Corporate Presentation June 2015

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 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 8 Appendix 4 Operational Overview 16 22

Business Overview

Gathering, transportation, treating and processing services JV with First Reserve Energy Infrastructure Fund (FREIF) Benefits include: reducing costs, eliminating flaring, reducing volumes transported via trucks and crude stabilization TPC wholly owned energy services subsidiary TPC wholly owned E&P subsidiary Business Overview Triangle Petroleum Corporation OVERVIEW 5 Offers integrated completion services package including pressure pumping, wireline and pump down and well intervention services Maintained high utilization with third parties through TUSA completion deferral period Increase in market share through downturn positions company well for a recovery scenario although visibility is very limited and utilization levels are subject to change Independent E&P company operating in the Williston Basin Q1FY’16 production of ~13,775 Boepd; current production over ~13,000 Boepd Proved reserves of 58.9 MMBoe as of the end of FY2015 (1) ~82,400 net core acres predominantly in McKenzie / Williams Counties (62% operated; 84% HBP) FY2016 development contemplates 1.5 operated rigs on average and delaying completions(2) Focused on protecting the balance sheet, maintaining adequate liquidity and managing return on capital Note: Triangle Petroleum Corporation’s Q1 Fiscal Year 2016 (“Q1 FY2016”) ended April 30, 2015. (1) Based on internal parent level reserves as of January 31, 2015, which were independently audited by Cawley, Gillespie & Associates. TUSA reserves may differ slightly from parent level reserves due to intercompany eliminations, which improves well economics at the parent level. (2) Subject to commodity prices and gaps in the RockPile third-party completion schedule. TPC owns 50% of G.P. and 28% of L.P.

Key Investment Highlights 6 (1) Based on internal parent level reserves as of January 31, 2015, which were independently audited by Cawley, Gillespie & Associates. TUSA reserves may differ slightly from parent level reserves due to intercompany eliminations, which may improve well economics at the parent level. (2) As of April 30, 2015, pro forma for TUSA’s $350mm borrowing base, which became effective April 30, 2015 following the semi-annual redetermination. 58.9 MMBoe of proved reserves (89% liquids; 61% proved developed)(1) Contiguous acreage position prospective for Bakken and Three Forks (TFS) formations Extensive low-risk inventory continues to be enhanced with the success of ongoing down spacing tests and provides 20+ years of development at current pace 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 received $95mm of distributions from its non-E&P subsidiaries in FY2015 Integrated and Efficient Development Model $500mm in total lending facility commitments with $305mm in pro forma liquidity(2) Conservative financial approach with focus on protecting the balance sheet and cash flow FY’16 capex reduced ~71%; TPC/TUSA reported cash G&A targeted down ~20% YoY Repurchased 11.4mm shares and repurchased and retired $20.5mm face value of our outstanding 6.75% senior notes during 2H FY’15 Top-tier private equity partners (NGP, First Reserve and TIAA Oil & Gas Investments) Strong Financial Position Disciplined financial management supported by a team with a proven blend of technical, operational, commercial, land, and regulatory experience Key technical and operations members of our team average more than 20 years of industry experience Disciplined Managers and Experienced Operators Q1FY’16 production increased 69% year over year (YoY) FY2015 proved reserves increased 46% YoY(1) Increased scale during FY2015 and FY2014 through selective bolt-on acquisitions and trades in core area Substantial Growth in Operated production and Reserves Business Overview

PDP Reserves PUD Reserves Operated vs. Non-Operated Volumes (% of production) Significant Operated Production and Reserves Growth 7 Net Sold Production Volumes (Boepd) Note: FY2016 production guidance increased June 8, 2015 from initial range of 11,000-13,000 Boepd issued on February 5, 2015. (1) Based on internal parent level reserves as of April 30, 2015. TUSA reserves may differ slightly from parent level reserves due to intercompany eliminations, which may improve well economics at the parent level. Actual Production Business Overview FY2016 Avg. Daily Production Guidance 11,500 – 13,500 Boepd (1) Proved Reserves (MMBoe) Guidance Low Case Guidance High Case Avg. Rig Count Non-Operated Volumes Operated Volumes (1) 70% 65% 78% 80% 85% 86% 86% 85% 84% 30% 35% 22% 20% 15% 14% 14% 15% 16% 0% 20% 40% 60% 80% 100% Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 Q1 FY'15 Q2 FY'15 Q3 FY'15 Q4 FY'15 Q1 FY'16 % of Total Sold Volumes 2,714 4,287 6,804 7,254 8,129 10,551 12,230 14,747 13,775 1,334 5,286 11,441 13,500 0 2 4 6 8 10 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 Q1 FY'15 Q2 FY'15 Q3 FY'15 Q4 FY'15 Q1 FY'16 FY'13A FY'14A FY'15A FY'16E Operated Rig Count Net Sales Volumes (Boepd) 1.5 14.6 40.3 58.9 0 10 20 30 40 50 60 FY'12 FY'13 FY'14 FY'15

Operational Overview

Operational Overview Triangle USA Core Area – McKenzie and Williams Counties 9 (1) As of June 5, 2015. (2) See slide 23 in the Appendix for additional details on the bridge between FY2015 PDP EURs and the FY2016 average development program Middle Bakken target EUR. (3) TUSA’s operatorship in North Dakota has been confirmed through title and permits. In Montana, operatorship has been confirmed through title and permits or assumes 30% or greater working interest. (4) Gross Operated Locations Remaining assumes eight Bakken and four Three Forks wells per DSU. Recent Developments 127 gross operated horizontal wells currently producing and 24 wells in progress or waiting on completion(1) Average PDP EURs increased to ~532 Mboe in FY2015, which represented ~4% YoY growth Targeting Middle Bakken wells with 630 Mboe average EURs in FY2016(2) Strategic and targeted development of operated DSUs to maximize returns and operational efficiencies in current commodity price environment Successfully proved middle Bakken down spacing concept across TUSA core acreage, which implies 8 middle Bakken locations per DSU Further testing of Three Forks down spacing ongoing Evaluating conversion to 25% from 100% ceramic proppant completions based on historical performance of early tests Electrical submersible pumps (ESP) leading to expedited production; 30%+ increase on average over first 6 months Current Triangle Leasehold and Activity Details TPLM Core Net Core Acreage ~82,400 Percent Operated (%)(3) 62% Percent Held By Production (%) 84% Operated DSUs(4) 65 Total Operated Locations Remaining(3) 653 TPLM Acreage TPLM Operated DSU 2 Little Muddy Wells Avg. EUR: ~705Mboe 2 Wisness Wells Avg. EUR: ~790Mboe 4 Hagen Wells Avg. EUR: ~640Mboe 4 Nygaard Wells Avg. EUR: ~550Mboe Eckert Three Forks Well EUR: ~530Mboe ESP Installation Slick Water Frac Three Forks Downspace White Sand Proppant TUSA DSUs 1/31/2015 TUSA Core Acreage

Operational Overview Drilling and Production Profile 10 (1) Before RockPile and other eliminations. TUSA Operated Wells Completed (Gross vs. Net) Average Completed Well Cost by Fiscal Year (1) Leading edge AFEs have been reduced to $7.3mm, which is 28% below the FY2016 average (1) Driven by service company price concessions, internal efficiencies and other cost reductions FY2016 spud to TD target is ~14 days, which is in line with 2H FY’15 and Q1 FY’16 results Evaluating other changes to drilling and completion procedures and designs that could yield incremental savings Highlights Average Spud to Total Depth Drilled Days Reacted quickly to declining oil price environment 49% Reduction 5.0 8.0 9.0 9.0 9.0 15.0 17.0 8.0 5.0 4.3 6.2 6.4 6.7 6.2 10.4 13.4 4.5 3.3 Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 Q1 FY'15 Q2 FY'15 Q3 FY'15 Q4 FY'15 Q1 FY'16 Gross Operated Completions Net Operated Completions 28 24 17 14 10 0 5 10 15 20 25 30 FY'13 FY'14 FY'15 Q1FY'16 Record Well Days $4.1 $3.2 $7.8 $7.0 $11.9 $10.2 $7.3 $0 $2 $4 $6 $8 $10 $12 FY'14 FY'15 Leading Edge AFEs $MM

Operational Overview TPC Stand-alone Well Economics Overview 11 (1) Representative of current TUSA operated completion design including 31 stages, a cemented liner, a hybrid slickwater frac and 4mm pounds of proppant. Well dataset comprised of 40 wells. (2) McKenzie County historical production sourced from HPDI. Well dataset comprised of 214 wells. (3) See slide 23 in the Appendix for additional details on the bridge between FY2015 PDP EURs and the FY2016 average development program Middle Bakken target EUR. (4) Includes RockPile, Caliber, and other services consolidated intercompany eliminations that reduce capital expenditures at the Triangle Parent Company level. Intercompany eliminations subject to change based on future well costs, TUSA working interest in each well, completion design and per well service intensity. FY2016 Target Middle Bakken Well Assumptions Economic Sensitivity (WTI / HH Pricing) Gross EUR (Mboe)(3) 630 % Oil 83% 30-Day IP (Boepd) 507 Gross Well Cost ($mm)(4) $6.3 Oil Price Realization (% WTI) 90% Gas Price Realization (% HH) 79% NGL Price Realization (% WTI) 24% TUSA Operated Well(1) Offset Operator McKenzie County Well(2) TUSA Operated FY’16 Target Middle Bakken EUR - 100 200 300 400 0 10 20 30 40 50 Cumulative Production (Mboe) Months 0% 20% 40% 60% IRR D&C (-10%) IRR EUR (+10%) IRR Base IRR D&C (+10% D&C) IRR% $60.00 / $3.00 $70.00 / $3.00 $75.00 / $3.50

Simultaneous operations – 1) drilling operations, 2) Caliber piping freshwater provisions, 3) Workover rigs returning 2 wells to production and 4) operational production facilities Operational Overview RockPile Energy Services 12 “Best in Class” execution driving critical volume and access to new clients Q1 FY’16 was a record in terms of volume with 55 total wells completed and the number of completed stages up 21% QoQ despite challenging winter conditions However, intense competitive pressure drove significant revenue and margin compression Revenue per stage down from Q3 FY’15 peak due to price concessions and design changes Cost cuts lagged price concessions due to implementation hurdles and working through high-cost legacy materials inventory The near term Williston Basin completion services market outlook remains challenging but leading edge indicators with clients have begun to improve 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 >90% of work performed for third parties during FY Q1’16 vs. ~65% in FY Q1’15 1 5 6 5 8 9 9 9 15 17 8 5 1 4 5 10 19 16 17 19 26 37 50 - 10 20 30 40 50 60 70 80 90 100 0 5 10 15 20 25 30 35 40 45 50 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14 Q3 FY'14 Q4 FY'14 Q1 FY'15 Q2 FY'15 Q3 FY'15 Q4 FY'15 Q1 FY'16 Horsepower (000s) Wells Completed Triangle Wells 3rd Party Wells Horsepower

Operational Overview WILLISTON BASIN COMPLETION Services MARKET UPDATE 13 (1) Baker Hughes Weekly Rig Count. (2) North Dakota Industrial Commission Monthly Director’s Cut Report. (3) Based on RockPile Estimates, public filings and Wall Street research reports. Big 3: Baker Hughes, Halliburton and Schlumberger. North Dakota Average Monthly Rig Count (1) North Dakota Waiting on Completion Inventory(2) 9 The North Dakota rig count is down ~60% in 6 months since the late October 2014 peak Compares to 62% drop over 7 months in ‘08/’09 The backlog of wells in the basin waiting on completion has swelled as E&P companies delay completions Erosion of supply base likely to position the Bakken for a significant snapback in pricing when market turns This points to a favorable opportunity for players that can remain positioned to grow when the cycle turns Spreads Operating in Williston Basin(3) Completion Services Market Characteristics 78 0 50 100 150 200 250 Jan- 04 Jan- 05 Jan- 06 Jan- 07 Jan- 08 Jan- 09 Jan- 10 Jan- 11 Jan- 12 Jan- 13 Jan- 14 Jan- 15 # of Rigs Running 880 0 100 200 300 400 500 600 700 800 900 1000 Jan-12 May-12 Sep-12 Jan-13 May-13 Sep-13 Jan-14 May-14 Sep-14 Jan-15 # of wells in backlog 70 52 22 1.7 3.1 4.0 72 55 26 - 10 20 30 40 50 60 70 80 2013 2014 2015 Est. Frac Crews In the Williston Basin ND Frac Crews ex-RPES RPES Frac Crews

Operational Overview RockPile Maintaining utilization and gaining market share through downturn 14 (1) North Dakota Industrial Commission and RockPile Estimates. Average wells per spread based on estimated wells completed / estimated spreads working in the Williston Basin. (2) RockPile Estimates. RockPile Stages Completed Per Month RockPile’s Share of North Dakota Completions 9 Completed 730 stages in April, 40% more stages than previous single month record RockPile’s estimated share of completion activity has increased to ~15%, up from ~6% in calendar year 2014 Looking at market share from another perspective, RockPile has ~15% of the completion spreads that are currently active in the Williston Basin(2) Spreads Operating in Williston Basin(1) Highlights 0 100 200 300 400 500 600 700 800 Jul-12 Nov-12 Mar-13 Jul-13 Nov-13 Mar-14 Jul-14 Nov-14 Mar-15 # of Stages Completed 0% 5% 10% 15% 20% 25% 30% 0 50 100 150 200 250 300 Feb-14 Apr-14 Jun-14 Aug-14 Oct-14 Dec-14 Feb-15 RPES ND Market Share ND Total Completions ND Total Completions RPES ND Market Share 29 41 48 2% 6% 15% - 10 20 30 40 50 60 0% 2% 4% 6% 8% 10% 12% 14% 16% 2013 2014 2015 ND Avg Wells Completed Per Spread RPES Share of ND Frac Market Avg Wells per Spread RPES Mkt Share

Operational Overview Caliber Midstream 15 (1) Assumes all warrants exercised into Class A units. Reflects receipt by Triangle of 3.6mm new warrants in conjunction with FREIF’s equity infusion. (2) As of April 2015. Caliber Midstream Partners, LP is focused on providing gathering, transportation and processing in the Williston Basin $34m equity infusion made by FREIF in early 2015 to fund executed 3rd party agreements and for general corporate purposes Following FREIF’s equity infusion, Triangle has a ~28% ownership stake, but can still earn up to 50% subject to the performance of the business (1) Paid $6.1mm cash distribution net to Triangle in December 2014; cumulative cash distributions to date to Triangle equal ~$10mm Currently gathering an average of ~8.2 MMcfepd (2) in gas system and processing throughput of ~8.2 MMcfpd (2) through natural gas facility Phase I and II, including the Cartwright freshwater system, for TUSA complete and fully operational Crude flowed through the Alexander Oil Center starting in August 2014, providing stabilization as well as additional takeaway optionality via pipeline and truck to rail (both inbound and outbound loading services) 40,000 bbls of working storage and inbound and outbound truck loading services for access to rail option SWD injections averaging ~23,800 Bpd (2) Central facility crude gathering averaging ~14,300 Bopd (2)

Financial Overview

Financial Overview Current Position 17 (1) Basic shares outstanding as of June 2015. Does not include $137.6mm 5% convertible note, which is convertible into Triangle stock at $8.00 per share and potentially dilutive into approximately ~17.2mm shares of Triangle common stock. (2) Carrying value as of April 30, 2015, which includes ~$17.6mm in accrued interest. (3) As of April 30, 2015. (4) Common stock assumes conversion of $137.6mm convertible note as of April 30, 2015. Potentially dilutive into approximately ~17.2mm shares of Triangle common stock. (5) Calculated using outstanding management and board stock and options and unvested employee RSUs. Does not apply treasury stock method. Liquidity ($mm) Total Current and Potential Diluted Ownership Key Highlights Debt metrics remain conservative with TUSA senior debt to trailing 12-month adjusted EBITDA of 0.7x and RockPile debt to trailing 12-month adjusted EBITDA of 1.2x(2) In Q1 FY’16, proactively amended TUSA’s existing senior credit facility and modified certain covenants to further enhance TUSA’s financial flexibility (4) (5) (5) Current Position Common Stock - Public 89% Employee RSUs 3% Management and Board: Common Stock and Options 8% Total Cash $50 TUSA Credit Facility Availability $204 RPES Credit Facility Availability $51 Liquidity (3) $305 Share Price (as of June 5, 2015) $5.14 90-day % Change 2.2% Basic Shares Outstanding (mm) (1) 75.4 Market Capitalization ($mm) $387 Convertible Note ($mm) (2) $138 Debt ($mm) (3) $685

$150mm Senior Credit Facility Non-recourse to TPC, no cross default risk ~$99mm drawn, ~$51mm available (2) Allows for future cash distributions to TPC, with some restrictions Key covenants: <2.75x total debt / TTM EBITDA ~1.2x at end of Q1 FY’16 TTM Fixed charge coverage ratio >1.25x 25x at end of Q1 FY’16 $137.6mm 5% Convertible Note (includes ~$17.6mm of accrued interest) Converts into TPLM common stock at $8.00/sh Interest paid-in-kind RockPile Energy - wholly owned energy services subsidiary Triangle Petroleum USA - wholly owned E&P subsidiary Financial Overview Triangle Petroleum Corporation debt structure OVERVIEW 18 $350mm Senior Credit Facility ~$146mm drawn (1), ~$204mm available (2) Allows for limited movement of cash to/from TPC Key covenants: <2.75x senior secured debt/TTM EBITDA 0.7x at end of Q1 FY’16 Interest coverage ratio >2.5x 6.9x at end of Q1 FY’16 $429.5mm 6.75%Senior Unsecured Notes due 2022 Repurchased and retired $20.5mm face value for $13.9mm during FYQ4’15 TUSA debt is non-recourse to TPC, no cross default risk (1) As of April 30, 2015. (2) Based on April 30, 2015 amendment and semi-annual redetermination.

Financial Overview Stand-alone Capital Budget for FY2016 (ending January 31, 2016) 19 (1) FY2016 capital budget issued on February 5, 2015. (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 likely be reduced by eliminations. (3) Subject to commodity prices and gaps in the RockPile third-party completion schedule Budget Detail FY2016 Budget Highlights Represents a 71% year-over-year reduction Primary focus on protecting the balance sheet, maintaining adequate liquidity, return on capital and positioning for growth post-recovery Drilling plan contemplates 1.5 operated rigs on average for FY2016 Spud ~25-27 gross operated wells Complete ~27-29 gross operated wells Deferring completions (3) Anticipate having 20-24 wells waiting on completion, which could represent a source of incremental growth with a further improvement in commodity prices Budget Allocation (2) Capital Expenses FY2016 Proposed Budget ($mm) (1) E&P Operated Drilling Program $150-165 E&P Non-Operated Drilling Program $0-10 RockPile $15-20 Total $165-195 E&P Operated Drilling Program 88% E&P Non - Op Drilling Program 3% RockPile 10%

Financial Overview additional Business Segment Guidance 20 *Description of segment information and non-GAAP measures are located at the back of the Appendix (1) FY2016 guidance issued on February 5, 2015. (2) Reflects efforts to optimize internal cash G&A and shifting of some expenses to TPC from TUSA. (3) Comparison versus annualized expense incurred over Oct ‘14 to Dec ‘14 time period during which time RPES operated 4 hydraulic fracturing spreads; RPES anticipates purchasing or leasing an additional spread in FY2016. Excludes intercompany charges. (4) Given the impairment recorded in Q1 FY’16, the amount of accumulated NOLs for federal tax purposes and the possibility that the Company could recognize additional impairments in future periods if commodity prices remain at current levels or decline, we do not anticipate having any income tax expense for FY2016. FY2016 Consolidated Financials The following items must also be considered for the consolidated financials: Item Description Consolidated Triangle Parent Company (“TPC”) G&A Incremental corporate level G&A expense $18 - 23mm (2) FY2016 Effective Tax Rate 0%(4) TUSA-specific FY2016 items(1): RockPile-specific FY2016(1) items: $6.50-7.10/boe in LOE expenses $5.30-5.80/boe in gathering, transportation and processing expenses $1.30-1.40/boe in cash G&A expenses(2) represents 55%+ year-over-year decline 10-11% production tax rate $27-29mm in expected cash G&A expense ~10-15% decline from YE’15 levels(3) ~25%+ decline on per spread basis from YE’15(3) Anticipate 15%+ reduction on key costs (chemicals, proppant, labor, etc.) based on current market conditions Guidance details are subject to change based on the dynamic nature of the commodity price environment

Risk Management 21 Mark-to-market value of hedge book was ~$25mm as of April 30th, 2015 Hedging program consists of zero cost collars and swaps to protect present and future cash flows Ability to hedge up to 85% of expected production over next 36 months Monitoring market conditions for opportunities to adjust hedge position into FY2017 Financial Overview Hedge Position (BOPD) Current Hedges (BOPD and Volume Weighted Average Price) Key Highlights *Note: As of April 16, 2015. FY’16 Collars ~$98/Bbl Ceiling ~$87/Bbl Floor FY’16 Swaps ~$60/Bbl FY’17 Swaps ~$60/Bbl BOPD Hedged BOPD Hedged ~4,400 ~860 ~2,750 - 1,500 3,000 4,500 6,000 FY2016 FY2017 Costless Collar Volume Swap Volume 6,000 6,000 4,484 995 842 2,668 3,000 3,000 3,000 1,989 $87.50 $87.50 $82.47 $65.59 $60.23 $60.23 $60.23 $60.23 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 Q1 FY'16 Q2 FY'16 Q3 FY'16 Q4 FY'16 Q1 FY'17 Q2 FY'17 Q3 FY'17 Q4 FY'17 WTI Hedge Price ($ / Bbl) Costless Collar Volume Swap Volume VWAP - Floor

Appendix a) TUSA FY2016 EUR Bridge b) Historical Financials c) Reconciliations and Segment Information

Operational Overview TUSA FY2015 PUD EUR to FY2016 DEVELOPMENT PROGRAM TARGET MIDDLE BAKKEN EUR Bridge 23 (1) Per well PDP EURs based on reserve report as of January 31, 2015, which was independently audited by Cawley, Gillespie & Associates. (2) Representative of current completion design including 31 stages, a cemented liner, a hybrid slickwater frac and 4mm pounds of proppant. Well dataset comprised of 40 wells. Uplift for Exclusion of Non-Op Locations Gross Up for Average ~21% TUSA Royalty Uplift for Current Completion Design Improvements Uplift for Targeted FY2016 Development Program Uplift for Exclusion of Three Forks Locations 424 630 112 14 15 25 40 536 550 565 590 630 300 350 400 450 500 550 600 650 FY'15 YE Net PUD (1) Gross Up for Royalties Exclude Non-Op Locations Exclude Three Forks Current Completion Design Improvement (2) High Grade FY'16 Activity FY'16 Target EUR Per Well EUR (Mboe)

Appendix Q1 FY’16 Consolidated Income Statement 24 (a) Includes intercompany eliminations; reference Note 3 – Segment Reporting in the fiscal year 2015 Form 10-K for additional details. (b) The tax benefit for the quarter ended April 30, 2015 is associated with the establishment of a full valuation allowance against our net deferred tax assets. The effective tax rate for the quarter ended April 30, 2014 was approximately 40.8%. Income tax provision is a non-cash expense. (c) Includes interest expense add-back of $0.9 million net of income taxes and amounts capitalized Q1 fiscal 2015 related to outstanding convertible note. (d) See “Use of Segment Information and Non-GAAP Measures” and “Adjusted Net Income Reconciliation” in the Appendix for additional details. Quarter Ended April 30, Three Months Ended January 31, 2014 2015 Revenues Oil, natural gas and natural gas liquids sales 60,834 $ 47,778 $ Oilfield services (a) 38,948 70,510 Total revenues 99,782 118,288 Expenses Lease operating expenses 4,726 10,909 Gathering, transportation and processing 3,802 6,348 Production taxes 6,348 4,787 Depreciation and amortization (a) 21,287 37,806 Impairment of oil and natural gas properties - 192,000 Accretion of asset retirement obligations 25 57 Oilfield services (a) 27,710 65,464 Corporate and other stock-based compensation 1,523 2,136 E&P stock-based compensation 395 321 RockPile stock-based compensation 90 51 Corporate and other cash G&A expenses 3,518 4,977 E&P cash G&A expenses 2,778 748 RockPile cash G&A expenses 5,097 6,626 Total operating expenses 77,299 332,230 Operating Income (Loss) 22,483 (213,942) Interest expense, net (2,672) (9,106) Amortization of deferred loan costs (192) (616) Realized commodity derivative gains (losses) (818) 19,468 Unrealized commodity derivative gains (losses) (4,638) (33,442) Equity investment income (loss) (126) 188 Gain (loss) on equity investment derivatives 10,454 - Gain on Caliber capital transactions - 2,880 Other income (a) 62 930 Total other income (expense) 2,070 (19,698) Income (Loss) Before Income Taxes 24,553 (233,640) Income tax provision (benefit) (b) 10,011 (53,441) Net Income (Loss) Attributable to Common Stockholders 14,542 $ (180,199) $ Net Income (Loss) per Common Share Basic 0.17 $ (2.39) $ Diluted (c) 0.15 $ (2.39) $ Adjusted Net Income (Loss) per Common Share (d) Basic 0.13 $ (0.09) $ Diluted (c) 0.12 $ (0.09) $ Weighted Average Common Shares Basic 85,952 75,256 Diluted 103,314 75,256

Appendix Consolidated Adjusted Net Income Reconciliation Stand-Alone Business Segment Adjusted EBITDA Reconciliation 25 (a) Tax adjustment is calculated by applying Company's effective tax rate of 40.8% for Q1 fiscal 2015 to pre-tax effected adjusting items and expected Q1 fiscal 2016 statutory tax rate of 38.0% to adjusted pre-tax loss. (b) Includes interest expense add-back of $0.9 million net of income taxes and amounts capitalized for Q1 fiscal 2015 related to outstanding convertible note. (c) RockPile Adjusted EBITDA calculated as per RockPile credit facility. Quarter Ended April 30, 2014 2015 Net Income (Loss) Before Income Taxes 16,040 $ (217,693) $ Depreciation and amortization 20,153 29,299 Impairment of oil and natural gas properties - 192,000 Net interest expense 942 6,521 Stock-based compensation 395 321 Accretion of asset retirement obligations 25 57 Other 169 507 Unrealized commodity derivative losses (gains) 4,638 33,442 Adjusted-EBITDA 42,362 $ 44,454 $ Quarter Ended April 30, 2014 2015 Net Income (Loss) Before Income Taxes 8,437 $ (7,033) $ Depreciation and amortization 3,590 9,489 Stock-based compensation 90 51 Net interest expense 507 787 Other 1,176 219 Adjusted-EBITDA (c) 13,800 $ 3,513 $ Quarter Ended April 30, 2014 2015 Net income (Loss) Attributable to Common Stockholders $ 14,542 $ (180,199) Impairment of oil and natural gas properties - 192,000 Unrealized (gain) loss on commodity derivatives 4,638 33,442 (Gain) loss on equity investment derivatives (10,454) - Gain on Caliber capital transactions - (2,880) Tax benefit associated with reversal of deferred tax liability - (53,441) Tax adjustment (a) 2,373 4,210 Adjusted Net Income (Loss) 11,099 $ (6,868) $ Adjusted Net Income (Loss) Per Common Share Basic 0.13 $ (0.09) $ Diluted (b) 0.12 $ (0.09) $ Weighted Average Common Shares Basic 85,952 75,256 Diluted 103,314 75,256

Appendix Q1 FY’16 Intersegment Table 26 (a) Corporate and Other includes Triangle's corporate office and several subsidiaries that management does not consider to be part of the exploration and production or oilfield services segments. Also included are results from Triangle's investment in Caliber, including any changes in the fair value of equity investment derivatives. Other than Caliber, these subsidiaries have limited activity. (b) $2.9 million RockPile, Caliber, and other services consolidated elimination results in a $2.9 million reduction in oil and natural gas property expenditures. *Reference Note 3 – Segment Reporting in our fiscal year 2015 Form 10-K for additional details. Exploration and Production Oilfield Services Corporate and Other (a) Eliminations and Other Consolidated Total Revenues Oil, natural gas and natural gas liquids sales $ 47,778 $ - $ - $ - $ 47,778 Oilfield services for third parties - 71,090 - (580) 70,510 Intersegment revenues - 9,504 - (9,504) - Total Revenues 47,778 80,594 - (10,084) 118,288 Expenses LOE, GTP, Production Taxes and other expenses 22,101 - - - 22,101 Depreciation and amortization 29,299 9,489 325 (1,307) 37,806 Impairment of oil and natural gas properties 192,000 - - - 192,000 Cost of oilfield services - 70,586 1,238 (6,360) 65,464 General and administrative 1,069 6,677 7,113 - 14,859 Total operating expenses 244,469 86,752 8,676 (7,667) 332,230 Operating Income (196,691) (6,158) (8,676) (2,417) (213,942) Other income (expense), net (21,002) (875) 2,686 (507) (19,698) Net Income (Loss) Before Income Taxes $ (217,693) $ (7,033) $ (5,990) $ (2,924) (b) $ (233,640)

Use of Segment Information and Non-GAAP Measures 1) The Company often provides financial metrics for Triangle’s 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 stand-alone revenues differ from Triangle’s consolidated revenues for the corresponding reporting period. Triangle’s consolidated revenues would reflect segment revenues reduced for intercompany sales (i.e. for RockPile services to Triangle’s E&P segment). Triangle also believes that stand-alone segment revenue assists investors in measuring RockPile’s performance as a stand-alone company without eliminating, on a consolidated basis, certain revenues attributable to services for Triangle’s economic interests in wells operated by Triangle’s E&P segment. 2) Adjusted-EBITDA represents income before interest expense, income taxes, depreciation and amortization, other non-cash items, and non-recurring items. Adjusted-EBITDA is not a calculation based upon generally accepted accounting principles in the U.S. ("GAAP"). Triangle has presented Adjusted-EBITDA by segment because it regularly reviews Adjusted-EBITDA by segment as a measure of the segment’s operating performance. Triangle also believes Adjusted-EBITDA assists investors in comparing segment performance on a consistent basis without regard to interest expense, income taxes, depreciation and amortization, other non-cash items, and non-recurring items which can vary significantly depending upon many factors. The total of Adjusted-EBITDA by segment is not indicative of Triangle’s consolidated Adjusted-EBITDA, which reflects other matters such as (i) additional parent company administrative costs, (ii) intercompany eliminations, (iii) paid-in-kind interest expense on the convertible notes, and (iv) the use of the equity method, rather than consolidation, for Triangle’s investment in Caliber. The Adjusted-EBITDA measures presented in the “Reconciliation Tables” may not always be comparable to similarly titled measures reported by other companies due to differences in the components of the calculation. Triangle believes that net income before income taxes is the performance measure calculated and presented in accordance with GAAP that is most directly comparable to Adjusted-EBITDA. Net income before income taxes will be significantly affected by consolidated interest expense and full-cost pool amortization. Such amortization varies with changes in proved reserves, well costs during the year, and future plans in developing proved undeveloped reserves 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. Triangle presents 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).