Triangle Petroleum (TPLMQ) 8-K Regulation FD Disclosure

Exhibit 99.1

CORPORATE PRESENTATION February 2015

10

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 13 19

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 completions services package including pressure pumping, wireline and pump down services Lowers total operating costs, reduces non-productive time, provides convenience Maintaining high utilization with 3rd parties through planned TUSA completion deferral period Growth oriented E&P company operating in the Williston Basin Current production of approximately 13,000 Boepd ~128,000 net acres with proved reserves of 57.1 MMBoe (1) ~86,000 net core acres predominantly in McKenzie / Williams Counties (59% operated; 77% HBP) FY2016 development contemplates 2 operated rigs on average and delaying completions until May or longer (2) Focused on protecting the balance sheet, maintaining adequate liquidity and return on capital Note: Triangle Petroleum Corporation’s Fiscal Year 2016 (“FY2016”) ends January 31, 2016. (1) Internal parent level reserve estimate as of October 31, 2014. TUSA reserves may differ slightly from parent level reserves due to intercompany eliminations, which may improve 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) Internal parent level reserve estimate as of October 31, 2014. TUSA reserves may differ slightly from parent level reserves due to intercompany eliminations, which may improve well economics at the parent level. (2) United States Geological Survey (USGS) published on April 30, 2013. (3) Pro forma for November 2014 TUSA and RockPile credit facility amendments, $32mm for share buybacks subsequent to Q3 FY’15, and $50mm Q4 FY’15 RockPile special dividend. ~128,000 net acres; 57.1 MMBoe proved reserves (89% liquids; 57% proved developed)(1) Contiguous acreage position prospective for the Bakken and Three Forks Formations, which are estimated to contain ~7.4 billion barrels of recoverable oil(2) Extensive low-risk development opportunities providing 10+ years of drilling inventory 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 $585mm in total lending facility commitments with $521mm in pro forma total liquidity(3) Conservative financial approach with focus on protecting cash flow through hedging ~4,800 Bopd hedged for FY2016 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 Q3 FY’15 production increased 80% year over year from Q3 FY’14 Proved reserves have increased 76% year over year(1) Increased scale during FY2015 through selective bolt-on acquisitions and trades in core area SUBSTANTIAL GROWTH IN OPERATED PRODUCTION AND RESERVES BUSINESS OVERVIEW

OPERATED VS. NON-OPERATED VOLUMES (% OF PRODUCTION) SIGNIFICANT OPERATED PRODUCTION AND RESERVES GROWTH 7 NET SOLD PRODUCTION VOLUMES (BOEPD) Note: FY2016 production guidance issued on February 5, 2015 Revised FY2015 and 2nd Half FY2015 production guidance issued on May 14, 2014 to 10,200-11,200 Boepd and 11,600-12,600 Boepd, respectively. Previous guidance (FY2015 daily production guidance 9,500–10,500 Boepd; 2nd Half FY2015 production guidance 10,500–11,500 Boepd) issued on January 21, 2014. Internal parent level reserve estimate as of October 31, 2014. Actual Production Completed first operated well in May 2012 RockPile completed first well August 2012 Caliber generates first revenues BUSINESS OVERVIEW FY2015 Avg. Daily Production Guidance 10,200 – 11,200 Boepd FY2016 Avg. Daily Production Guidance 11,000 – 13,000 Boepd PROVED RESERVES (MBOE) (1) Guidance Low Case Guidance High Case Avg. Rig Count PDP Reserves PUD Reserves Non-Operated Volumes Operated Volumes (2) (1)

OPERATIONAL OVERVIEW

OPERATIONAL OVERVIEW TRIANGLE USA CORE AREA – MCKENZIE AND WILLIAMS COUNTIES 9 (1) As of February 6, 2015. (2) Triangle’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. (3) Gross Operated Locations Remaining assumes six Bakken and four Three Forks wells per DSU. Supported by recent density tests near Triangle’s core acreage. RECENT DEVELOPMENTS 119 gross operated horizontal wells currently producing and 16 wells waiting on completion(1) Approximately 90% of operated wells hooked up to gas sales(1), as compared to 0% at the end of Q1 FY’14 All operated wells hooked up to Caliber are in compliance with amended NDIC oil handling guidelines released in December; anticipate being in compliance for all other wells before the rules take effect in April 2015 Ongoing downspacing tests indicate potential for 8 – 12+ locations per DSU Multiple operated DSUs containing middle Bakken wells spaced ~600’ apart Nearby operators undergoing 12 and 16 well density tests in a single DSU targeting the Middle Bakken and Lower Three Forks benches ASSET MAP: DOWNSPACING &THREE FORKS ACTIVITY DETAILS TPLM CORE Net Core Acreage ~86,000 Percent Operated (%)(2) 59% Percent Held By Production (%) 77% OPERATED DSUS(2) 66 TOTAL OPERATED LOCATIONS REMAINING(3) 545 TPLM Acreage TPLM Operated DSU Bakken & Three Forks Density Test Select Lower Three Forks Wells Select Tests OAS WLL WLL OAS OAS CLR CLR WLL OAS OAS WLL WLL 3) 7) 11) 4) 6) 9) 12) 10) 1) 2) 5) 8)

OPERATIONAL OVERVIEW DRILLING AND PRODUCTION PROFILE 10 (1) Spud to total depth drilled days excludes days when rig is batch drilling adjacent well. (2) Before RockPile and other eliminations. (3) Excludes produced volumes of natural gas and NGL’s not being sold. TUSA OPERATED WELLS COMPLETED (GROSS VS. NET) Q3 FY’15 SOLD VOLUMES PRODUCTION MIX(3) Targeting further well cost savings of 10-20% due to anticipated service cost declines Spud to TD averaged only 14 days in Q3 FY’15 Operational efficiencies reduced AFE’s on wells in 2HFY’15 to $9.5 million(2) Efficiencies related to pad drilling Caliber reduces pad equipment on site Reducing time drilling rig spends on location HIGHLIGHTS AVERAGE SPUD TO TOTAL DEPTH DRILLED DAYS(1)

Simultaneous operations – 1) drilling operations, 2) Caliber piping freshwater provisions, 3) RockPile batch completing two wells and 4) operational production facilities OPERATIONAL OVERVIEW ROCKPILE ENERGY SERVICES 11 (1) As of January 31, 2015 Integrated end-to-end completion services solution provides a distinct competitive advantage which helps to manage total operating costs and reduce downtime Fourth pressure pumping spread was deployed in September in a new basin operating for 3rd party clients Total RockPile distributions of $89 million paid during FY2015, which represents over 2.3x TPC’s capital investment Backlog of approximately 27 wells(1) waiting for completion including multiple wells with a Tier 1 producer new to RockPile as a customer TUSA’s deferred completion inventory should provide a significant backlog of work in Q2 and Q3 when there is less visibility into 3rd party activity levels Customer pricing pressure is being partially offset by passing on cost reductions from RockPile’s supply chain and optimizing corporate overhead 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

OPERATIONAL OVERVIEW CALIBER MIDSTREAM 12 (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 December 2014. Caliber Midstream Partners, LP is focused on providing gathering, transportation and processing in the Williston Basin Recent $34m equity infusion by FREIF will be used to fund newly 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; brings cash distributions to date to Triangle to ~$10mm Currently gathering an average of ~8.5 MMcfepd (2) in gas system and processing throughput of ~7.5 MMcfpd (2) through natural gas facility Phase I and II, including the Cartwright freshwater system, should be 100% operational by April 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 ~16,600 Bblpd (2) Central facility crude gathering averaging ~14,500 Bopd (2)

FINANCIAL OVERVIEW

FINANCIAL OVERVIEW CURRENT POSITION 14 (1) Basic shares outstanding as of January 2015, which reflects all of the 11.4mm shares repurchased in Q3 and Q4 FY’15. Does not include $134mm 5% convertible note, which is convertible into Triangle stock at $8.00 per share and potentially dilutive into approximately 16.7mm shares of Triangle common stock. (2) Pro forma Q3 FY’15 debt adjusted for $50mm Q4 FY’15 RockPile special dividend. (3) Pro forma for November 2014 TUSA and RockPile credit facility amendments, $32mm for share buybacks subsequent to Q3 FY’15, and $50mm Q4 FY’15 RockPile special dividend. (4) Common stock includes $134mm convertible note as of October 31, 2014. Potentially dilutive into approximately 16.7mm shares of Triangle common stock. (5) Calculated using outstanding management and board stock and options and unvested employee RSUs. Does not apply treasury stock method. PRO-FORMA LIQUIDITY ($MM) TOTAL CURRENT AND POTENTIAL DILUTED OWNERSHIP KEY HIGHLIGHTS Debt metrics remain conservative with TUSA debt to annualized Q3 FY’15 adjusted EBITDA of 2.1x(1) TUSA and RockPile credit facilities were both amended and upsized subsequent to the end of Q3 FY’15 Repurchased ~11.4mm shares of common stock (representing ~13% of basic shares outstanding) through December 10, 2014 at an average price of $6.72/sh (4) (5) (5) CURRENT POSITION Share Price (as of February 12, 2015) $5.62 90-day % Change -19.7% Basic Shares Outstanding (mm)(1) 75.2 Market Capitalization ($mm) $422 Debt ($mm) (2) $595 Total Cash $71 TUSA Credit Facility Availability $402 RPES Credit Facility Availability $48 Pro Forma Liquidity(3) $521 Management and Board: Common Stock and Options 7% Employee RSUs 3% Common Stock - Public 89% (1) (2) (3) (4) (5)

FINANCIAL OVERVIEW STAND-ALONE CAPITAL BUDGET FOR FY2016 (ENDING JANUARY 31, 2016) 15 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 be lower by eliminations. 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 2 operated rigs on average for FY2016 Spud ~25-27 gross operated wells Complete 27-29 gross operated wells Deferring completions until May 1, 2015 (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(2) 88% E&P Non-Op Drilling Program 3% RockPile 10% (1) (2) (3)

FINANCIAL OVERVIEW ADDITIONAL BUSINESS SEGMENT GUIDANCE 16 *Description of segment information and non-GAAP measures are located at the back of the Appendix FY2016 guidance issued on February 5, 2015. Reflects efforts to optimize internal cash G&A and shifting of some expenses to TPC from TUSA. Potential North Dakota tax incentives that could reduce oil extraction production tax rates based on low average WTI prices over different periods of time. 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 an additional spread FY2016. Excludes intercompany charges 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) Caliber EBITDA Anticipate minimal contribution of Caliber due to intracompany eliminations - FY2015 Effective Tax Rate (through Q3) 41-43% (98% deferred) TUSA-SPECIFIC FY2016 ITEMS(1): ROCKPILE-SPECIFIC FY2016 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 ~7% average production tax rate, dependent on North Dakota price-related oil tax incentives (3) $27-29mm in expected cash G&A expense ~10-15% decline from YE’15 levels(4) ~25%+ decline on per spread basis from YE’15(4) 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 — — — (1) (2) (3) (4)

RISK MANAGEMENT 17 Hedging program currently consists of zero cost collars to protect present and future cash flows Ability to hedge up to 85% of expected production over next 36 months FINANCIAL OVERVIEW HEDGE POSITION CURRENT HEDGES (BOPD) KEY HIGHLIGHTS *Note: As of October 31, 2014. Midpoint of FY2016 production guidance: 12,000 Boepd FY’15 Collars ~$101 Ceiling ~$87 Floor FY’16 Collars ~$98 Ceiling ~$87 Floor 6,000 4,500 3,000 1,500 FY2015 FY2016 5,900 4,400 Bopd 14000 12000 10000 8000 6000 4000 2000 0 Q4 FY’15 Q1 FY’16 Q2 FY’16 Q3 FY’16 Q4 FY’16 Costless Collar Volume FY’16 Production Guidance

APPENDIX RockPile: Vertical Integration Profile Caliber: Vertical Integration Profile Montana – Station Prospect Historical Financials Reconciliations and Segment Information a) b) c) d) e)

Control 100% of largest E&P cost center Dedicated high quality frac fleet and personnel Maintain greater control over completion schedules, work quality and production facilities planning Third-party completions boost consolidated revenues and earnings Realized capex reduction/well of $1.1mm over last 4 quarters (1) Potential distributions from subsidiary back to TPC provide additional capital allocation flexibility FY2014 - FY2015 STAND-ALONE FINANCIALS(2) ROCKPILE’S BENEFIT TO TRIANGLE APPENDIX ROCKPILE: VERTICAL INTEGRATION PROFILE 19 Calculated using total net income elimination divided by total gross operated completions over trailing 4 quarters ended FY3Q’15. Based on 2H FY’15 guidance issued on January 21, 2014. Reference “Segment Reporting and Non-GAAP Measures” tables in company financial statements and presentation appendix. Peer Group data sourced from Bloomberg as of February 12, 2015: 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. RPES valuation less $102m of pro forma debt divided by TPC fully diluted shares outstanding (75.2mm basic shares outstanding as of January 2015 plus 17.7mm diluted shares). ROCKPILE IMPLIED VALUATION Peer Average 2014E EV / EBITDA(3) 4.2x RPES 2H FY’15 Ann. EBITDA Midpoint(2) $86mm RPES Valuation $361mm TPC Fully Diluted Shares (mm) 92.9 Valuation Per TPC Share (4) $2.80 (1) (2) (3) (4)

Secured long term gas and crude oil gathering and takeaway capacity at market rates in the Williston Basin Potential to i) capture value for gas previously flared, ii) remove trucks from pads iii) increase realized prices by increasing optionality on delivery points and iv) contribute to TPC net income via equity investment Potential distributions from subsidiary back to TPC provide additional capital allocation flexibility APPENDIX CALIBER: VERTICAL INTEGRATION PROFILE 20 CALIBER’S BENEFIT TO TRIANGLE Peer Group data sourced from Bloomberg as of February 12, 2015: ACMP, AMID, APL, BKEP, CMLP, DPM, HEP, MMLP, MWE, NGLS, RGP, RRMS, SMLP, SXE, TCP, TLLP, TLP, WES, XTEX. See “Use of Segment Information and Non-GAAP Measures” in the Appendix. FY2015 guidance (based on Triangle’s 32% ownership stake through FY2015) adjusted to reflect current 28% ownership stake post-FREIF’s February 2015 equity infusion. Please reference Note 10 – Fair Value Measurements and Note 11 – Equity Investment in our FY2014 Form 10-K for additional details. Caliber implied valuation adjusted to reflect 48% net debt/cap ratio (based on peer group average per Bloomberg) divided by TPC fully diluted shares outstanding (75.2mm basic shares outstanding as of January 2015 plus 17.7mm diluted shares). CALIBER IMPLIED VALUATION Peer Average 2014E EV / EBITDA(1) 15.2x CLBR 2H FY’15 Ann. EBITDA Midpoint(2) $13mm CLBR Valuation $198mm TPC Basic Shares Outstanding (mm) 92.9 Valuation Per TPC Share (4) $1.10 IMPACT ON CONSOLIDATED FINANCIALS In FY2016, anticipate minimal gain from equity investment due to elimination, and no debt consolidation due to equity method accounting Fair value ownership of warrants reevaluated quarterly(3) (1) (2) (3) (4)

APPENDIX MONTANA – FOXTROT AND STATION PROSPECT 21 Source: Triangle Petroleum Corporation and Montana Board of Oil and Gas, 2014. DETAILS ~42,000 net acres; 67% operated Potential Drilling Inventory: 294 operated locations Seismic data has been licensed and is being interpreted for prospectivity KEY HIGHLIGHTS Industry activity continues in offsetting townships Ongoing exploration programs for Bakken and Three Forks New exploration program for conventional Red River initiated by peer operator Long-term leasehold allows a “wait-and-see” approach Asset provides substantial exploration upside for unconventional and conventional accumulations 16 TPLM Acreage TPLM Operated DSU Select Wells County Sagebrush Resources SBR1-36H Southwestern Energy Bedwell 1H Samson Resources Riva Ridge 33-56H MB Riva Ridge 0607-2H TF Whiting Petroleum Gronlle Farms 24-20 Whiting Petroleum Olson 21-28 Brigham Beck 15-101-H Whiting Petroleum French 21-26 Brigham Rogney 17-8-1-H Samson Oil & Gas Australia II Samson Oil & Gas Australia III Samson Oil & Gas Gretel II Continental Resources Abercrombie 1-10H Samson Oil & Gas Australia IV

APPENDIX Q3 FY’15 CONSOLIDATED INCOME STATEMENT 22 (a) Includes intercompany eliminations; reference Note 4 – Segment Reporting in the Q3 FY’15 Form 10-Q for additional details. (b) The effective tax rate for the three months ended October 31, 2014 is approximately 43%, which differs from the statutory income tax rate due to permanent book to tax differences. Income tax provision is primarily a non-cash expense, with a cash tax expense component of approximately $0.3 million. (c) Includes net interest expense add-back of $0.9 million in both Q3 FY’15 and Q3 FY’14 related to outstanding convertible notes. (d) See “Use of Segment Information and Non-GAAP Measures” and “Adjusted Net Income Reconciliation” in the Appendix. 2014 2013 Revenues Oil, natural gas and natural gas liquids sales 80,139 $ 55,477 $ Oilfield services 94,057 33,072 Total Revenues 174,196 88,549 Expenses Production taxes 8,637 6,161 Lease operating expenses 7,454 4,443 Gathering, transportation and processing 4,380 1,443 Oilfield services (a) 70,857 29,164 Depreciation and amortization 32,581 18,609 Accretion of asset retirement obligations 149 983 Corporate and Other stock-based compensation 1,588 1,981 E&P stock-based compensation 93 328 RockPile stock-based compensation 146 148 Corporate and Other cash G&A expenses 3,426 2,385 E&P cash G&A expenses 2,896 2,594 RockPile cash G&A expenses 7,310 3,150 System Conversion Costs 1,334 - Total operating expenses 140,851 71,389 Operating Income 33,345 17,160 Gain (loss) on equity investment derivatives 742 35,832 Gain (loss) from commodity derivative activities 19,822 2,123 Interest expense (9,463) (1,992) Income (loss) from equity investment 393 - Interest income 39 53 Other income (180) 15 Total other income 11,353 36,030 Net Income Before Income Taxes 44,698 53,190 Income tax provision (b) (19,300) (5,969) Net Income 25,398 $ 47,221 $ Net Income per Common Share Basic 0.30 $ 0.60 $ Diluted (c) 0.26 $ 0.50 $ Adjusted Net Income per Common Share (d) Basic 0.17 $ 0.16 $ Diluted (c) 0.15 $ 0.14 $ Weighted Average Common Shares Basic 85,242 79,059 Diluted 102,954 96,042 Three Months Ended October 31,

APPENDIX CONSOLIDATED ADJUSTED NET INCOME RECONCILIATION STAND-ALONE BUSINESS SEGMENT ADJUSTED EBITDA RECONCILIATION 23 (a) Tax impact is computed as pre tax-effected adjusting items multiplied by the Company's effective tax rate. (b) Includes interest expense add-back of $0.9 million net of income taxes and amounts capitalized in Q3 FY’15 related to outstanding convertible notes. (c) RockPile Adjusted EBITDA as per credit facility; does not include other non-RockPile OFS (d) Well connect fees are recorded as deferred revenue when completed and amortized over the expected term of the underlying production for revenue recognition purposes. The adjustment to EBITDA represents well connect fees billed, net of revenue recognized during the period. (e) Caliber Adjusted-EBITDA represents Triangle’s 32% ownership share of the partnership through FY2015. Q3 Fiscal 2015 Q3 Fiscal 2014 Net income attributable to common stockholders $ 25,398 $ 47,221 (Gain) loss on equity investment derivatives (742) (35,832) (Gain) loss on commodity derivatives (19,822) (2,123) Realized gain (loss) on commodity derivatives 688 (602) System Conversion Costs 1,334 - Tax impact (a) 8,006 4,333 Adjusted net income 14,862 $ 12,996 $ Adjusted net income per common Basic 0.17 $ 0.16 $ Diluted (b) 0.15 $ 0.14 $ Weighted average common shares Basic 85,242 79,059 Diluted 102,954 96,042 (a) Tax impact is computed as pre tax-effected adjusting items multiplied by the Company's effective tax rate. (b) Includes interest expense add-back of $0.9 million and $0.9 million net of income taxes and amounts capitalized in Q3 fiscal 2015 and Q3 fiscal 2014, respectively, related to outstanding convertible note. Q3 Fiscal 2015 Q2 Fiscal 2015 Net income before income taxes 26,715 $ 22,453 $ Depreciation and amortization 6,120 4,690 Stock-based compensation 146 127 Net interest expense 572 564 Other 1,112 930 Adjusted-EBITDA (c) 34,665 $ 28,764 $ Q3 Fiscal 2015 Q2 Fiscal 2015 Net income before income taxes 39,461 $ 28,865 $ Depreciation and amortization 27,998 23,439 Net interest expense 7,379 3,351 Stock-based compensation 93 344 Accretion of asset retirement obligations 149 41 System Conversion Costs 1,334 - (Gain) loss on commodity derivatives (19,822) 921 Realized gain (loss) on commodity derivatives 688 (2,954) Adjusted-EBITDA 57,280 $ 54,008 $ Q3 Fiscal 2015 Q2 Fiscal 2015 Net income before income taxes $1,113 $881 Depreciation and amortization 894 510 Warrant amortization expense 210 171 Net interest expense 251 114 Net well connect fees billed(d) 391 588 Adjusted-EBITDA(e) $ 2,858 $ 2,264

APPENDIX Q3 FY’15 INTERSEGMENT TABLE 24 (a) RockPile's Pressure Pumping and Other Services includes a small amount of non-pressure pumping related intersegment oilfield services revenue. (b) Corporate and Other includes our 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 our results from our investment in Caliber, including any changes in the fair value of our equity investment derivatives. Other than our investment in Caliber, these subsidiaries have limited activity. (b) $16.7 million RockPile, Caliber, and other services consolidated elimination results in a $16.7 million reduction in oil and natural gas property expenditures. *Reference Note 4 – Segment Reporting in our Q3 FY’15 Form 10-Q for additional details. Exploration and Production RockPile's Pressure Pumping and Other Services (a) Corporate and Other (b) Eliminations and Other Consolidated Total Revenues Oil, natural gas and natural gas liquids sales $ 80,139 $ - $ - $ - $ 80,139 Oilfield services for third parties - 96,810 - (2,753) 94,057 Intersegment revenues - 46,941 - (46,941) - Total revenues 80,139 143,751 - (49,694) 174,196 Expenses Prod. taxes, LOE, and other expenses 20,620 - - - 20,620 Depreciation and amortization 27,998 6,249 125 (1,791) 32,581 Cost of oilfield services - 102,762 - (31,905) 70,857 General and administrative 4,323 7,456 5,014 - 16,793 Total operating expenses 52,941 116,467 5,139 (33,696) 140,851 Income (loss) from operations 27,198 27,284 (5,139) (15,998) 33,345 Other income (expense), net 12,263 (695) 443 (658) 11,353 Net income (loss) before income taxes $ 39,461 $ 26,589 $ (4,696) $ (16,656) (c) $ 44,698

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