENDIX MONTANA – STATION PROSPECT 22 Source: Triangle Petroleum Corporation and Montana Board of Oil and Gas, 2014. DETAILS ~43,000 net acres; 67% operated Potential Drilling Inventory: 318 operated locations Allocating $10mm to acquire seismic data and drill and complete 3 – 4 exploratory wells in FY2015 KEY HIGHLIGHTS Industry activity continues in offsetting townships Ongoing exploration programs for Bakken and Three Forks New exploration program for conventional Red River initiated by peer operator Long-term leasehold allows a “wait-and- see” approach Asset provides substantial exploration upside for unconventional and conventional accumulations 16 TPLM Acreage TPLM Operated DSU Select Wells County

Q4 FY’14 CONSOLIDATED INCOME STATEMENT 23 APPENDIX (1) Includes intercompany eliminations; reference Note 4 – Segment Reporting in the FY2014 Form 10-K for additional details. (2) Includes interest expense add-back of $3.4mm and $0.9mm in FY2014 and Q4 FY’14, respectively, related to outstanding convertible notes. (3) See “Use of Segment Information and Non-GAAP Measures” and “Adjusted Net Income Reconciliation” in the Appendix. Three Months Ended January 31,Year EndedJanuary 31,2014201320142013RevenuesTotal revenues$8 5,510$2 3,901$2 58,747$6 0,701Costs and ExpensesOil and gas operating expenses (incl. production taxes)1 3,2003 ,6073 6,7628 ,208Oilfield services(1)2 9,2855 ,8648 2,3271 6,606Depreciation and amortization2 0,0485 ,7575 7,0481 5,081Accretion of asset retirement obligations1811 1 ,018 184 Corporate and Other stock-based compensation1 ,9799576 ,1133 ,342E&P stock-based compensation2305871 ,1272 ,507RockPile stock-based compensation132617590617Corporate and Other cash G&A expenses2 ,7041 ,0028 ,2034 ,358E&P cash G&A expenses2 ,3992 ,8837 ,7776 ,838RockPile cash G&A expenses3 ,5415 ,5711 1,1161 1,130Total operating expenses7 3,5362 6,8562 12,0816 8,871Operating Income (Loss)1 1,974(2,955)4 6,666(8,170)Gain on equity investment derivative3 ,953-3 9,785-Gain (loss) from derivative activities2 ,146(4,971)1 ,082(3,570)Interest expense(2,252)(1,346)(7,686)(2,818)Loss from equity investment-(283)-(283)Interest income6711200134Other income (expense)3322641 ,374223Total other income (expense)4 ,246(6,325)3 4,755(6,314)Net Income (Loss) Before Income Taxes1 6,220(9,280)8 1,421(14,484)Income tax provision$(1,972) 1 4,248-$(7,941) 7 3,480-Net Income (Loss)$(9,280)$(14,484)Noncontrolling interest's net loss share-$98 (9,182)-$724Net Income (Loss) Attributable to Common Stockholders $1 4,248$7 3,480(13,760)Net Income (Loss) per CommonBasic$0 .17$(0.20)$1 .07$(0.31)Diluted(2)$0 .15$(0.20)$0 .91$(0.31)Adjusted Net Income (Loss) per Common(3)Basic$0 .12$(0.10)$0 .58$(0.23)Diluted(2)$0 .11$(0.10)$0 .51$(0.23)Weighted Average Common SharesBasic8 5,6774 5,2426 8,5794 4,475Diluted1 02,7574 5,2428 4,5584 4,475(1) Includes intercompany eliminations; reference Note 4 –Segment Reporting in the FY2014 Form 10-K foradditional details.

CONSOLIDATED ADJUSTED NET INCOME RECONCILIATION 24 APPENDIX (1) Includes interest expense add-back of $3.4mm and $0.9mm in FY2014 and Q4 FY’14, respectively, related to outstanding convertible notes. *Adjusted-EBITDA does not include TPC (parent company) cash G&A expense of $2.7mm in Q4 fiscal year 2014 and $8.2mm in fiscal year 2014 *TUSA results include all exploration and production related business lines (“E&P”) *RockPile FY2014 Adjusted-EBITDA restated to be calculated as per methodology from recently upsized credit facility, which closed on March 25, 2014 *See “Use of Segment Information and Non-GAAP Measures” in the back of the Appendix for disclosures *Caliber Adjusted-EBITDA represents Triangle’s 30% ownership share of the partnership, before intracompany elimination STAND-ALONE BUSINESS SEGMENT ADJUSTED EBITDA RECONCILIATION (1) Q4 fiscal 2014 $ 14,248Q4 fiscal 2013 $ (9,182)Fiscal 2014Fiscal 2013Net income (loss) attributable to common stockholders$ 73,480$ (13,760)(Gain) loss on equity investment derivative(3,953)-(39,785)-(Gain) loss on derivative activities(2,146)4 ,979(1,082)3 ,578(Gain) loss on investment in marketable securities-(204)(1,040)(204)Net deferred income tax liability (benefit)$1 ,972 1 0,121-7 ,941 $ 3 9,514-Adjusted net income (loss)$(4,407)$ (10,386)Adjusted net income (loss) per commo nBasic$0 .12$(0.10)$ 0 .58$ (0.23)Diluted'1'$0 .11$(0.10)$ 0 .51$ (0.23)Weighted average common sharesBasic8 5,6774 5,2426 8,5794 4,475Diluted1 02,7574 5,2428 4,5584 4,475SS SEGMENT ADJUSTED EBITDA RECONCILIATIONQ4 fiscal 2014 $ 17,456Fiscal 2014Net income (loss) before income taxes$62,924Depreciation and amortization17,50751,065Net interest expense1,0282,317Stock-based compensation2301,127Accretion of asset retirement obligations181,018Unrealized (gain) loss on derivative activities( 4,594)( 5,725)(Gain) on securities held for investment-$( 1,040) 111,686Adjusted-EBITDA$31,645Q4 fiscal 2014 $ 5,967Fiscal 2014Net income (loss) before income taxes$29,684Depreciation and amortization3,4318,905Stock-based compensation132590Net interest Expense380991One-time start-up costs and other577$1,775 41,945Adjusted-EBITDA$10,486Q4 fiscal 2014 $ 449Fiscal 2014Net income (loss) before income taxes$2,126Depreciation and amortization156460Warrant expense5858Net interest expense5454Adjusted-EBITDA$717$2,698

FY2014 INTERSEGMENT TABLE 25 APPENDIX (1) Corporate and Other includes the corporate office and several subsidiaries that management does not consider in the exploration and production or pressure pumping segments. These subsidiaries have limited activity. (2)$35.2mm RockPile, Caliber, and other services consolidated elimination results in a $35.2mm reduction in oil and natural gas property expenditures. *Reference Note 4 – Segment Reporting in our fiscal year 2014 Form 10-K for additional details $Exploration and Production1 60,548 ---$RockPile's Pressure Pumping and Other Services-1 02,6069 1,019-$Corporateand Other(1)---1 ,1921 ,192$Eliminations and Other-(4,407)(91,019) (1,192)(96,618)Consolidated TotalRevenuesOil and natural gas salesPressure pumping and related services for third partiesIntersegment revenuesOther$ 1 60,5489 8,199--Total revenues1 60,5481 93,6252 58,747Costs and ExpensesProd. taxes, LOE, and other expenses Depreciation and amortization Pressure pumping General and administrative3 7,7805 1,065-8 ,9049 7,749-8 ,9051 42,3391 1,7061 62,950-620-1 4,316 1 4,936-(3,542)(60,012)-3 7,780 5 7,048 8 2,327 3 4,926Total operating expenses(63,554)2 12,081Income (loss) from operations Other income (expense)6 2,799 125$3 0,675(991) 2 9,684$(13,744) 3 7,805 2 4,061$(33,064) (2,184) (35,248) (2)4 6,666 3 4,755Net income (loss) before income taxes$6 2,924$ 8 1,421(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.

USE OF SEGMENT INFORMATION AND NON-GAAP MEASURES 1) The Company often provides financial metrics for each of Triangle’s three segments of operation. Revenues for each segment are disclosed in notes to the financial statements contained in the Company’s Form 10-K and Form 10-Q filings, but the sum of those unconsolidated revenues differs from Triangle’s consolidated revenues for the corresponding reporting period. Triangle’s consolidated revenues would reflect segment revenues reduced for intracompany sales (i.e. for RockPile services to Triangle’s E&P segment). Triangle also believes that unconsolidated segment revenue assists investors in measuring RockPile’s performance as a stand- alone company without eliminating, on a consolidated basis, certain revenues attributable to completion services for Triangle’s economic interests in new wells operated by Triangle. 2) EBITDA represents income before interest, income taxes, depreciation and amortization. EBITDA is not a calculation based upon generally accepted accounting principles in the U.S. ("GAAP"). Triangle has presented ranges of anticipated EBITDA, by segment, because it regularly reviews EBITDA by segment as a measure of the segment’s operating performance. Triangle also believes EBITDA assists investors in comparing segment performance on a consistent basis without regard to interest, income taxes, depreciation and amortization, which can vary significantly depending upon many factors. A large portion of Triangle’s consolidated interest expense relates to paid-in-kind interest on the convertible note at the parent. The total of EBITDA by segment is not indicative of Triangle’s consolidated EBITDA, which reflects other matters such as (i) additional parent administrative costs, (ii) the aforementioned intracompany eliminations, and (iii) the use of the equity method, rather than consolidation, for Triangle’s investment in Caliber. The EBITDA measures presented in the Tables may not always be comparable to similarly titled measures reported by other companies due to differences in the components of the calculation. 3) Adjusted net income (loss) is defined as net income (loss) applicable to common stockholders Adjusted to exclude certain charges or amounts in order to provide users of this financial information with additional meaningful comparisons between current results and the results of prior periods. We present this measure because (i) it is consistent with the manner in which the Company's performance is measured relative to the performance of its peers, (ii) this measure is more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the company excludes information regarding these types of items. These Adjusted amounts are not a measure of financial performance under GAAP. We believe that net income (loss) is the performance measure calculated and presented in accordance with GAAP that is most directly comparable to Adjusted net income (loss).