Triangle Petroleum (TPLMQ) 8-K Regulation FD Disclosure

Exhibit 99.1

CORPORATE PRESENTATION December 2015

The information presented in this presentation may contain ʺforward‐looking statementsʺ 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 Companyʹs 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. FORWARD LOOKING STATEMENTS

TABLE OF CONTENTS Appendix20 Financial Overview14 Operational Overview8 Business Overview4

 BUSINESS OVERVIEW

Note: Triangle Petroleum Corporation’s Q3 Fiscal Year 2016 (“Q3 FY2016”) ended October 31, 2015. (1) (2) FY2016 production guidance increased November 7, 2015 from prior range of 11,500‐13,500 Boepd issued on June 8, 2015. 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. 5 BUSINESS OVERVIEW Offers integrated completion services package including pressure pumping, wireline and pump down and well intervention services Have maintained high utilization with third parties over the last four quarters 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 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 owns 50% of G.P. and 28% of L.P. TPC wholly owned energy services subsidiary Independent E&P company operating in the Williston Basin Q3FY’16 production of 13,685 Boepd; FY’16 production guidance of 13,200‐13,600 Boepd (1) Proved reserves of 58.9 MMBoe as of the end of FY2015 (2) ~78,000 net core acres predominantly in McKenzie / Williams Counties (63% operated; 91% held by production [HBP]) Focused on protecting the balance sheet, maintaining adequate liquidity and managing return on capital TPC wholly owned E&P subsidiary TRIANGLE PETROLEUM CORPORATION OVERVIEW

IMPROVING AND EFFICIENT (1) As of October 31, 2015. 6 BUSINESS OVERVIEW STILL POISED FOR FUTURE GROWTH Inventory of 18 gross operated wells waiting on completion serves as a ready source of production volumes(1) Extensive low‐risk inventory provides 20+ years of development 91% of core acreage is held by production DISCIPLINED MANAGERS AND EXPERIENCED OPERATORS Disciplined financial and operational management has enabled the Company to navigate through a challenging environment while at the same time preserving future growth optionality Strategically aligned to unlock value through potential future asset monetizations INTEGRATED BUSINESS MODEL Recycles meaningful capital expenditure dollars into the business Recovers value‐leakage to critical supply chain services Reduces reliance on third‐party service providers; relieves infrastructure constraints Triangle received $95mm of distributions from its non‐E&P subsidiaries in FY2015 Development program aims to preserve financial and operational flexibility $293mm in liquidity(1); no term debt maturities until 2022 Focused on protecting the balance sheet and preserving liquidity No long term rig or oilfield service commitments Top‐tier private equity partners (NGP, First Reserve and TIAA Oil & Gas Investments) STRONG FINANCIAL POSITION PROVIDES OPTIONS CONSISTENT FOCUS ON OPERATIONAL EFFICIENCIES Completion design evolution continues to improve well performance Evaluating further adjustments to well designs in an effort to further reduce costs, improve recoveries and enhance operational efficiencies and returns KEY INVESTMENT HIGHLIGHTS: MANAGING THROUGH THE DOWNTURN

16,000 00 14,000 4 12,000 10,000 8,000 2 6,000 4,000 2,000 0 0 Q1 FYʹ14 Q2 FYʹ14 Q3 FYʹ14 Q4 FYʹ14 Q1 FYʹ15 Q2 FYʹ15 Q3 FYʹ15 Q4 FYʹ15 Q1 FYʹ16 Q2 FYʹ16 Q3 FYʹ16 FYʹ13A FYʹ14A FYʹ15A FYʹ16E Actual Production Guidance Low Case Guidance High Case Avg. Rig Count 58.9 60 100% 50 80% 45% 40 60% 30 40% 20 20% 10 0% 0 Q1 FYʹ13 Q2Q3Q4 FYʹ13 FYʹ13 FYʹ13 Q1Q2 FYʹ14 FYʹ14 Q3Q4Q1 FYʹ14 FYʹ14 FYʹ15 Q2 FYʹ15 Q3 FYʹ15 (2) FYʹ12 FYʹ13 PDP Reserves FYʹ14 PUD Reserves FYʹ15 Non‐Operated Volumes Operated Volumes (1) (2) FY2016 production guidance increased November 7, 2015 from prior range of 11,500‐13,500 Boepd issued on June 8, 2015. 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. 7 BUSINESS OVERVIEW Operated Rig Count Net Sales Volumes (Boepd) % of Total Sold Volumes 22%20%15%13%14% 31%30%35% 64% 100% 40.3 14.6 1.5 PROVED RESERVES (MMBOE) OPERATED VS. NON‐OPERATED VOLUMES (% OF PRODUCTION) FY2016 Avg. Daily Production Guidance14,747 13,200 – 13,600 Boepd (1) 12,230 13,77513,50013,68513,6 11,441 10,551 8,129 6,8047,254 4,287 2,714 5,286 1,334 NET SOLD PRODUCTION VOLUMES (BOEPD) SIGNIFICANT OPERATED PRODUCTION AND RESERVES GROWTH

 OPERATIONAL OVERVIEW

135 gross operated horizontal wells currently producing and 18 gross (15.8 net) wells waiting on completion(1) Targeting Middle Bakken wells with 630 Mboe average EURs in FY2016(2) FY2016 Middle Bakken wells completed year to date exceeding target Strategic and targeted development of operated DSUs to maximize returns and operational efficiencies in current commodity price environment Leading edge AFEs have been reduced to $6‐6.3mm driven by ongoing service price concessions, internal efficiency improvements and other cost reductions Latest completion design delivering 15%+ and 25%+ improvement in 60‐ and 90‐day cumulative production over analogue offset wells over a broad geographic area 4 4 Net Core Acreage ~78,000 Percent Held By Production (%) 91% GROSS OPERATED LOCATIONS REMAINING(4) 573 (1) (2) 9 (3) (4) As of October 31, 2015. See slide 21 in the Appendix for additional details on the bridge between FY2015 PDP EURs and the FY2016 average development program Middle Bakken target EUR. 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. Gross Operated Locations Remaining assumes eight Bakken and four Three Forks wells per operated DSU less currently producing gross operated wells. OPERATIONAL OVERVIEW OPERATED DSUS(3) 59 TUSA AcreageTUSA Operated DSUWells WOC Percent Operated (%)(3) 63% DETAILSTPLM CORE 2 2 2 Wisness Wells Avg. EUR: ~790Mboe 2 4 4 Hagen Wells Avg. EUR: ~640Mboe 2 Little Muddy Wells Avg. EUR: ~705Mboe CURRENT TRIANGLE LEASEHOLD AND ACTIVITY RECENT DEVELOPMENTS TRIANGLE USA CORE AREA – MCKENZIE AND WILLIAMS COUNTIES

FY’16 Operated Middle Bakken Completion(1) 160 17.0 $120 Mboe)(2) $100 environment 140 $80 $60 120 $40 3.3 $20 100 $‐ Q1 FYʹ14 Q2Q3Q4Q1Q2 FYʹ14 FYʹ14 FYʹ14 FYʹ15 FYʹ15 Gross Operated Completions Quarterly Avg. WTI Price Q3 FYʹ15 Q4Q1 FYʹ15 FYʹ16 Q2Q3 FYʹ16 FYʹ16 Net Operated Completions 80 60 $11.9 $12 $10 40 $8 $6 20 $4 $2 ‐ 0 30 60 90120 150 180 210 $0 FYʹ14 FYʹ15 Leading Edge AFEs Producing Days (1) (2) Well dataset comprised of 13 Middle Bakken wells completed year to date. See slide 21 in the Appendix for additional details on the bridge between FY2015 PDP EURs and the FY2016 average development program Middle Bakken target EUR. Before RockPile and other eliminations. (3) 10 OPERATIONAL OVERVIEW Cumulative Production (Mboe) $MM # of wells $/Bbl $10.2 $6‐6.3 $4.1$3.2 $7.0 $7.8 AVERAGE COMPLETED WELL COST BY FISCAL YEAR (3) 15.0Reacting quickly 13.4to oil price 10.4 9.09.09.09.0 8.08.0 6.26.46.76.26.6 5.05.0 4.34.5 2.0 1.7 FY’16 Operated Target Middle Bakken EUR (630 TUSA OPERATED WELLS COMPLETED (GROSS VS. NET) FY2016 MIDDLE BAKKEN WELL PERFORMANCE DRILLING AND PRODUCTION PROFILE

ile Energy Services, LLC is focused on providing “Best in pressure pumping and ancillary services in the Williston Basin Triangle Wells 3rd Party Wells Horsepower in Class” execution driving critical volume with existing clients, opening up access to new clients and g opportunities for geographic diversification >90% of work performed for third parties during 50 45 40 35 30 25 20 15 10 5 0 110 100 90 80 70 60 50 40 30 20 10 0 tion dropped in Q3 FY’16 as key clients deferred completion activity ued focus on cost reduction yielding significant and RockPile’s costs are on par or superior to of our major competitors 1 999 9 8 8 6 5 5 5 2 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 FYʹ13 FYʹ13 FYʹ13 FYʹ14 FYʹ14 FYʹ14 FYʹ14 FYʹ15 FYʹ15 FYʹ15 FYʹ15 FYʹ16 FYʹ16 FYʹ16 However, intense competitive pressure has resulted in unsustainable pricing. And while major input costs fallen significantly, these reductions have not kept ith pricing and design changes so margins are compressed 16 activity levels are trending ahead of Q3 FY’16 supported by increased activity in legacy basins and the establishment of operations in new markets including mian Basin where one completion crew is active other ancillary services are being provided 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 Horsepower (000s) Wells Completed Q3 FY’16 vs. ~60% in Q3 FY’15 265039 1937 1617 101925 1451517 GROSS WELLS COMPLETED EVERAGING REPUTATION & MAINTAINING FOCUS ROCKPILE ENERGY SERVICES RockP Class” L “Best creatin Utiliza Contin results most have pace w still Q4 FY’ the Per and 11

The North Dakota rig count is down ~70% in 13 months since the October 2014 peak Compares to 62% drop over 7 months in ‘08/’09 The backlog of wells in the basin waiting on completion swelled as E&P companies delayed completions Erosion of supply base continues with an estimated ~14 completion spreads currently active in the Williston Basin, ~15% of which are RockPile spreads. This could drive a significant snapback in pricing when activity recovers ‐05 Jan‐06 Jan‐07 Jan‐08 Jan‐09 Jan‐10 Jan‐11 Jan‐12 Jan‐13 Jan‐14 Jan‐15 800 700 5 600 500 400 300 200 100 0 y‐12 Sep‐12 Jan‐13 May‐13 Sep‐13 Jan‐14 May‐14 Sep‐14 Jan‐15 May‐15 Sep‐15 Jul‐12 Nov‐12 Mar‐13 Jul‐13 Nov‐13 Mar‐14 Jul‐14 Nov‐14 Mar‐15 Jul‐15 ) ) ) Baker Hughes Weekly Rig Count, December 4, 2015. North Dakota Industrial Commission December 2015 Monthly Director’s Cut Report. Based on RockPile Estimates, public filings and Wall Street research reports. OPERATIONAL OVERVIEW Williston Basinn Rig Count # of wells in backlog RPES Stages Completed 97 ROCKPILE STAGES COMPLETED PER MONTH DAKOTA WAITING ON COMPLETION INVENTORY(2) 60 COMPLETION SERVICES MARKET CHARACTERISTICS DAKOTA AVERAGE MONTHLY RIG COUNT (1) WILLISTON BASIN COMPLETION SERVICES MARKET UPDATE NORTH 250 200 150 100 50 0 Jan‐04 Jan NORTH 1200 1000 800 600 400 200 0 Jan‐12 Ma (1 12(2 (3

Caliber Midstream Partners, LP is focused on providing gathering, transportation and processing in the Williston Basin Triangle has a ~28% ownership stake, but can still earn up to 50% subject to the performance of the business (1) Cumulative cash distributions to date to Triangle equal ~$10mm Currently gathering an average of ~6.3 MMcfepd (2) in gas system and processing throughput of ~6.3 MMcfpd (2) through natural gas facility 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 ~24,570 Bpd (2) Central facility crude gathering averaging ~12,800 Bopd (2) Assumes all warrants exercised into Class A units. Reflects receipt by Triangle of 3.6mm new warrants in conjunction with FREIF’s early 2015 equity infusion. As of October 2015. OPERATIONAL OVERVIEW CALIBER MIDSTREAM 13(1) (2)

 FINANCIAL OVERVIEW

Share Price (as of December 17, 2015) $0.61 Total Cash $36 90‐da y % Cha nge ‐72.0% TUS A Credit Facility Availability $161 Basic Shares Outstanding (mm)(1) 75.7 RPES Credit Facility Availability $96 At the end of Q3FY’16, TUSA’s senior debt to trailing 12‐month adjusted EBITDA ratio was 1.0x and RockPile’s debt to trailing 12‐month adjusted Common Stock ‐ Public (4) 94% Management and Board: Common Stock and Options 2% (5) (3) EBITDA ratio was 2.3x In Q4FY’16, the borrowing base on TUSA’s existing senior credit facility was reaffirmed at $350mm Employee RSUs (5) 4% Remain in compliance with all other covenant requirements on respective subsidiary credit facilities (1) Basic shares outstanding as of October 2015. Does not include $141.0mm 5% convertible note, which is convertible into Triangle stock at $8.00 per share and potentially dilutive into approximately ~17.6mm shares of Triangle common stock. Carrying value as of October 31, 2015, which includes ~$21mm in accrued interest. As of October 31, 2015. Common stock assumes conversion of $141.0mm convertible note as of October 31, 2015. Potentially dilutive into approximately ~17.6mm shares of Triangle common stock. Calculated using outstanding management and board stock and unvested employee RSUs. Does not apply treasury stock method. Excludes management options. (2) (3) (4) 15 (5) FINANCIAL OVERVIEW TOTAL CURRENT AND POTENTIAL DILUTED OWNERSHIP Debt ($mm) (3) $673 KEY HIGHLIGHTS Conver tible Note ($mm) (2) $141 Liquidity(3) $293 Mar ket Capitalization ($mm)$46 CURRENT POSITION LIQUIDITY ($MM) CURRENT POSITION

Triangle Petroleum USA ‐ wholly owned E&P subsidiary RockPile Energy ‐ wholly owned energy services subsidiary (1) As of October 31, 2015. 16 FINANCIAL OVERVIEW $350mm Senior Credit Facility ~$189mm drawn (1), ~$161mm available Allows for limited movement of cash to/from TPC Key covenants: <2.75x senior secured debt/TTM EBITDA 1.0x at end of Q3FY’16 Interest coverage ratio ≥2.5x 5.5x at end of Q3FY’16 $415.9mm 6.75%Senior Unsecured Notes due 2022 Repurchased and retired $34.1mm face value for $22.2mm over the last four quarters TUSA debt is non‐recourse to TPC, no cross default to TPC or RockPile $150mm Senior Credit Facility Non‐recourse to TPC, no cross default to TPC or TUSA ~$54mm drawn, ~$96mm available (1) Allows for future cash distributions to TPC, with some restrictions Key covenants: <2.75x total debt/TTM EBITDA 2.29x at end of Q3FY’16 TTM Fixed charge coverage ratio >1.25x 7.7x at end of Q3FY’16 $141.0mm 5% Convertible Note (includes ~$21.0mm of accrued interest) Converts into TPLM common stock at $8.00/sh Interest paid‐in‐kind No financial covenants Not exposed to cross default risk from subsidiaries TRIANGLE PETROLEUM CORPORATION DEBT STRUCTURE OVERVIEW

E&P Operated Drilling Program $150‐165 E&P Non‐Operated Drilling Program $0‐10 RockPile $15‐20 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 program temporarily paused due to current depressed commodity pricing environment Spud 16 gross operated wells to date Plan to complete ~20‐22 gross operated wells(3) 18 wells waiting on completion as of October 31st could provide a source of incremental supply to manage production and/or increase volumes with improvement in commodity prices E&P Non‐Op Drilling Program 3% E&P Operated Drilling RockPile 10% (2) Program 88% (1) (2) FY2016 capital budget issued on February 5, 2015. 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. Gross completion count may vary depending on actual working interests in operated wells and is subject to commodity prices and gaps in the RockPile’s third‐party completion schedule. (3) 17 FINANCIAL OVERVIEW BUDGET ALLOCATION FY2016 BUDGET HIGHLIGHTS Total$165‐195 Capital ExpensesFY2016 Proposed Budget ($mm)(1) BUDGET DETAIL STAND‐ALONE CAPITAL BUDGET FOR FY2016 (ENDING JANUARY 31, 2016)

$21‐23mm in expected cash G&A expense ― ~17‐24% decline from Q4 FY’15 levels(4) Anticipate 30‐50% reduction on key input costs (chemicals, proppant, labor, etc.) based on current market conditions $8.50‐9.00/boe in LOE expenses(2) $5.30‐5.80/boe in gathering, transportation and processing expenses $1.30‐1.40/boe in cash G&A expenses(3) ― represents 55%+ year‐over‐year decline 10‐11% production tax rate The following items must also be considered for the consolidated financials: Consolidated Triangle Parent Company (“TPC”) G&A Incremental corporate level G&A expense $18 - 23mm (3) FY2016 Effective Tax Rate 0%(5) *Description of segment information and non‐GAAP measures are located at the back of the Appendix (1) (2) (3) (4) (5) FY2016 guidance issued on February 5, 2015. Raised LOE guidance in conjunction with Q2FY’16 results on September 8, 2015 to account for higher than expected workover and saltwater disposal costs. Reflects efforts to optimize internal cash G&A and shifting of some expenses to TPC from TUSA. Comparison versus annualized expense incurred during Q4 FY’15; Excludes intercompany charges. Given the impairments recorded to date, 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. 18 FINANCIAL OVERVIEW ITEMDESCRIPTION FY2016 CONSOLIDATED FINANCIALS ROCKPILE‐SPECIFIC FY2016(1) ITEMS: TUSA‐SPECIFIC FY2016 ITEMS(1): Guidance details are subject to change based on the dynamic nature of the commodity price environment ADDITIONAL BUSINESS SEGMENT GUIDANCE

Mark‐to‐market value of hedge book was ~$8mm as of October 31st, 2015 3,000 Hedging program consists of zero cost collars and swaps to protect present and future cash flows 2,000  Ability to hedge up to 85% of expected production over next 36 months 1,000 Monitoring market conditions for opportunities to further adjust hedge position into FY2017 ‐ FY2016 Costless Collar Volume FY2017 Swap Volume $68.59 $70.00 4,000 $60.00 $50.00 3,000 $40.00 2,000 $30.00 $20.00 1,000 $10.00 0 $‐ Q4 FYʹ16 Q1 FYʹ17 Costless Collar Volume Q2 FYʹ17 Q3 FYʹ17 VWAP Floor Q4 FYʹ17 Swap Volume 19 *Note: As of October 31, 2015. FINANCIAL OVERVIEW WTI Hedge Price ($/Bbl) BOPD Hedged BOPD Hedged $60.03 $57.31$55.54$54.80 1,995 3,0003,000 1,674 9951,000 CURRENT HEDGES (BOPD AND VOLUME WEIGHTED AVERAGE PRICE) FY’17 Swaps FY’16 Swaps ~$56/Bbl ~$60/Bbl ~2,200 Q4 FY’16 Collars ~$96/Bbl Ceiling ~$80/Bbl Floor ~1,000 ~2,000 KEY HIGHLIGHTS HEDGE POSITION (BOPD) RISK MANAGEMENT

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

650 600 FY2016 550 t for Current Completion Design Improvements 500 450 400 350 300 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 (1) (2) Per well PDP EURs based on reserve report as of January 31, 2015, which was independently audited by Cawley, Gillespie & Associates. 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. 21 OPERATIONAL OVERVIEW Per Well EUR (Mboe) 590 630 40 630 536 565 Uplift for Targeted Development Program 550 15 Uplif 14 112 Uplift for Exclusion of Non‐Op Locations 424 Gross Up for Average ~21% TUSA Royalty Uplift for Exclusion of Three Forks Locations 25 TUSA FY2015 PUD EUR TO FY2016 DEVELOPMENT PROGRAM TARGET MIDDLE BAKKEN EUR BRIDGE

Quarter Ended October 31, 2014 2015 Revenues Oil, natural gas and natural gas liquids s ales Oilfield s ervices (a) Total revenues Expens es Leas e operating expens es Gathering, trans portation and proces s ing Production taxes Depreciation and amortization(a) Impairment of oil and natural gas properties Accretion of as s et retirement obligations Oilfield s ervices (a) Corporate and other s tock-bas ed compens ation E&P stock-based compensation RockPile s tock-bas ed compens ation Corporate and other cas h G&A expens es E&P cas h G&A expens es RockPile cas h G&A expens es Other Total operating expens es $ 80,139 94,057 $ 42,871 22,273 174,196 65,144 7,317 4,380 8,637 32,471 - 259 70,805 1,587 94 146 3,693 2,896 7,043 1,334 10,135 6,537 4,052 28,396 261,000 75 21,700 7,259 390 117 4,477 855 5,336 - 140,662 350,329 Operating Income (Los s ) 33,534 (285,185) Interest expense, net Amortization of deferred loan cos ts Gain on extinguis hment of debt Realized commodity derivative gains (los s es ) Unrealized commodity derivative gains (los s es ) Equity inves tment income (los s ) Gain (los s ) on equity inves tment derivatives Other income(a) Total other income (expens e) (8,984) (479) - 688 19,134 393 742 (330) (9,877) (852) 4,175 27,857 (21,044) 450 (1,118) (1,405) 11,164 (1,814) Income (Los s ) Before Income Taxes Income tax provis ion (benefit)(b) Net Income (Los s ) Attributable to Common Stock holders 44,698 19,300 (286,999) - $ 25,398 $ (286,999) Net Income (Los s ) per Common Share Bas ic Diluted(c) Adjus ted Net Income (Los s ) per Common S hare(d) Bas ic Diluted(c) Weighted Average Common S hares Bas ic Diluted $ $ 0.30 0.26 $ $ (3.80) (3.80) $ $ 0.17 0.15 $ $ (0.11) (0.11) 85,242 102,954 75,588 75,588 (a) Includes intercompany eliminations; reference Note 3 – Segment Reporting in the Q3 fiscal year 2016 Form 10‐Q for additional details. (b) The effective tax rate for the quarter ended October 31, 2014 was approximately 43.2%. 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 Q3 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. 22 APPENDIX Q3FY’16 CONSOLIDATED INCOME STATEMENT

Quarter Ended October 31, 2014 2015 Net Income (Los s ) Attributable to Common Stockholders Impairment of oil and natural gas properties Unrealized (gain) los s on commodity derivatives (Gain) los s on equity inves tment derivatives Gain on extinguis hment of debt Sys tem convers ion cos ts Tax adjus tment(a) Adjusted Net Income (Loss) Adjus ted Net Income (Los s ) Per Common Share Bas ic Diluted(b) Weighted Average Common S hares Bas ic Diluted $ 25,398 - (19,134) (742) - 1,334 8,007 $ (286,999) 261,000 21,044 1,118 (4,175) - - $ 14,863 $ (8,012) $ $ 0.17 0.15 $ $ (0.11) (0.11) 85,242 102,954 75,588 75,588 STAND‐ALONE BUSINESS SEGMENT ADJUSTED EBITDA RECONCILIATION Quarter Ended October 31, 2014 2015 $ 37,057 30,291 - 6,846 94 259 1,813 $ (258,576) 21,394 261,000 7,241 390 75 (3,419) Net Income (Los s ) Before Income Taxes Depreciation and amortization Impairment of oil and natural gas properties Net interes t expens e Stock-bas ed compens ation Accretion of as s et retirement obligations Other Unrealized commodity derivative los s es (gains ) Adjus ted-EBITDA (19,134) 21,044 $ 57,227 $ 49,149 Quarter Ended October 31, 2014 2015 Net Income (Los s ) Before Income Taxes Depreciation and amortization Stock-bas ed compens ation Net interest expense Other Adjus ted-EBITDA(c) $ 26,829 6,119 146 572 999 $ (13,173) 6,797 117 793 1,456 $ 34,665 $ (4,010) (a) Tax adjustment is calculated by applying Companyʹs effective tax rate of 43.2% for Q3 fiscal 2015 to pre‐tax effected adjusting items. (b) Includes interest expense add‐back of $0.9 million net of income taxes and amounts capitalized for Q3 fiscal 2015 related to outstanding convertible note. (c) RockPile Adjusted EBITDA calculated as per RockPile credit facility. 23 APPENDIX CONSOLIDATED ADJUSTED NET INCOME RECONCILIATION

Corporate and Other(a) Exploration and Production Oilfield Services Eliminations and Other Cons olidated Total Revenues Oil, natural gas and natural gas liquids s ales Oilfield s ervices for third parties Inters egment revenues Total Revenues $ 42,871 - - $ - 21,922 3,881 $ - - - $ - 351 (3,881) $ 42,871 22,273 - 42,871 25,803 - (3,530) 65,144 Expens es LOE, GTP, Production Taxes and other expens es Depreciation, amortization and accretion Impairment of oil and natural gas properties Cos t of oilfield s ervices General and adminis trative Total operating expens es 20,724 21,469 261,000 - 1,245 - 6,797 - 24,664 5,453 - 420 - - 11,736 - (215) - (2,964) - 20,724 28,471 261,000 21,700 18,434 304,438 36,914 12,156 (3,179) 350,329 Operating Income Other income (expens e), net Net Income (Los s ) Before Income Taxes (261,567) 2,991 (11,111) (2,062) (12,156) (2,298) (351) (445) (285,185) (1,814) (796) (b) $ (258,576) $ (13,173) $ (14,454) $ $ (286,999) (a) Corporate and Other includes Triangleʹs 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 Triangleʹs investment in Caliber, including any changes in the fair value of equity investment derivatives. Other than Caliber, these subsidiaries have limited activity. (b) $0.8 million RockPile, Caliber, and other services consolidated elimination results in a $0.8 million reduction in oil and natural gas property expenditures. *Reference Note 3 – Segment Reporting in our Q3 fiscal year 2016 Form 10‐Q for additional details. 24 APPENDIX Q3FY’16 INTERSEGMENT TABLE

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. (ʺGAAPʺ). 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 5% convertible note, 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 Companyʹs 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). USE OF SEGMENT INFORMATION AND NON‐GAAP MEASURES