Corporate Presentation September 2017 1 Corporate Snapshot TSX

Corporate Presentation September 2017 1

Corporate Snapshot TSX: TOG Market Summary Basic Shares Outstanding 187 mm Average Daily Volume 1 1. 9 mm shares Market Cap / Enterprise Value $1. 1 bln / $1. 4 bln Monthly Dividend $0. 02 per share ($0. 24 annualized) CPPIB / Insider Ownership 25% CPPIB / 4% insiders 2017 e Production Average: 20, 600 boe/d Exit: 21, 200 boe/d (88% liquids) Corporate Summary P+P Reserves 2 101. 6 mmboe Tax Pools $1. 6 bln Q 2 2017 Exit Net Debt $242 mm Bank Line $400 mm 1) 2) Dividend Monthly: $0. 02 / share Annualized: $0. 24 / share (drawn ~$196 mm at Q 2 ‘ 17 exit) Average daily trading volume from Jan 2015 through to the end of 2016; volumes are a composite of all exchanges in Canada Based on independent reserves evaluation prepared by Sproule & Associates Limited dated March 1, 2017 and effective December 31, 2016; plus Q 1 net acquisitions 2

Proven Strategy Competitive advantage Per share growth through organic development & strategic acquisitions Capital efficiencies Integrated Approach Sustainability Operational Expertise Cash costs Financial Flexibility Long-term approach to business model Balance sheet strength Asset quality is priority CPPIB relationship Payout ratio Consistent Approach Throughout the Cycle 3

Strategic Priorities Free Cash Flow Managing a Cyclical Business Dividend Balance sheet strength is key Organic Growth Maintain and expand growth platform using free cash flow h. F Asset Sustainability Ca s Manage decline profile for sustainability low Focus on asset quality / capital efficiencies Balance Sheet Strength Dividend is a capital allocation decision Focus On Asset Quality and Financial Flexibility 4

Balanced Light Oil Asset Base Alberta Saskatchewan Southeast Saskatchewan Conventional • Low decline, high netback, light oil assets • >400 net undrilled conventional locations • >94% liquids • Significant management experience in area Cardium Trend Edmonton Southeast Saskatchewan Torquay/Three Forks SE SK Conventional / Torquay / Three Forks • Significant exposure; >150 net locations • Robust industry activity • 2017 capital program focused on development projects & further delineation • >290 net undrilled locations for ongoing organic growth Calgary Cardium • Operated production base allows for control of development pace and growth plan • Further potential upside through reduced well spacing and EOR High Quality Development Assets 5

SASKATCHEWAN Southeast Saskatchewan Cash Flow Generation SE SK l/ Conventiona Torquay / Three Forks Light Oil • High Netbacks • Low Decline 6

SE Saskatchewan Conventional Cash Flow Engine Large Oil-in-Place 1 Conventional Pools ~5 to 100+ mmbbls Depth 1, 000 – 2, 000 m Oil Quality 30 -40 API Well Spacing 75 – 150 m inter-well Undrilled Locations 2 >400 net Booked Locations 210 net 2017 Budget 38 (31. 5 net) wells 1) Consisting of discovered and undiscovered PIIP internally estimated by TORC 2) Internal estimates High Netbacks & Low Decline Generate Significant Free Cash Flow 7

SE Saskatchewan Conventional SE Saskatchewan - Conventional & Frac’d Midale Ratcliffe Midale Frobishe r Alida Tilsto n § Conventional Mississippian: Stacked, discrete flow units, excellent rock properties § § Unconventional Midale: Low permeability, large OIP, layered § § Frobisher: Open hole, 1/2 mile hz Midale: 30 stage liner, 5 tonnes/stage, frac’d with water at low rates - 1 mile hz Trap: subcrop, shoals and buried hills Multiple Plays – Evolving Opportunities 8

SE Saskatchewan Conventional Cash Flow Engine 300 2014 Economic Parameters 1 2015 DCE&T $0. 9 mm IP 365 46 bopd • 51 boepd Reserves 50 mbbls • 55 mboe Production Adds $17, 650 per boe/d 160 Reserve Adds $16. 35 per boe 140 NPV 10 $0. 9 120 P/I 1. 0 ROR 120% 60 Payout 1. 0 yrs 40 Operating Netback 2 ~$30 / boe 20 Recycle Ratio 1. 8 X 280 Production Rate, 30 Day Avg (BOPD) 260 2016 240 2017 220 50 mbbl Curve 200 180 100 80 0 1 2 3 4 5 6 Months 7 8 9 10 11 12 1) Sproule December 31, 2016 prices 2) $65 Edm Lt Robust Economics and Significant Undrilled Inventory 9

SE Saskatchewan Conventional Wells Drilled vs Inventory 400 § Inventory has been expanded through high quality acquisitions 350 Well Count 300 250 § Extensive experience in area drives prospect generation 200 150 100 [VALUE] [VAL UE] '14 '15 '16 50 0 Wells Drilled [VAL UE] § Tuck-in deals have historically replaced current year drill program '17 Identified Inventory Depth and Quality of Inventory 10

Torquay / Three Forks Light Oil Resource Play Large Oil-in-Place 1 >5 mmbbls / section Land ~50 net light oil sections Depth 2100 – 2300 m Oil Quality 40° API sweet Well Spacing 4 wells / section Undrilled Locations 2 >150 net Booked Locations 32 net 2017 Budget 15 (12. 5 net) wells 1) Consisting of discovered and undiscovered PIIP internally estimated by TORC 2) Internal estimates Improving Costs & Completion Techniques Drive Attractive Economics 11

Torquay / Three Forks Units 46 Units 13 § Trap: combination stratigraphic-structural, proximal to Bakken oil generation window § 30 stage liner, 40 tonnes/stage, frac’d with slickwater – 1 mile hz § Units 1 - 6: Cyclical deposition, overall deepening, widespread shallow marine § Frac height contained to units 4 -6, increased risk of water from lower units Continued Evolution → Well Placement + Frac Design 12

Torquay / Three Forks Light Oil Resource Play 350 300 Production Rate, 30 Day Avg (BOPD) Economic Parameters 1 175 mbbl Curve Average 250 200 150 100 50 0 1 2 3 4 5 6 Months 7 8 9 10 11 12 DCE&T $2. 8 mm IP 365 119 bopd Reserves 175 mbbls Production Adds $23, 530 per boe/d Reserve Adds $16. 00 per boe NPV 10 $3. 2 P/I 1. 1 ROR 71% Payout 1. 5 yrs Operating Netback 2 ~$40 / boe Recycle Ratio 2. 5 X 1) Sproule December 31, 2016 prices 2) $65 Edm Lt 2017 Capital Budget Focused on Development and Further Delineation 13

Torquay / Three Forks Depth and Quality of Inventory Torquay/Three Forks Wells Drilled vs Inventory § Initial footprint was acquired through 2013 strategic acquisition 160 140 § TORC exploration program along with industry activity has proved up concept Well Count 120 100 80 § Further delineation drilling in 2016 has evolved play to development focus and added quality inventory 60 40 20 0 [VALUE] '14 [VALUE] [VAL UE] '15 '16 '17 Wells Drilled Identified Inventory Idea Generation → Technical Focus → Development Project 14

ALBERTA Core Asset t n e m p lo e Dev Cardium Light Oil Low-Risk Development Inventory 15

Cardium Trend Development Drilling Large Oil-in-Place 1 ~5 mmbbls / section Land ~95 net light oil sections Depth 1600 – 2000 m Oil Quality 40° API sweet Well Spacing 4 wells / section Undrilled Locations 2 >290 net Booked Locations 88 net 2017 Budget 12 (10. 7 net) wells 1) Consisting of discovered and undiscovered PIIP internally estimated by TORC 2) Internal estimates Significant Inventory for Continued Organic Growth 16

Cardium Trend West Central Alberta - Cardium § Regional shoreface, stratigraphic trap, low permeability halo and discrete pools § Land wellbore in upper porosity and geosteer in best quality rock § 25 stage liner, 20 tonnes/stage, frac’d with slickwater - 1 mile hz Geosteering Optimizes Well Results 17

Cardium Trend Development Drilling 350 300 Production Rate, 30 Day Avg (BOEPD) Economic Parameters 1 250 mboe Curve Average 250 200 150 100 50 0 1 2 3 4 5 6 Months 7 8 9 10 11 12 DCE&T $2. 7 mm IP 365 85 bopd • 135 boepd Reserves 156 mbbls • 250 mboe Production Adds $20, 000 per boe/d Reserve Adds $10. 80 per boe NPV 10 $3. 1 P/I 1. 1 ROR 61% Payout 1. 6 yrs Operating Netback 2 ~$28 / boe Recycle Ratio 2. 6 X 1) Sproule December 31, 2016 prices 2) $65 Edm Lt Strong Economics and Significant Undrilled Inventory 18

Cardium Trend Depth and Quality of Inventory Cardium Wells Drilled vs Inventory 300 § Maintained inventory through tuck-in acquisitions replacing annual drill program 250 Well Count 200 150 § Sustainability and repeatability are supported by inventory replacement 100 50 [VAL UE] [VALUE] '14 '15 0 Wells Drilled [V AL UE ] '16 [VALUE] '17 Identified Inventory Supports Long-Term Free Cash Flow 19

Supporting Sustainability Asset Quality with Financial Flexibility 20

Sustainability Analysis Sustainability Highlights Sustainability Run Rate Production § Run rate production of 20, 800 boe/d (88% oil & NGLs) o Corporate decline of ~23% Decline Rate Annual Production Decline ~$27 mm required for cash dividend Annual Dividend per Share Annual Dividends § 100% CPPIB Share Dividend participation 23. 0 % 4, 784 boe/d Dividend Payout Shares Outstanding o 20, 800 boe/d Share Dividend Participation Less: Share Dividend Proceeds Net Dividends 187 mm $0. 24 / share $45 mm 40 % $18 mm $27 mm Continued Focus on the Sustainability of the Business Model 21

Sustainability Analysis Commodity Sensitivity Run Rate: 20, 800 boe/d WTI (US$) $40. 00 $45. 00 $50. 00 $55. 00 $60. 00 FX (US$/C$) $0. 75 $0. 77 $0. 79 WTI (C$/bbl) $53. 33 $60. 00 $64. 94 $69. 62 $75. 95 Edm Lt vs C$ WTI Differential ($/bbl) -$4. 50 Edm Lt (C$/bbl) $48. 83 $55. 50 $60. 44 $65. 12 $71. 45 Capital Efficiency ($/boe/d) $24, 000 $24, 000 Run Rate Cash Flow ($mm) $129 $165 $192 $218 $253 Maintenance Capital ($mm) $115 $115 $27 $27 $27 $142 $142 $15 $15 $157 $157 Cash Surplus ($mm) -$28 $8 $35 $61 $96 Total Payout Ratio 121% 95% 82% 72% 62% 2. 0 x 1. 6 x 1. 3 x 1. 2 x 1. 0 x Dividend ($mm) Capex Plus Dividend ($mm) Growth Capital ($mm) Total Capital + Dividend ($mm) Net Debt / Cash Flow (net debt of ~$242 mm) 22

Balance Sheet Strength $242 mm net debt $450 $400 $350 $300 $400 mm bank facility $196 mm drawn $mm $250 $200 $150 $100 $50 $0 Q 4 '14 >50% undrawn bank line Q 4 '15 Drawn Q 4 '16 Q 2 '17 Facility Size Maintain Financial Flexibility by Managing Within Cash Flow 23

Dividend + Disciplined Growth Checklist Sustainability of the business model driven by: ü Decline rate ~23% ü Operating netback 1 ~$30 ü Capital efficiency: all-in IP 365 $24, 000 per boe/d (2017 budget) ü Strong balance sheet $242 mm net debt $196 mm drawn at Q 2 exit $400 mm bank facility ü Development drilling inventory 2 >800 undrilled locations ü Hedging strategy Up to 60% of volumes ü Access to capital CPPIB provides differentiated access to capital 1) $65 Edm Lt 2) Internal estimates Sustainability + Repeatability Supported Through Multiple Facets 24

Investment Summary ü Low decline, high netback production base Focused, light oil asset base ü Sustainable yield All-in payout ratio targeted below 100% ü Strategic relationship Opportunity for CPPIB to support future growth and / or M&A ü Strong balance sheet Well capitalized to be opportunistic ü Experienced management Significant management experience ü Unbooked development inventory Large inventory of low-risk, unbooked development locations ü Upside Potential future upside with exposure to earlier-stage emerging light oil opportunities Well Positioned for Disciplined Growth 25

Corporate Information Management Banks Brett Herman Bank of Montreal The Toronto‐Dominion Bank Canadian Imperial Bank of Commerce Royal Bank of Canada National Bank of Canada The Bank of Nova Scotia Alberta Treasury Branches Caisse Centrale Desjardins President & Chief Executive Officer Jason Zabinsky Vice President, Finance & Chief Financial Officer Sandy Brown Vice President, Geosciences Shane Manchester Vice President, Operations Marvin Tang Controller Jeremy Wallis Vice President, Land Haywood Securities – Christopher Jones Transfer Agent John Brussa Computershare Limited Raymond Chan Corporate Office Scott Lawrence Dale Shwed Desjardins Capital Markets ‐ Kristopher Auditor Directors David Johnson Clarus Securities ‐ Daniel Choi GMP First. Energy ‐ Stacy Mc. Donald Shannon Gangl Brett Herman Cormark Securities – Garett Ursu Sproule Associates Limited Legal Counsel Bruce Chernoff Canaccord Genuity ‐ Anthony Petrucci Zack KPMG LLP Corporate Secretary BMO Capital Markets ‐ Ray Kwan Independent Reserve Engineer Mike Wihak Vice President, Production Analyst Coverage Burnet, Duckworth & Palmer LLP Eighth Avenue Place Suite 1800, 525 – 8 th Avenue SW Calgary, AB T 2 P 1 G 1 T: (403) 930‐ 4120 | F: (403) 930‐ 4159 www. torcoil. com Macquarie Capital ‐ Brian Bagnell National Bank Financial ‐ Dan Payne Paradigm Capital ‐ Ken Lin Peters & Co ‐ Dale Lewko RBC Capital Markets – Shailender Randhawa Scotia Capital ‐ Patrick Bryden TD Securities ‐ Juan Jarrah 26

Appendix 27

2017 Capital Program Conservative $130 mm program Capital Spending • Flexibility to adjust spending levels and asset allocation through the year $90 • 5 -7% growth maintains current 23% decline rate $80 • Focus on sustainability and balance sheet protection $70 Modest cost increases budgeted to account for inflation caused by elevated industry activity • $24, 000/boepd capital efficiency • Focus on operational and service cost efficiencies 2017 E Production Guidance: • >20, 600 boe/d average & 21, 200 exit (87% light oil & liquids) $mm $60 $50 ~$80 mm in 2 nd half +60% ~$50 mm in 1 st half $40 $30 $20 $10 $0 1 H 2 H Continued Focus on the Sustainability of the Business Model 28

Wells Drilled Corporately Depth and Quality of Inventory Depth of Inventory Across All Core Areas Total Wells Drilled vs Inventory 900 25% 800 § Each location thoroughly scrutinized through detailed evaluation by the technical team 20% 700 § Focus on quality of inventory not quantity Well Count 600 15% 500 400 300 10% [VALUE] 200 0 [VALUE] '14 Wells Drilled [VA LUE ] '15 [VALUE] 0% '16 Identified Inventory '17 o robust economics o expand scope of inventory 5% 100 § Drill program focused on high quality prospects that provide: o payout matters - not just BOEs § Acquisitions and organically generated locations need to enhance inventory to truly be additive % of Inv Growing High Quality Inventory Supports Repeatability of Business Model 29

Modeling Assumptions Production: 2017 Average: ~20, 600 boepd (88% oil & liquids) 2017 Exit: ~21, 200 boepd (88% oil & liquids) Per Share: $0. 24 per share Annual Dividend: Gross: 2017 Cash Flow Assumptions: Sustainability ~$45 mm Net: ~$27 mm (net of 40% SDP participation) Corporate Diff to Edm Lt Oil: ~$5. 50 / bbl Average Royalty: ~17 -18. 0% OPEX & Transportation: ~$13. 00 / boe G&A: ~$1. 40 / boe Capital efficiency: $24, 000(1)/ boepd (IP 365) - 2017 Budget Corporate decline: ~23% +/- $1. 00 WTI: $7. 0 mm Sensitivity +/- $0. 10 AECO: $0. 4 mm +/- $0. 01 FX: $4. 9 mm (1) Discount to previous capital efficiencies due to current commodity price environment 30

Hedging Current Hedge Summary (C$/Bbl) Volume (Bbl/d) Type Low High Index Jan 1, 2017 - Dec 31, 2017 250 Collar 55. 00 77. 50 C$WTI Jan 1, 2017 - Dec 31, 2017 250 Collar 55. 00 80. 25 C$WTI Jan 1, 2017 - Dec 31, 2017 250 Collar 55. 00 83. 10 C$WTI Jan 1, 2017 - Dec 31, 2017 250 Collar 55. 00 84. 00 C$WTI Jan 1, 2017 - Dec 31, 2017 250 Collar 55. 00 82. 00 C$WTI Jan 1, 2017 - Dec 31, 2017 250 Collar 55. 00 85. 75 C$WTI Jan 1, 2017 - Dec 31, 2017 250 Collar 55. 00 90. 75 C$WTI 31

Significant Cornerstone Investment from CPPIB Strategic Relationship: Governance: About CPPIB: • CPPIB’s Relationship Investments group provides long-term strategic capital to select companies CPPIB believes are positioned to be leaders in their respective industries • Ownership of ~ 25% • Share Dividend enrollment for 100% of accrued dividends • CPPIB entitled to fund its pro rata share of any future equity raises to support growth • Entitled to two Board nominees if ownership > 20% • Scott Lawrence; VP - Head of Relationship Investments at CPPIB; Mr. Lawrence was previously on the Board of Progress Energy Resources Corp. prior to its sale to PETRONAS • Professional investment management organization with a purpose to invest the assets of the Canada Pension Plan in a way that maximizes returns without undue risk of loss • Assets under management of ~ $270 billion • CPPIB has significant investments in private and public companies in the Canadian Oil & Gas Industry 32

TORC Advisory Forward‐Looking Statements: This presentation contains forward‐looking statements and forward‐looking information (collectively "forward‐looking information") within the meaning of applicable securities laws relating to plans of TORC Oil & Gas Ltd. ("TORC" or the "Company"), aspects of TORC's 2016 capital budget, strategic objectives and focus, anticipated future operational plans and activity, financial, operating and production results, including matters related to production, cash flow, netbacks, decline rates, net debt, capital expenditure program, commodity pricing, dividends, targeted growth, tax pools and drilling and development plans and the timing thereof. In addition, and without limiting the generality of the foregoing, this presentation contains forward‐looking information regarding: the Company's strategy, focus and objectives; the focus and allocation of TORC's 2017 capital budget, including expected expenditures and operations, the Company's budgeting philosophy and certain cost estimates; management's view of the characteristics and quality of TORC's assets, including the high quality, low‐risk, light oil, high netback, development nature of TORC's properties, quantities of resources, the magnitude of opportunities available to the Company on its assets, the production profile and decline rates on the Company's assets, payouts, the Company's exposure to large scale resource plays, the quality of commodities expected from the Company's properties, the repeatability of operations, drilling and completion optimization opportunities, the potential applicability of technologies to the Company's properties and the well spacing and drilling inventory available to the Company; economic parameters and assumptions employed by management; matters pertaining to type curves and capital efficiencies; the Company's ability to achieve controlled and sustainable growth; matters pertaining to the Company's efforts to drive down costs and the assumptions related thereto and the expected results thereof; matters pertaining to CPPIB, including the Company's belief that it has differentiated access to capital and CPPIB's continued participation in the share dividend program; matters pertaining to commodity price sensitivity; the Company's 2016 daily run rate, average and exit production guidance; matters pertaining to tax pools; matters pertaining to sustainability and other matters ancillary or incidental to the foregoing. Forward‐looking information typically uses words such as "anticipate", "believe", "project", "target", "guidance", "expect", "goal", "plan”, "intend" or similar words suggesting future outcomes, statements that actions, events or conditions "may", "would", "could" or "will" be taken or occur in the future. The forward‐looking information is based on certain key expectations and assumptions made by TORC's management, including expectations and assumptions concerning prevailing commodity prices, exchange rates, interest rates, applicable royalty rates and tax laws; capital efficiencies; decline rates; future production rates and estimates of operating costs; performance of existing and future wells; reserve and resource volumes; anticipated timing and results of capital expenditures; the success obtained in drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the state of the economy and the exploration and production business; results of operations; performance; business prospects and opportunities; the availability and cost of financing, labour and services; the impact of increasing competition; ability to market oil and natural gas successfully and TORC's ability to access capital. Statements relating to "reserves" or "resources" are also deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves or resources, as the case may be, described exist in the quantities predicted or estimated and that the reserves or resources, as the case may be, can be profitably produced in the future. Although the Company believes that the expectations and assumptions on which such forward‐looking information is based are reasonable, undue reliance should not be placed on the forward‐looking information because TORC can give no assurance that they will prove to be correct. Since forward‐looking information addresses future events and conditions, by its very nature they involve inherent risks and uncertainties. The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, the forward‐looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward‐looking information will transpire or occur, or if any of them do so, what benefits that the Company will derive there from. Management has included the above summary of assumptions and risks related to forward‐looking information provided in this presentation in order to provide security holders with a more complete perspective on TORC's future operations and such information may not be appropriate for other purposes. Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www. sedar. com). These forward‐looking statements are made as of the date of this presentation and TORC disclaims any intent or obligation to update publicly any forward‐looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. The information contained in this presentation does not purport to be all‐inclusive or to contain all information that prospective investors may require. Prospective investors are encouraged to conduct their own analysis and reviews of the Company and of the information contained in this presentation. Without limitation, prospective investors should consider the advice of their financial, legal, accounting, tax and other advisors and such other factors they consider appropriate in investigating and analyzing the Company. Dividends: The payment and the amount of dividends declared in any month will be subject to the discretion of the board of directors and will depend on the board of director's assessment of TORC's outlook for growth, capital expenditure requirements, funds from operations, potential acquisition opportunities, debt position and other conditions that the board of directors may consider relevant at such future time. The amount of future cash dividends, if any, may also vary depending on a variety of factors, including fluctuations in commodity prices and differentials, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens and foreign exchange rates. Financial Outlooks: The estimates of net debt and anticipated future cash flows contained in this presentation may be considered financial outlooks within the meaning of applicable securities laws. These financial outlooks have been prepared by management of TORC to provide an outlook respecting aspects of TORC’s future financial position based on management's expectations and assumptions as to a number of factors, including commodity pricing, production, operating expenses and royalties. Readers are cautioned that this information may not be appropriate for any other purpose. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the financial outlooks or assurance that such results will be achieved. The actual results of TORC will likely vary from the amounts set forth in the financial outlooks and such variation may be material. 33

TORC Advisory Non‐GAAP Measures: In this presentation, management uses certain key performance indicators and industry benchmarks such as "net debt", "profit to investment ratio", "operating netbacks" ("Netbacks"), "cash flow“ and "free cash flow", which do not have a standardized meaning prescribed by Canadian generally accepted accounting principles ("GAAP") and therefore may not be comparable with the calculation of similar measures by other companies. TORC uses these metrics to analyze financial and operating performance. TORC feels these benchmarks are key measures of profitability and overall sustainability for TORC. These terms are commonly used in the oil and gas industry. These terms are not intended to represent or be a proxy for operating profits nor should they be viewed as an alternative to cash flow provided by operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP. Cash flows are calculated as cash flows from operating activities less changes in non‐cash working capital. Netbacks are determined by deducting royalties, production expenses and transportation and selling expenses from oil and gas revenue. Where discussed herein "NPV 10%" represents the net present value (net of capex) of net income discounted at 10%, with net income reflecting the indicated oil, liquids and natural gas prices and IP rate, less internal estimates of operating costs and royalties. It should not be assumed that the future net revenues estimated by TORC's independent resource evaluators represent the fair market value of the reserves, nor should it be assumed that TORC's internally estimated value of its undeveloped land holdings represent the fair market value of the lands. Reserves Information: All information in respect of the crude oil, natural gas liquids and natural gas reserves in this presentation is based upon the independent engineering report dated March 3, 2017 and effective December 31, 2016 prepared by Sproule & Associates evaluating the oil, NGL and natural gas reserves attributable to all of our properties which was prepared in accordance with NI 51‐ 101 and the COGE Handbook. Initial Production Rate, Type Curves and Capital Efficiencies: Any references in this presentation to initial production rates, production type curves and capital efficiencies are useful in confirming and assessing the potential for the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter and are not necessarily indicative of long‐term performance or long term economics of the relevant well or fields or of ultimate recovery of hydrocarbons. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production or performance for TORC. Certain Reserves or Resources Not Classified as Recoverable : This presentation contains projections of production growth based on drilling opportunities identified by management of TORC. Certain of the drilling opportunities identified have no associated reserves or resources which can presently be classified as recoverable. As such, the initial rates of production and reserves per well identified herein do not represent estimates of future production or reserves associated with the drilling opportunities. The initial rates of production, reserves per well and the capital costs associated with drilling and recompletion identified herein are based on TORC's historical results and analogous public information received from other producers using similar technologies as TORC intends to use in the same or similar areas and formations. The initial rates of production, production type curves, capital efficiencies, reserves per well and capital costs associated with the wells have been provided herein to give an indication of management's assumptions used for budgeting, planning and forecasting purposes. The initial rates of production, production type curves, capital efficiencies, reserves and capital costs will most likely be different than projected. Barrels of Oil Equivalent: The term "BOE" or barrels of oil equivalent may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Additionally, given that the value ratio based on the current price of crude oil, as compared to natural gas, is significantly different from the energy equivalency of 6: 1; utilizing a conversion ratio of 6: 1 may be misleading as an indication of value. Analogous Information: Certain information in this presentation may constitute "analogous information" as defined in NI 51‐ 101, including, but not limited to, information relating to the areas in geographical proximity to lands held or to be held by TORC believes this information is relevant as it helps to define the reservoir characteristics in which TORC may hold an interest. TORC is unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor. Such information is not an estimate of the reserves or resources attributable to lands held or to be held by TORC and there is no certainty that the reservoir data and economics information for the lands held or to be held by TORC will be similar to the information presented herein. The reader is cautioned that the data relied upon by TORC may be in error and/or may not be analogous to such lands to be held by TORC. Finding and Development Costs: NI 51‐ 101 specifies how finding and development costs ("F&D costs") should be calculated if they are reported. Essentially NI 51‐ 101 requires that the exploration and development costs incurred in the year along with the change in estimated F&D costs be aggregated and then divided by the applicable reserve additions. The calculation specifically excludes the effects of acquisitions and dispositions on both reserves and costs. By excluding the effects of acquisitions and dispositions TORC believes that the provisions of the NI 51‐ 101 do not fully reflect TORC's ongoing reserve replacement costs. Since acquisitions can have a significant impact on TORC's annual reserve replacement costs, excluding these amounts could result in an inaccurate portrayal of TORC's cost structure. Accordingly, TORC also provides FD&A costs that incorporate all acquisitions and dispositions during the year. F&D costs disclosed herein are based on working interest gross reserves. 34