FORWARD LOOKING STATEMENT Certain statements in this press release regarding strategic plans, expectations and objectives for future operations or results are "forward-looking statements" as defined by the Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this press release 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, including the risks discussed in the Company's annual report on Form 10-K and the Company's other filings with the Securities and Exchange Commission. Factors that could cause differences include, but are not limited to history of losses; speculative nature of oil and natural gas exploration; changes in estimates of proved reserves; substantial capital requirements and inability to access additional capital; reductions in the borrowing base under the Company's credit facility; reallocations or reductions in the fiscal 2014 capital budget; inability to meet the drilling schedule; changes in tax regulations applicable to the oil and natural gas industry; results of acquisitions; failure to close anticipated acquisitions; relationships with partners and service providers; inability to acquire additional leasehold interests or other oil and natural gas properties; defects in title to the Company's oil and natural gas interests; inability to manage growth in the Company's businesses, including RockPile Energy Services and Caliber Midstream; properties that the Company does not operate; lack of diversification; competition in the oil and natural gas industry; global financial conditions; oil and natural gas realized prices; future production and development costs; inability to market and distribute oil and natural gas produced; inability to meet financial and production guidance; cancellation of expected RockPile Energy Services completion jobs by third-party operators; delays or complications in construction operations; inability to secure third party contracts; seasonal weather conditions; government regulation of the oil and natural gas industry, including potential regulations affecting hydraulic fracturing and environmental regulations such as climate change regulations; cybersecurity risks; aboriginal derivative instruments and hedging program; and a material weakness in internal accounting controls. The forward-looking statements in this press release are made as of the date of this press release, even if subsequently made available by the Company on its website or otherwise. The Company does not undertake any obligation to update the forward-looking statements as a result of new information, future events or otherwise.

Gathering, transportation, treating and processing services JV with First Reserve Energy Infrastructure Fund (70% of L.P.) All segments of the Phase I system expected to be in service by the third quarter of fiscal year 2014 TPC wholly owned energy services subsidiary TPC wholly owned E&P subsidiary BUSINESS OVERVIEW TRIANGLE PETROLEUM CORPORATION OVERVIEW 5 TPC owns 50% of G.P. and 30% of L.P. Hydraulic pressure pumping and well completion services Provides greater largest cost center ~45% of completion jobs since inception performed for third parties Growth oriented E&P company focused on the Williston Basin ~95,000 net acres, with current production rate of ~5,650 Boepd and proved reserves of 22.9 MMBoe(1) ~45,000 net acres in core areas of McKenzie / Williams Counties (64% operated)(2) Recent acquisition of several properties contiguous to existing acreage in McKenzie County (1) Internal reserve estimate, as of April 30, 2013, pro forma for the Aggregate Acquisitions announced August 6, 2013. (2) Percent operated information pro forma for the Aggregate Acquisitions. Note: TUSA information pro forma for Aggregate Acquisitions. Triangle Petroleum Corporation has Fiscal Year end January 31.

KEY INVESTMENT HIGHLIGHTS 6 (1) Internal reserve estimate as of April 30, 2013, pro forma for the Aggregate Acquisitions. Production estimate based on 4,100 as of July 31, 2013, not pro forma for the Aggregate Acquisitions. (2) Production estimate based on midpoint of (3) Assumes debt balance as of April 30, 2013, pro forma for the Aggregate Acquisitions, equity issuances and borrowing base redetermination. ~95,000 net acres; 22,865 MBoe proved reserves (87% oil; 45% proved developed)(1) The Aggregate Acquisitions have increased our scale in core areas of McKenzie County The Bakken Shale and Three Forks formations in the Williston Basin represent one of the largest oil deposits in North America OIL-FOCUSED WILLISTON BASIN OPERATOR Reduces reliance on third-party service providers and relieves challenging infrastructure constraints Recovers value-leakage to critical supply chain services Multi-well pad drilling, zipper-, improve costs and completion time INTEGRATED AND EFFICIENT DEVELOPMENT MODEL $165 million reserve-based lending facility with $247mm in pro forma liquidity as of 4/30/13(3) Conservative financial policies with focus on protecting cash flow through hedging 3,350 Boepd and 2,700 Boepd hedged for CY 2013 and 2014, respectively Top-tier private equity partners (NGP, First Reserve and TIAA Oil & Gas Investments) STRONG FINANCIAL POSITION Key members of the technical and operations team each have 10 to 35 years of oil and gas experience Focused on continued hiring of seasoned operating personnel with substantial experience in the Williston Basin HIGHLY EXPERIENCED OPERATIONS TEAM Production and reserves have increased 257% and 1,043%,(1) respectively, in the last year 47% quarter over quarter increase production rate from Q1 2014 to Q2 2014(2) Company continues to increase operated production at lower cost SUBSTANTIAL GROWTH IN OPERATED PRODUCTION AND RESERVES BUSINESS OVERVIEW

Nesson Anticline Core Operating Area OIL-FOCUSED SINGLE BASIN OPERATOR 7 Source: Triangle Petroleum Corporation, Montana Board of Oil and Gas, and North Dakota Industrial Commission, 2013. (1) Pro forma for the Aggregate Acquisitions. (2) working interest. (3) Base Case based upon 4 Bakken shale and 4 Three Forks wells per DSU; Upside Case based upon 8 Bakken shale and 4 Three Forks wells per DSU, supported by a recent 12-well density test in southern Williams County. DETAILS TPLM CORE AREA(1) NET ACREAGE ~45,000 PERCENT OPERATED (%)(2) 64% OPERATED DSUS(2) 40 - 42 TOTAL OPERATED DRILLING LOCATIONS(3) 320 - 504 BUSINESS OVERVIEW TPLM Operated DSU TPLM Acreage Three Forks Wells Bakken Wells County Primary Acquisition Concentrated acreage in core area of Williston Basin ~45,000 net acres in McKenzie and Williams Counties(1) Williston Basin in the early stages of 20+ year development program Increased density drilling and discovery of additional geologic zones may further increase the horizon of full development Provides Triangle with acquisition opportunities to increase scale Implementing the latest technologies including pad drilling and zipper-ncrease efficiencies while controlling costs ASSET MAP KEY HIGHLIGHTS

36% 55% 69% 70% 100% 64% 45% 31% 30% 0% 20% 40% 60% 80% 100% Q1 FY'13 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 SIGNIFICANT OPERATED PRODUCTION AND RESERVES GROWTH 8 NET PRODUCTION VOLUMES (BOEPD)(2)(3) (4) (1) Internal reserve estimate as of April 30, 2013, pro forma for the Aggregate Acquisitions. (2) Sold production volumes. (3) Acquisitions. (4) Revised exit guidance issued on August 6, 2013. Previous guidance (FY2014 Daily Production Guidance 3,600 4,000 Boepd) issued on March 4, 2013. (5) Median Bloomberg Consensus estimate as of August 1, 2013. Actual Production Guidance Low Case Guidance High Case Avg. Rig Count 616 696 1,120 1,389 2,098 2,714 3,900 5,000 7,000 4,100 5,500 8,000 0 2 4 6 8 10 0 2,000 4,000 6,000 8,000 10,000 Q4 FY'12 Q1 FY'13 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14E Q4 FY'14E Exit Previous Q4 FY'14E Exit Revised Operated Rig Count Net Sales Volumes (Boepd) Completed first operated well May 2012 RockPile completed first well August 2012 Caliber generates first revenues BUSINESS OVERVIEW 1,236 1,477 2,000 7,044 0 5,000 10,000 15,000 20,000 25,000 Q4 FY'11 Q4 FY'12 Q1 FY'13 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 8,278 14,637 22,865(1) PDP PUD (41% PDP) (17% PDP) (39% PDP) (38% PDP) (45% PDP) (45% PDP) (30% PDP) OPERATED VS. NON-OPERATED VOLUMES Operated Volumes Non-Operated Volumes FY2014 Avg. Daily Production Guidance 4,750 5,350 Boepd (Previous Guidance 3,600 4,000 Boepd) Consensus estimated median of ~3,700 Boepd(5) PROVED RESERVES (MBOE)

Net Percent Operated Gross Operated Locations Est. Current Proved % Proved % Details Acreage Operated DSUs(1) Base Case Upside Case Production (Boepd) Reserves Developed Oil Core Area 35,210 56% 33 264 396 4,500 16,050 48% 86% Aggregate Acquisitions 9,354 86% 7 - 9 56 - 72 84 - 108 1,150 6,815 37% 89% Pro Forma 44,564 64% 40 - 42 320 - 336 480 - 504 5,650 22,865 45% 87% Increase Over Standalone 27% 21% - 27% 21% - 27% 26% 42% (5) (6) (7) (4) (2) (3) TRANSACTION HIGHLIGHTS ACQUISITION OF PROPERTIES FROM THE AGGREGATE ACQUISITIONS 10 (1) (2) Pro forma for acreage traded in connection with the Aggregate Acquisitions. (3) Base Case based upon 4 Bakken and 4 Three Forks wells per DSU; Upside Case based upon 8 Bakken and 4 Three Forks wells per DSU. (4) Estimate based on a 21 day exit rate as of July 31, 2013. (5) Represents produced volumes for June 2013. (6) Triangle internal reserves estimates as of April 30, 2013. (7) The Aggregate Acquisitions reserves based on internal estimates utilizing SEC price deck as of July 1, 2013. Total consideration: ~$103.4 million cash + 582 nonop net acres traded + 325,000 shares ~9,350 net acres in McKenzie County, ND ~1,150 Boepd of current production Contiguous to current core producing properties, with access to Caliber infrastructure Substantially increased scale and operated acreage Acreage, production and reserves increased by 27%, 26% and 42%, respectively Operated acreage increases from 56% to 64% KEY ACQUISITION HIGHLIGHTS TPLM Op. DSU Bolt-on Acq. Operated DSUs Primary Acq. Operated DSUs TPLM Acreage PRO FORMA ASSET MAP

On August 6, 2013, Triangle announced several equity and debt financing deals Signed definitive agreement for two equity offerings to raise a total of approximately $190 million in gross proceeds Amendment to TUSA's Senior Credit Facility and Borrowing Base Redetermination Resulting in a $55 million increase in the borrowing base to $165 million from $110 million Received non-binding commitment letter and term sheet from Wells Fargo for a senior secured second-lien term loan facility of $60 million due in 2018 Expected to close by October 2013 TRANSACTION HIGHLIGHTS 11 RECENT ANNOUNCEMENTS EQUITY OFFERINGS SIZE 28.6 million shares(1)(2) WEIGHTED AVERAGE SHARE PRICE $6.63 / share USE OF PROCEEDS To fund the Aggregate Acquisitions, fund drilling and development program (including the development of the acquired properties) and for other general corporate purposes, including working capital EXPECTED CLOSING August 2013 for PIPE, August 14th 2013 for public offering TERMS 180 day lock-up for PIPE, 90 day lock-up for public offering (1) Includes a total of 17.25 million shares of common stock from Triangle at the public offering price of $6.25 per share before underwriting discounts and commissions. Assumes underwriters exercise full over-allotment. (2) Includes 11.35 million shares through a private investment by TIAA Oil & Gas Investments.

OPERATIONAL OVERVIEW PRO FORMA TRIANGLE CORE AREA – MCKENZIE AND WILLIAMS COUNTIES 13 Source: Triangle Petroleum Corporation and North Dakota Industrial Commission, 2013. (1) Includes $1mm average RockPile Elimination. KEY HIGHLIGHTS 34 gross operated wells producing and 6 wells waiting on completion Recent downspacing test indicates potential for 8 – 12 locations per DSU Nearby operator undergoing 12-well spacing pilot per DSU Decreasing spud to total depth days; average of Targeting $9.0 - $9.5 million AFE costs(1) Efficiencies related to pad drilling Caliber reduces pad equipment on site TPLM Acreage TPLM Operated DSU Primary Acquisition Bolt-on Acquisitions Currently operating 3 full-time drilling rigs Plug and perf completions (McKenzie 100% ceramic, Williams 25% ceramic) CURRENT DEVELOPMENT 100% Ceramic Wells 25% Ceramic Wells Primary Acquisition Operated Wells SKEDSVOLD TRUST 32-29 Pad ROWE 1-12 Pad TRIANGLE 36-25 Pad LARSON 9-4 Pad GUSTAFSON 5-8 Pad STEEN 13-24 Pad DWYER 2-11 Pad FREDRICK JAMES 3-10 Pad GULLICKSON 36-25 Pad DWYER 35-26 Pad DWYER 21-16 Pad TRIANGLE 1-12 Pad LARSEN 21-16 Pad STATE 25-36 Pad HELLING 7-6 Pad FRITZ 32-29 Pad NYGAARD 28-33 Pad J GARVIN JACOBSON 17-20 Pad J GARVIN JACOBSON 8-5 Pad LARSEN 28-33 Pad

Aimed to lower cost per barrel, reduce reliance on third-party service providers and relieve infrastructure constraints Triangle has deployed ~$60 million of cash to its subsidiaries, representing only 12% of total capital invested(1) 14 INTEGRATED AND EFFICIENT DEVELOPMENT MODEL ROCKPILE ENERGY SERVICES OPERATIONAL OVERVIEW TPLM Acreage TPLM Operated DSU Primary Acquisition Bolt-on Acquisitions CLBR Phase I System Reduces Triangle’s cost of well completions completions Ensures timely access to completion services for Triangle’s E&P operations Captures significant third-party business, currently accounting for ~45% of frac jobs Completed 25 wells for TUSA since inception CALIBER MIDSTREAM PARTNERS Delivers freshwater for well completions, disposes of produced water and gathers produced natural gas/oil Provided freshwater for 13 TUSA wells since inception Crude oil and natural gas gathering operations fully operational during Q2 FY’14 Triangle has a 30% ownership stake, but can earn up to 50% if incentives are met KEY HIGHLIGHTS (1) Since new management turn-around beginning in 2010.

Share Price (as of August 9, 2013) $6.52 90-day % Change 15.0% Shares Outstanding 85.4 Market Capitalization $557 Total Debt (as of April 30, 2013) (1) $77 Total Cash (as of April 30, 2013) (2) $134 FINANCIAL OVERVIEW 16 Note: Dollars in U.S. millions, except per share data. (1) Does not include $120mm convertible note with a 5% cashless coupon per annum convertible into Triangle stock at $8.00 per share; covenant light. (2) As of April 30, 2013 pro forma for the Aggregate Acquisitions, public equity issuance, TIAA Oil and Gas Investments investment and borrowing base redetermination. (3) Redetermination effective July 30, 2013. CURRENT POSITION CURRENT POSITION LIQUIDITY PROFILE(2) FULLY DILUTED OWNERSHIP Pro Forma Total Cash (as of April 30, 2013) $134 Revolver Availability (as of April 30, 2013) $104 RPES Credit Facility Availability (as of April 30, 2013) $10 Total Liquidity $247 3% 97% Officers & Directors Public KEY HIGHLIGHTS Conservative leverage profile Quarterly credit facility redetermination increased borrowing base $55 million, from $110 million to $165 million(3) Commitment letter and term sheet for senior secured second-lien term loan facility of $60 million Ownership stake throughout company Revolver Availability does not include potential incremental value from the acquired 6.8 MMBoe of proved reserves from the Aggregate Acquisitions

66% 26% 4% 4% TUSA Drilling Program TUSA Land Spend Infrastructure RockPile FY2014 Revised Budget ($mm) Capital Expenses FY2014 Previous Capex Budget ($mm) Low Case High Case TUSA Drilling Program(1)(2) $192 $285 - $305 TUSA Land Spend $6 $110 - $120 Infrastructure(3) $15 $15 - $20 RockPile(4) $20 $20 - $20 Variance (~5%) $12 NA - NA Total $245 $430 - $465 FINANCIAL OVERVIEW 17 FY2014 CAPITAL BUDGET Note: Budget Detail and Budget Allocation based on Management estimates and assumptions as of August 6, 2013. All forward looking information subject to a number of assumptions and uncertainties. They are not a guarantee of future performance. BUDGET DETAIL BUDGET ALLOCATION ($430MM - $465MM) PROJECTED FY2014 DRILLING ACTIVITY Drilling program consists of 3 full-time operated rigs Spud ~ 34 gross operated wells Complete ~ 28 to 32 gross operated wells (1) TUSA 3-Rig Operated Drilling Program does not include the RockPile elimination that reduces capital expenditures at the TPC level. (2) Previous TUSA drilling program guidance allocated $165 million for operated drilling capital expenses and $27 million for non-operated drilling capital expenses. (3) TUSA Infrastructure does not include TPC equity infusions to Caliber. (4) Represents capital expenditures at RockPile including the addition of a 3rd Spread during mid FY 2015. Does not include any capital spent by TPC for RockPile.

1 5 6 5 8 1 4 5 10 6 10 10 18 - 10,000 20,000 30,000 40,000 0 5 10 15 20 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14 Horsepower Wells Completed Triangle Wells Third Party Wells Horsepower NA NA NA 0.9 1.0 1.1 $0 $1 $1 $2 $2 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14E Revenue ($mm) 7.5 10.4 16.8 21.1 30.0 33.0 $0 $10 $20 $30 $40 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14E Revenue ($mm) 8.1 23.9 25.2 26.9 43.0 47.0 $0 $15 $30 $45 $60 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14E Revenue ($mm) FINANCIAL OVERVIEW 18 HISTORICAL FINANCIALS AND OPERATIONAL UPDATE NET PRODUCTION VOLUMES (BOEPD)(1) TUSA HISTORICAL REVENUE RPES HISTORICAL REVENUE CLBR HISTORICAL REVENUE RPES GROSS WELLS COMPLETED (1) Sold production volumes. 1,120 1,389 2,098 2,714 3,900 4,100 0 1,500 3,000 4,500 6,000 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14E Net Production (Boepd)

5.2 7.5 10.4 16.8 21.1 8.1 23.9 25.2 26.9 5.2 7.5 10.4 16.8 21.1 2.6 10.7 7.4 13.1 0.9 0.9 $0.0 $10.0 $20.0 $30.0 $40.0 $50.0 $60.0 $70.0 Q1 FY'13 (A) Q2 FY'13 (A) Q3 FY'13 (A) Q4 FY'13 (A) Q1 FY'14 (A) Revenue ($mm) Triangle USA RockPile Stand Alone RockPile Consolidated Caliber TRIANGLE USA (E&P) ROCKPILE ENERGY SERVICES FINANCIAL OVERVIEW STAND ALONE BUSINESS SEGMENT FINANCIAL RESULTS AND GUIDANCE 19 CALIBER MIDSTREAM (Previous Guidance) Revenue1 ($ million) EBITDA2 ($ million) Q4 FY’14 Q4 FY’14 Q4 FY’14 * Caliber guidance net to Triangle’s 30% ownership stake. $46 - $50 ($34 - $37) $32 - $36 ($23 - $26) Q4 Ann. $184 - $200 ($136 - $148) $128 - $144 ($92 - $104) Fiscal 2014 $140 - $154 ($106 - $116) $96 - $110 ($70 - $80) Revenue1 ($ million) EBITDA2 ($ million) $58 - $64 $12 - $15 Q4 Ann. $232 - $256 $48 - $60 Fiscal 2014 $185 - $202 $42 - $49 Revenue1 ($ million) EBITDA2 ($ million) $2.6 - $3.1 $2.1 - $2.6 Q4 Ann. $10.4 - $12.4 $8.4 - $10.4 Fiscal 2014 $7.2 - $8.0 $5.2 - $5.8 *Sold production volumes. *EBITDA estimates do not include TPC (parent company) overhead. *Footnotes (1) and (2) describing segment information and non-GAAP measures are located at the back of the Appendix. STAND ALONE VS. CONSOLIDATED REVENUE GROWTH Stand Alone Consolidated Stand Alone Consolidated Stand Alone Consolidated Stand Alone Consolidated Stand Alone Consolidated

RISK MANAGEMENT 20 Triangle has improved its hedging program since April to reduce commodity price risk 3,350 Boepd hedged for the remainder of calendar year 2013, an increase of 123% since 4/30/13 2,723 Boepd hedged for calendar year 2014, an increase of 148% since 4/30/13 FINANCIAL OVERVIEW INCREASED HEDGED POSITION(1) CURRENT HEDGES As of July 31, 2013 Volumes (Boepd) Weighted Average Floor Price ($) Weighted Average Ceiling Price ($) Calendar Year 2013 3,350 $88.51 $104.11 Calendar Year 2014 2,723 83.38 99.99 Calendar Year 2015 500 80.00 94.50 1,500 1,100 3,350 2,723 500 0 1,000 2,000 3,000 4,000 2013 2014 2015 Production (Boepd) Q1 FY’14 Q2 FY’14 KEY HIGHLIGHTS (1) Reflects Calendar year.

1 5 6 5 8 1 4 5 10 6 10 10 18 - 10,000 20,000 30,000 40,000 0 3 6 9 12 15 18 Q2 FY'13 Q3 FY'13 Q4 FY'13 Q1 FY'14 Q2 FY'14 Horsepower Wells Completed Triangle Wells Third Party Wells Horsepower (1) APPENDIX 23 ROCKPILE ENERGY SERVICES Successfully completed approximately 500 stages during Q2 FY’14 Second spread now fully operational on a 24-hour basis Total capacity increased to 36,000 HP to facilitate third party work Backlog of 11 Triangle wells and six third party wells at beginning of Q3 FY’14 Performed first cased hole wireline job for third party in Q2 FY’14 First plug-and-perf third party job to take place by early Q3 FY’To date, completed third party jobs for five 3rd party operators Backlog of two wells for new third party operator to begin in Q3 FY’14 Reducing days from rig release to first frac EXPANDING CAPACITY AND CAPABILITIES GROSS WELLS COMPLETED AND BACKLOG 9 RockPile Energy Services, LLC is focused on providing “Best in Class” presure pumping and ancillary services in the Williston Basin CONSOLIDATED ELIMINATION Net Income Eliminated through Q1 FY’14 ($mm)1 RPES-Triangle Completed Wells Q1 FY’14 Avg. Net Income Eliminated per Triangle well ($mm) $17.0 17 $1.0 (1) Reference “Segment Reporting” tables in company financial statements and presentation appendix.

Salt water disposal facility operational Fresh water pipeline system operational Crude oil processing operational in Q2 FY 2014 Gas processing operational Q3 FY 2014 Since Jan. 2013, injected over 450,000 bbls of water into SWD Successfully delivered freshwater to 13 Triangle fracs since inception Ability to access oil pipelines and rail terminals provides transportation optionality for better price realizations OPERATIONS UPDATE APPENDIX 24 CALIBER MIDSTREAM Source: Triangle Petroleum Corporation and North Dakota Industrial Commission, 2013. MULTIPLE OPTIONS FOR OIL, INCLUDING PIPE AND RAIL GAS GOES TO MIDWEST MARKETS, INCLUDING CHICAGO STRATEGIC OBJECTIVE Get pipe into the ground and trucks off pads Offer Bakken operators gathering & processing capabilities at market or better rates Facilitate operational efficiencies for producers Provide gas and NGL production monetization option TIMING Caliber Midstream Partners, LP is focused on providing gathering, transportation and processing in the Williston Basin

APPENDIX MONTANA – STATION PROSPECT 25 Source: Triangle Petroleum Corporation and Montana Board of Oil and Gas, 2013. 16 DETAILS ~50,000 net acres; 65% operated Potential Drilling Inventory: 360 operated locations 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 TPLM Acreage TPLM Operated DSU Select Wells County

INCOME STATEMENT 26 Note: The consolidated income statement and other consolidated financial data for the three months ended April 30, 2012 and April 30, 2013 have been derived from unaudited interim consolidated financial data. APPENDIX ($US in thousands) FYE January 31, Three Months Ended April 30, 2013 2013 2012 2013 INCOME STATEMENT Revenue Oil and Natural Gas Sales $39,614 $5,172 $21,060 Pressure Pumping Services 20,747 - 13,120 Other 340 69 114 Total Revenue $60,701 $5,241 $34,294 Operating Expenses Oil and Gas Production $8,210 $845 $4,697 Pressure Pumping 16,605 186 11,186 Depletion, Depreciation and Amortization 15,081 2,173 7,473 Accretion 183 83 8 General and Administrative 28,791 5,290 6,504 Foreign Exchange Loss (Gain) 1 - - Total Operating Expenses $68,872 $8,577 $29,868 Total Other Income (Expense) ($6,314) $12 $785 Net Income (Loss) for the Period ($14,485) ($3,324) $5,211 STATEMENT OF CASH FLOWS Cash Provided by (Used in) Operating Activities $2,763 $2,455 $8,282 Cash Used in Investing Activities ($179,712) ($33,610) ($93,163) Cash Provided by (Used in) Financing Activities $141,250 ($1,393) $106,212

1Q FY2014 INTERSEGMENT TABLE 27 APPENDIX ($US in thousands) Corporate and Other(1) Exploration and Production Pressure Pumping Services Eliminations and Other Consolidated Total Revenues Oil and natural gas sales - 21,060 - - 21,060 Pressure-pumping services for third parties - - 15,030 (1,910) 13,120 Intersegment revenues - - 11,739 (11,739) - Other 276 - 114 (276) 114 Total revenues 276 21,060 26,883 (13,925) 34,294 Expenses Production taxes and other lease operating - 4,660 - - 4,660 Gathering, transportation and processing - 37 - - 37 Depletion, depreciation and amortization 123 6,618 1,239 (507) 7,473 Accretion of asset retirement obligations - 8 - - 8 Pressure-pumping - - 19,121 (7,935) 11,186 General and Administrative: Stock-based compensation 1,062 322 211 - 1,595 Other general and administrative 1,466 1,464 1,979 - 4,909 Total operating expenses 2,651 13,109 22,550 (8,442) 29,868 Income (loss) from operations (2,375) 7,951 4,333 (5,483) 4,426 Other income (expense) (415) 1,353 (153) - 785 Net income (loss) before income taxes (2,790) 9,304 4,180 (5,483) 5,211 (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.

APPENDIX SUM-OF-THE-PARTS ANALYSIS 28 Note: Does not include potential future incurred debt. 1. Based on Liberty – Kodiak M&A deal announced June 3, 2013 (42,000 acres, 5,700 Boepd at $660 million purchase price). 2. Does not include $120mm convertible note with a 5% cashless coupon per annum convertible into Triangle stock at $8.00 per share; covenant light. 3. As of April 30, 2013 pro forma for the Aggregate Acquisitions, public equity issuance, TIAA Oil and Gas Investments investment and borrowing base redetermination. 4. ROCKPILE ENERGY SERVICES Q4 FY 2014 estimated exit rate : 7,000 Boepd $80,000 per flowing barrel1 = $560 million Total core acreage: 45,000 $4,857 per acre1 = $219 million Station Prospect (MT) acres: 50,000 Cost-basis = $20 million CALIBER MIDSTREAM Q4 FY 2014 estimated annualized EBITDA of $9 million4 Peer group EV/EBITDA range of 9.2x – 19.8x 14.2x average TRIANGLE USA (E&P) Q4 FY 2014 estimated annualized EBITDA of $54 million4 Peer group EV/EBITDA range of 4.0x – 6.6x 5.4x average Implied Value of $799 million, or $9.35 per share Implied Value of $275 million, or $3.22 per share Implied Value of $120 million, or $1.40 per share Triangle Petroleum consolidated value of approximately $1,251 million, or $14.65 per share3 LESS: NET DEBT (AS OF APRIL 30, 2013) $77 million debt2 & $134 million cash3 = $57 million Value of approximately $0.67 per share See “ Use of Segment Information and Non-GAAP Measures” in the Appendix.

4.0x 4.1x 4.2x 4.2x 4.7x 4.7x 4.8x 5.1x 5.2x 5.4x 5.6x 5.6x 6.0x 6.0x 6.0x 6.2x 6.2x 6.3x 6.5x 6.6x .0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x 7.0x Low Case Average Case High Case Peer EV/EBITDA 4.0x 5.4x 6.6x RPES Valuation $216mm $290mm $354mm TPC per Share $2.53 $3.40 $4.15 APPENDIX 29 ROCKPILE ENERGY SERVICES IMPLIED VALUATION 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. Source: Bloomberg. 1. 2. Data as of 8/1/2013. 3. As of April 30, 2013 pro forma for the Aggregate Acquisitions, public equity issuance, TIAA Oil and Gas Investments investment and borrowing base redetermination. RockPile Energy Services Q4 FY 2014 estimated annualized EBITDA of approximately $54 million1 Peer group 2013E EV/EBITDA range of 4.0x to 6.6x with an average 5.4x Valuation implies $2.53 to $4.15 per share for Triangle Petroleum shareholders OILFIELD SERVICE PEER GROUP 2013(E) EV/EBITDA EV/EBITDA MULTIPLE VALUATION See “Use of Segment Information and Non-GAAP Measures” in the Appeidix.

Low Case Average Case High Case Peer EV/EBITDA 9.2x 14.2x 19.8x Caliber Valuation $285mm $441mm $615mm TPC Interest $85mm $132mm $185mm TPC per Share $1.00 $1.55 $2.16 APPENDIX 30 CALIBER MIDSTREAM IMPLIED VALUATION Peer Group: ACMP, AMID, APL, BKEP, CMLP, DPM, HEP, MMLP, MWE, NGLS, RGP, RRMS, SMLP, SXE, TCP, TLLP, TLP, WES, XTEX. Source: Bloomberg. 1. 2. Data as of 8/1/2013. Caliber Midstream Q4 FY 2014 estimated annualized EBITDA of $31 million1 ownership Peer group 2013E EV/EBITDA range of 9.2x to 19.8x with an average 14.2x Valuation implies $1.00 to $2.16 per share for Triangle Petroleum shareholders Potential additional value from Trigger Units and Cashless Warrants package MIDSTREAM MLP PEER GROUP 2013(E) EV/EBITDA EV/EBITDA MULTIPLE VALUATION 9.2 x 10.8 x 11.6 x 12.4 x 12.4 x 12.4 x 12.5 x 12.7 x 13.2 x 13.6 x 13.7x 14.2 x 14.7 x 15.0 x 15.1 x 16.0 x 16.7 x 18.4 x 19.8 x 19.8 x .0 x 5.0 x 10.0 x 15.0 x 20.0 x 25.0 x See “Use of Segment Information and Non-GAAP Measures” in the Appendix.

HEDGE PORTFOLIO 31 Hedge Expiry Date Days Remain Volume Strike Outright bullet puts 12/16/2013 181 500,000 $75.00 APPENDIX Hedge Period Start Period End Volume (Bopd) Days Remain Total Volumes Floor Avg. Ceiling Calendar-month-average swap zero cost collar 1/1/2013 12/31/2013 500 141 182,500 $85.00 $104.30 Calendar-month-average swap zero cost collar 1/1/2013 12/31/2013 500 141 182,500 $85.00 $100.50 Calendar-month-average swap zero cost collar 2/1/2013 12/31/2013 250 141 83,500 $90.00 $101.50 Calendar-month-average swap zero cost collar 2/1/2013 9/30/2013 250 49 60,500 $90.00 $102.50 Calendar-month-average swap zero cost collar 5/1/2013 12/31/2013 100 141 24,500 $87.50 $100.00 Calendar-month-average swap zero cost collar 7/1/2013 12/31/2013 500 141 92,000 $87.00 $101.75 Calendar-month-average swap zero cost collar 7/3/2013 12/31/2013 500 141 91,000 $90.00 $105.00 Calendar-month-average swap zero cost collar 7/1/2013 12/31/2013 250 141 46,000 $90.00 $107.85 Calendar-month-average swap zero cost collar 10/1/2013 12/31/2013 250 141 23,000 $90.00 $106.50 Calendar-month-average swap zero cost collar 7/1/2013 12/31/2013 250 141 46,000 $93.00 $107.50 Calendar-month-average swap zero cost collar 8/1/2013 12/31/2013 250 141 38,250 $94.00 $110.25 Calendar-month-average swap zero cost collar 1/1/2014 12/31/2014 500 365 182,500 $80.00 $101.20 Calendar-month-average swap zero cost collar 1/1/2014 12/31/2014 250 365 91,250 $85.00 $99.50 Calendar-month-average swap zero cost collar 1/1/2014 12/31/2014 250 365 91,250 $82.00 $98.00 Calendar-month-average swap zero cost collar 1/1/2014 3/31/2014 250 90 22,500 $85.00 $98.75 Calendar-month-average swap zero cost collar 4/1/2014 6/30/2014 150 91 13,650 $84.25 $100.00 Calendar-month-average swap zero cost collar 1/1/2014 12/31/2014 500 365 182,500 $83.00 $99.25 Calendar-month-average swap zero cost collar 1/1/2014 6/30/2014 500 181 90,500 $85.00 $100.80 Calendar-month-average swap zero cost collar 1/1/2014 6/30/2014 250 181 45,250 $87.00 $101.00 Calendar-month-average swap zero cost collar 1/1/2014 12/31/2014 250 365 91,250 $85.00 $100.00 Calendar-month-average swap zero cost collar 1/1/2014 12/31/2014 250 365 91,250 $85.00 $100.50 Calendar-month-average swap zero cost collar 7/1/2014 12/31/2014 500 184 92,000 $83.50 $100.00 Calendar-month-average swap zero cost collar 1/1/2015 12/31/2015 500 365 182,500 $80.00 $94.50

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 expense, 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 expense, income taxes, depreciation and amortization, which can vary significantly depending upon many factors. Most of Triangle’s consolidated interest expense relates to debt of the consolidated 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.