Raging River Exploration. Share Price March 5,

Transcription

1 March 2018

2 Raging River Profile Raging River Exploration RRX.TO Share Price March 5, Basic Shares Outstanding (mm) In-the-money Dilutives (mm) 1.1 FD Shares Outstanding (mm) Insider Ownership Basic 8.4% Insider Ownership Fully Diluted 9.2% Enterprise Value ($mm) 1,701 Market Capital ($mm) 1,401 Forecasted December 31, 2017 Net Debt ($mm) Q4, 2017 Annualized Net Debt to Funds Flow 0.9 Credit Facility ($mm) Production Guidance (boe/d) 24,500 % Oil 92% 2

3 RRX Production boe/d RRX Stock Price/WTI Cdn/10 RRX an Organic Growth Story 25,000 22,500 20,000 17,500 15,000 12,500 10,000 7,500 5,000 2, Production bbls/d Stock Price Production per 100 shares $WTI Cdn/10 3

4 Raging River 2017 Results Three months ended Year ended Percent December 31, December 31, Change Percent Change Wells drilled Net % % Average daily production Light crude oil and NGLs (bbls/d) 20,891 17,058 22% 19,863 15,589 27% Heavy crude oil (bbls/d) 1,115 1,780-37% 1, % Natural gas (mcf/d) 10,020 9,652 4% 10,742 8,079 33% Barrels of oil equivalent (boe/d) 23,676 20,447 16% 22,867 17,900 28% Netbacks ($/boe) Field netback % % Funds flow netback % % Financial (thousands of dollars except share data) Funds flow from operations 83,867 64,561 30% 281, ,188 50% Per share - basic % % Net earnings 19,950 18,986 5% 59,817 23, % Per share - basic % % Total capital expenditures 74, ,917-45% 372, ,203 4% Net debt 299, ,543 43% Shares outstanding, end of period (thousands) Basic 231, ,142 - Diluted 233, ,011-3% 4

5 Q2/12 Q3/12 Q4/12 Q1/13 Q2/13 Q3/13 Q4/13 Q1/14 Q2/14 Q3/14 Q4/14 Q1/15 Q2/15 Q3/15 Q4/15 Q1/16 Q2/16 Q3/16 Q4/16 Q1/17 Q2/17 Q3/17 Q4/17 Q2/12 Q3/12 Q4/12 Q1/13 Q2/13 Q3/13 Q4/13 Q1/14 Q2/14 Q3/14 Q4/14 Q1/15 Q2/15 Q3/15 Q4/15 Q1/16 Q2/16 Q3/16 Q4/16 Q1/17 Q2/17 Q3/17 Q4/17 Funds Flow per share ($/mm basic shares) Earnings per share ($/mm basic shares) WTI (US$/bbl) Producion per share (boe/mm basic shares) Q2/12 Q3/12 Q4/12 Q1/13 Q2/13 Q3/13 Q4/13 Q1/14 Q2/14 Q3/14 Q4/14 Q1/15 Q2/15 Q3/15 Q4/15 Q1/16 Q2/16 Q3/16 Q4/16 Q1/17 Q2/17 Q3/17 Q4/17 Reserves (mboe/mm FD shares) Per Share Growth Consistent and Efficient 120 Production per Share P+P Reserves per Share Reserves (Mboe/MM shares) 0.40 Funds Flow per Share Earnings per Share Funds Flow per share Growth WTI (US$/bbl) Earnings per Share WTI (US$/bbl) 5

6 Raging River 2018 Guidance 2018 average Production (92% oil) (boepd) 24,500 Funds Flow ($mm) $ Capital Expenditures ($mm) $335 Funds Flow Per Share basic $1.42 Forecast Year End 2018 Net Debt ($mm) $307 Operating Netback ($/boe) $39.44 Corporate Netback ($/boe) $ Assumptions Oil Pricing WTI ($/bbl US) $55.00 Exchange Rate ($C/$US) 0.78 Differential WTI to MSW ($/bbl) $3.85 Oil Pricing MSW ($C/bbl) $66.67 Raging River Net Price ($/boe) $57.14 Royalties 9.2% Operating Expense ($/boe) $10.95 Transportation Expense ($/boe) $ 1.45 Operating Netback ($/boe) $39.44 G&A and Interest ($/boe) $ 2.55 Hedging Gain/Loss($/boe) $ AT Funds Flow Netback ($/boe) $

7 2018 Guidance and Capital Allocation Base Viking Duvernay Total Oil (US$ WTI) $55.00 $55.00 $55.00 FX (C$/US$) $0.78 $0.78 $0.78 Oil (C$ MSW) $66.67 $66.67 $66.67 AECO (C$/GJ) $1.65 $1.65 $1.65 FFO Netback ($/boe) $36.30 $48.50 $36.67 Average Production 24, ,500 FFO ($mm) $318 $10 $328 FFO per share $1.38 $0.04 $1.42 Capex ($mm) $282 $53 $335 Exit Net Debt $253 $307 Exit 2018 Debt to FFO Viking Drilling, Completion and Tie-In Capital ($mm) Duvernay Drilling, Completion and Tie-In Capital ($mm) Duvernay Land ($mm) 9.0 Viking Waterflood and Facility Capital ($mm) 16.5 Viking Land, Seismic and Maintenance Capital ($mm) 12.0 Total 2018 Capital Expenditures Assumes 296 Net Viking Horizontal wells (60% ERH) 2. Assumes 6 Net Duvernay Delineation wells 7

8 2018 WTI Sensitivities 2018 Guidance Oil Pricing WTI ($/bbl US) Exchange ($C/$US) Oil Pricing MSW ($/bbl Cdn) Aeco Pricing ($/GJ Cdn) AT Funds Flow Netback ($/boe) Average Production (boe/d) 24,500 24,500 24,500 24,500 AT Funds Flow ($mm) Funds Flow per basic share ($/sh) Capex ($mm) Free Cash flow ($mm) Exit Net Debt ($mm) Exit 2018 Debt to FFO

9 December 31, 2017 Reserve Growth Reserve Category Oil (1) December 31, 2017 December 31, 2016 Natural YOY Total(2) Total(2) YOY Change Gas Growth (Mbbls) (Mmcf) (Mboe) % Reserves/ Basic Share (Mboe) (%) Proved Developed Producing 32,467 13,480 34,713 5% 32,991 6% Proven Undeveloped 45,087 12,720 47,207 38,372 23% Total Proved 77,561 26,622 81,998 15% 71,577 15% Probable Developed Producing 8,983 3,525 9,570 8,682 10% Probable Undeveloped 13,419 3,905 14,070 13,068 8% Total Proved Plus Probable 100,959 34, ,652 14% 93,989 13% 1,164 Net P+P Undeveloped wells booked at a FDC of $968.4 MM FDC represents approximately 3 times cashflow 1. NGL reserves are included in Oil reserves 2. Total reserve volumes (Mboe) include NGL volumes 9

10 December 31, 2017 Net Asset Value Sproule - December 31, 2017 Pricing SAL Dec. 31, 2017 Pricing ($000's) BTax NPV 10% $/share Proved plus probable reserves NPV (1,2) 2,190, Undeveloped acreage (3) 236, Net debt (4) (299,600) (1.28) Proceeds from Dilutives (5) 6, Net Asset Value (fully-diluted) 2,133, Fully Diluted Shares (M) in-the-money 233,253 - Additional Reserve Comments 2016 NAV (10% Disc) = $1,997,239 MM or $8.34/FD Share Undeveloped Acreage = 592,003 ac * $400/Acre = $236,801 MM 1,503 net Viking horizontal wells drilled and producing 1,159 net Viking horizontal wells booked 1 Duvernay producing well 3.8 Duvernay booked locations Sproule Dec. 31, 2017 Pricing: 1. Total reserve volumes (Mboe) include NGL volumes PDP includes 1166 Net Horizontal Viking Wells 3. Undeveloped acreage is calculated as $400/Acre 4. Net Debt at year end 2017 (unaudited) k options at an average strike price of $7.35 Sproule Dec. 31, 2017 Pricing Canadian WTI Light Sweet US 40 API Year $/Bbl $/Bbl

11 F&D Summary - December 31, Capital CORPORATE WITHOUT DUVERNAY Total E&D (000) 372, ,300 FD&A Recycle Ratio (1) Recycle Ratio (1) PDP Adds (Mboe) 10,062 9,881 PPDP Adds (Mboe) 10,951 10,722 PDP F&D (2) $36.98/boe 0.98 $33.32/boe 1.09 PPDP F&D (2) $33.98/boe 1.09 $30.71/boe 1.18 TP adds (Mboe) 18,761 18,227 Change in FDC (000) 167, ,190 Total Capital (000) 539, ,490 TP F&D $28.78/boe 1.26 $26.69/boe 1.36 P+P Adds (Mboe) 21,003 19,852 Change in FDC (000) 155, ,926 Total Capital (000) 527, ,226 P+P F&D $25.11/boe 1.45 $23.28/boe Based on 2017 Average Operating Netback of $36.36/BOE 2. Based on internally evaluated calculations 11

12 Light Oil Growth New Venture Area 380 sections prospective for Duvernay Light Oil Established Viking Light Oil - High Netback, Growth and Cash Flow Platform 12

13 Dominant Viking Position PROVOST Karve, Tamarack, Raging River, Rolling Hills KERROBERT Raging River, Whitecap HOOSIER Tamarack, Raging River PLENTY Raging River NAL, Teine RRX Land Viking HZ wells SEDALIA Tamarack, Raging River DODSLAND Raging River, Crescent Point, Teine LUCKY HILLS/Whiteside Raging River, Whitecap, Spartan, ISH, Yanchang BEADLE Raging River, Teine, Crescent Point FORGAN Raging River, NAL, Teine Dominant Land Position >460 highly prospective owned sections ~10 years of drilling inventory at our current pace of development MANTARIO (LAPORTE) Basal Mannville Heavy Oil Polymer Flood PLATO Raging River, Crescent Point, Teine Alberta Saskatchewan Viking Light Oil Resource Play >6800 Drilled and Licensed HZ wells >6200 With Public Domain Production Defined Viking Oil Pools 13

14 Raging River Saskatchewan HZ Wells Statistics Matter ~ 1,550 RRX Wells On-Stream 14

15 Extended Reach Horizontals - Forgan Enhancing Returns and Extending the Runway ERH wells are extending the economic boundaries of our asset base technology is making previous marginal lands economic at current commodity prices 15

16 Extended Reach Horizontals - Kerrobert Enhancing Returns and Extending the Runway ERH wells are extending the economic boundaries of our asset base technology is making previous marginal lands economic at current commodity prices 16

17 Raging River Waterflood Projects KERROBERT 1 Strong results - above Tier 9 tracking to EUR>>100 mstb per well 2 EUREKA GLENEATH DODSLAND 1 WHITESIDE 2 BEADLE Strong results - above Tier 7 tracking to EUR>60 mstb per well Gleneath and Eureka display very strong performance in pressure supported legacy waterfloods Above Tier 8 results and tracking to EUR>100 mstb per well Supportive of Waterflood recovery factors in excess of 25% PLATO FORGAN RRX Land RRX Land with WF Potential RRX WF PROJECT 17

18 Duvernay Emerging Light Oil Play RRX 4-11 DUVERNAY WELL Duvernay Company Activity Source: Geoscout and public documents. August Public Domain 39 Light Oil Producers 29 Light Oil Targeted Spuds Exponentially growing production 18

19 Duvernay Emerging Light Oil Play Early stage, high netback light oil resource play RRX has captured 390 net sections (250,000 acres) within the defined Duvernay Oil window, ~57% Crown FOX CREEK WEST SHALE BASIN Low cost of entry Moderate drilling depths ~ 2,200 to 2,400 m tvd. Significant resource potential internal estimates 8 to > 20 MMbbls OOIP per section Meaningful recent light oil success has been achieved by early entrants (Vesta, Artis, Paramount). Significant cost and technology improvements to date but still early in the play evolution EDMONTON RAGING RIVER FOCUS AREAS RED DEER EAST SHALE BASIN RRX first well drilled and placed on production in Q4, 2017 After Potma

20 Oil Rate bbls/d Duvernay Technology is Improving Peer Well Results by Vintage Technology Changes Increased Stages from Decreased inter-frac spacing from 100 m to 50 m Increased Lateral length from 1,200-2,400 m Proppant loading increased from tonnes per meter Aug-2012 Feb-2013 Sep-2013 Mar-2014 Oct-2014 Apr-2015 Nov-2015 Jun-2016 Dec-2016 Jul-2017 Jan

21 Duvernay Emerging Light Oil Play Ferrybank Area RRX 4-11 DUVERNAY WELL 3% SS IP: 146 bbl/d IP: 177 bbl/d IP: 202 bbl/d IP: 455 bbl/d IP: 173 bbl/d IP: 414 bbl/d Thickness 8-11m Porosity 5-10% (SS) Average 8% (SS) OOIP/section 8 12 MMBBL Total Organic Carbon 2% to 7.5% RRX successfully drilled the 4-11 horizontal well to a total measured depth of 4,573 m. The 4-11 well was completed with 43 stages over a 2,150 lateral length with average sand placement over the lateral length of 2 tonnes/m Commenced production on November 9, 2017 Maturity Mineralogy (XRD) Tmax: 434 C to 443 C Ro: 0.65% to 0.81% Carbonate 27% to 50% Quartz/Feldspar 33% to 41% Clay 12% to 30% 21

22 Oil rate Calendar (bbls/d) Duvernay Light Oil Historical Results RRX wells on production in the oil prone portion of the Duvernay play (does not include greater Kaybob). Average production significantly impacted by hours on production (reservoir management/land sale strategies) 22

23 Duvernay Emerging Light Oil Play RRX Drilled and Cased Completion Underway Paramount Focus Area RRX 4-11 Producing DUVERNAY WELL RRX 2-20 Drilled and Cased 2 mile lateral Q2/Q3 Completion Duvernay Well Costs Delineation $M Multi-well pad $M Development $M Drilling 1,950 1,850 1,600 Completions 4,550 3,350 2,850 E&T Total 7,000 5,500 4,750 Assumes 1.5 mile lateral and 1.5 tonne/m proppant loading Cost do not include: Vertical pilot holes, coring, logging, microseismic or other, reservoir characterizations methods. RRX has captured 390 net sections (250,000 acres) within the Duvernay light oil fairway RRX 1-20 Spud ~ Feb 25 Q2/Q3 Completion RRX 2018 Duvernay Capital Summary Vesta Focus Area Potential Initiation of Gas Window $MM Gross Wells Net Wells Duvernay DCET Land, Seismic, Maintenance Capital 9.0 Total 2018 Proposed Capital Artis Focus Area Potential Oil Maturity Limit Moderate drilling depths ~ 2,200 to 2,400 m tvd. Significant resource potential internal estimates 8 to 20 MMbbls OOIP per section First well (4-11) commenced oil production November 9, 2017 Preliminary 2018 program of 6 delineation wells evaluate acceleration of delineation program in Q3/

24 Duvernay Emerging Light Oil Play Knob Hill/Pigeon Lake area Thickness 15-25m Porosity OOIP/section 3-10% (SS) Average 5.5% (SS) MMBBL TOC 2% to 6.5% Maturity Mineralogy (XRD) Tmax: 441 C to 451 C Ro: 0.78% to 0.96% Carbonate 32% to 56% Quartz/Feldspar 26% to 41% Clay 15% to 25% Thickness 20m to 24m Porosity OOIP/section 3-10% (SS) Average 5.5% (SS) MMBBL TOC 2% to 6% Maturity Mineralogy (XRD) Tmax: 444 C to 456 C Ro: 0.83% to 1.05% Carbonate 9% to 78% Quartz/Feldspar 16% to 57% Clay 9% to 42% Cum oil to date = 131 Mstb 24

25 Why Raging River Management Proven execution throughout the commodity cycle Business Model Per share growth is imperative Balance Sheet Strict control and management of balance sheet Sustainability 10 year plus Viking drilling inventory Value Creation Early low cost entrant in emerging Duvernay light oil play 25

26 Office 1700, 605-5th Avenue SW Calgary, Alberta T2P 3H5 Main: (403) Fax: (403) Website For further information Please contact: Mr. Neil Roszell, P.Eng. Phone: (403) Mr. Jerry Sapieha, CA Phone: (403) Mr. Bruce Beynon, P.Geol. Phone: (403)

27 Disclaimer FORWARD LOOKING STATEMENTS: This presentation contains forward-looking statements. More particularly, this presentation contains statements concerning Raging River's expectations related to potential resources estimates, expected ability for productivity and recovery improvements in the Duvernay play through technology, details of the 2018 budget including amount to be spent on development expenditures, expected 2018 average and exit production, guidance for the full year 2018, including production, commodity prices, operating cashflow, general and administrative expenses, financial charges, funds flow from operations, annualized funds flow from operations per share 2018 exit net debt, 2017 and 2018 exit net debt to funds flow from operations, oil and gas sales, royalties, operating expense, transportation expense, operating netback, and funds flow netback, the expected results from certain drilling space, longer lateral and waterflood initiatives, the Company's flexibility in changing its capital budget in response to changing commodity prices, the ability to grow without additional land capture, technology improvements or acquisitions and the intent to pursue acquisitions that add to shareholder value. In addition, the use of any of the words guidance, initial, scheduled, can, will, prior to, estimate, anticipate, believe, potential, should, unaudited, forecast, future, continue, may, expect, project, and similar expressions are intended to identify forward-looking statements. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, that Raging River will not achieve the anticipated benefits of the Acquisition or other transactions, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations, changes in legislation affecting the oil and gas industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Additional information on these and other factors that could affect Raging River s operations and financial results are included in the Company s Annual Information Form and other reports on file with Canadian securities regulatory authorities, which may be accessed through the SEDAR website ( The Company has presented herein ten year growth plans based on certain commodity price assumptions. Such growth plans do not represent management's expectations of the Company's future performance but rather is intended to present management's belief in the economic viability of the Company's business based on such pricing scenarios. Readers should not use such ten year growth model as a presentation of the Company's future performance. The forward-looking statements contained in this presentation are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws. RESERVES AND PRODUCTION DISCLOSURE: Reserves and production information presented herein has been presented on a gross basis which are the Company s total working interest share before the deduction of any royalties and without including any royalty interests of the Company. The reserves estimates presented herein have been evaluated by Sproule and GLJ in accordance with NI and the COGE Handbook and are effective December 31, 2017 using Sproule's December 31, 2017 forecast pricing. GLJ evaluated the reserves associated with the Company's interests in the east Duvernay shale basin and Sproule evaluated the reserves associated with the remainder of the Company's oil and gas interests. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation. It should not be assumed that the estimates of future net revenues presented herein represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of the Company''s crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein. 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. OIL AND GAS METRICS: This press release contains a number of oil and gas metrics, including F&D or FD&A, recycle ratio, reserves replacement, and reserves life index or RLI, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods. 27

28 Disclaimer FUTURE ORIENTED FINANCIAL INFORMATION: Any financial outlook or future oriented financial information in this presentation, as defined by applicable securities legislation, has been approved by management of Raging River. Readers are cautioned that any such future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The Company and its management believe that the prospective financial information has been prepared on a reasonable basis, reflecting management's best estimates and judgments, and represent, to the best of management's knowledge and opinion, the Company's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results NON-IFRS MEASURES: This document contains the terms "funds from operations" (or "cash flow"), "net debt", "field netback", "operating netback" and "funds flow netback", which do not have a standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and therefore may not be comparable with the calculation of similar measures by other companies. Management uses funds from operations to analyze operating performance and leverage. Management believes "net debt" is a useful supplemental measure of the total amount of current and long-term debt of the Company. Mark-to-market risk management contracts are excluded from the net debt calculation. Management believes "field netback", "operating netback" and "funds flow netback" are useful supplemental measures of firstly, the amount of revenues received after royalties and operating and transportation costs, secondly, the amount of revenues received after royalties, operating, transportation costs and realized gain (loss) on derivatives, and thirdly, the amount of revenues received after royalties, operating, transportation costs, realized gain (loss) on derivatives, general and administrative costs, financial charges and asset retirement obligations. Additional information relating to certain of these non-ifrs measures, including the reconciliation between funds from operations and cash flow from operating activities, can be found in the Company's most recent management's discussion and analysis which is available on SEDAR at ASSUMPTIONS RELATING TO RESULTS FROM LONGER LATERAL WELLS, WATERFLOOD AND WELL SPACING ECONOMICS: The Company has presented certain anticipated results from initiatives that the Company is currently undertaking relating to drilling longer lateral wells, decreasing well spacing and waterfloods. Such results have been based on historic performance and certain assumptions made by management relating to future performance. Such information has been presented so that readers can understand management's assumptions and modeling used for the purpose of determining to undertake such initiatives. The information presented relating to improved recovery factors, initial production rates, finding and development costs ("F&D"), estimated ultimate recovery ("EUR"), recycle ratios and reserves life index are not intended to provide an estimate of future performance of wells or an estimate of reserves. Readers should not use such information as an estimate or projection of the Company's future performance or the performance relating to any particular initiative to be undertaken by the Company. OIL AND GAS METRICS: This presentation contains a number of oil and gas metrics, including capital efficiency, initial production rates for the first 90 days ("IP 90"), internal rate of return ("IRR"), reserves life, F&D, recycle ratio, and payout, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods. Capital efficiency is based on the total capital invested in a period divided by the average daily production additions (over the period indicated) resulting from such activity. IP 90 is the expected initial production rate for the first 90 days of production of a well. Internal rate of return is calculated by taking the expected capital costs to drill, complete and equip wells and balancing them against the future net revenue expected using various commodity price forecasts and management estimates of operating costs, royalties, production rates and reserves. Reserves life is determined by dividing the reserves by the annual production of the Company. Finding and development costs are determined by dividing the expected reserves addition by the capital expected to be spent finding and developing such reserves. Recycle ratio is the ratio between netbacks and F&D on a per BOE basis. Payout is calculated by determining the number of years it will take the Company to earn back the capital invested in such well based on expected production and various price and cost inputs. The capital efficiencies, initial rates of production, rates of return and payouts associated with the wells or assets have been provided herein to give an indication of management's assumptions used for budgeting, planning and forecasting purposes. The capital efficiencies, initial rates of production, IRR, F&D, reserves life, recycle ratio and payouts associated with the wells or assets will most likely be different than projected. Any references in this presentation to capital efficiencies, initial rates of production, IRR, F&D, reserves life, recycle ratio and payouts associated with the wells or assets are useful in confirming 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 the Company. INITIAL PRODUCTION RATES; References in this press release to initial production rates, and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, the Company cautions that the test results should be considered to be preliminary. OOIP: Original Oil-In-Place ("OOIP") is equivalent to Total Petroleum Initially-In-Place ("TPIIP") and has been estimated as at December 31, TPIIP, as defined in the Canadian Oil and Gas Evaluations Handbook, is that quantity of petroleum that is estimated to exist in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. A portion of the TPIIP is considered undiscovered and there is no certainty that any portion of such undiscovered resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of such undiscovered resources. With respect to the portion of the TPIIP that is considered discovered resources, there is no certainty that it will be commercially viable to produce any portion of such discovered resources. A significant portion of the estimated volumes of TPIIP will never be recovered. 28

29 Appendix Information

30 Management Team and Board of Directors Management Team Neil Roszell, P. Eng. Bruce Beynon, P. Geol. Jason Jaskela, P. Eng. CEO & Exec Chairman President VP Production & COO Jerry Sapieha, CA. Scott Rideout Jesse Barlow, P. Eng. VP Finance & CFO Vice President Land Vice President Engineering Terry Danku, P. Eng. Chad Lundberg, P. Eng. Jonathan Grimwood, P.Geol VP Business Development Vice President Operations Vice President Exploration Board of Directors Neil Roszell Dave Pearce Gary Bugeaud CEO & Exec Chairman Deputy Managing Partner Independent Businessman Raging River Exploration Azimuth Partners Calgary, Alberta George Fink Kevin Olson Raymond Mack Chairman & CEO President Kyklopes Partner: Kenway Mack Bonterra Oil & Gas Ltd. Capital Management Slusarchuk Stewart LLP Bruce Beynon President Raging River Exploration 30

31 Historical F&D Measures Average crude oil price WTI US$/bbl Capital ($000) 372, , , , , ,032 Production boe/d 22,867 17,900 13,715 10,755 5,665 2,277 Operating netback $/boe Proved Producing Total Reserves mboe 34,713 32,991 24,530 19,103 12,004 4,473 Reserves additions mboe 10,062 15,013 10,433 11,024 9,599 3,054 FD&A $/boe Recycle Ratio Reserves Replacement 121% 229% 208% 281% 464% 461% RLI (years) Total Proven Total Reserves mboe 81,998 71,577 57,391 49,928 31,376 11,544 Reserves additions mboe 18,761 20,738 12,467 22,466 21,851 8,451 Change in FDC ($000) 167,823 84,939 (67,100) 262, , ,698 FD&A $/boe Recycle Ratio Reserves Replacement 225% 317% 249% 572% 1057% 1275% RLI (years)

32 Historical F&D Measures Average crude oil price WTI US$/bbl Capital ($000) 372, , , , , ,032 Production boe/d 22,867 17,900 13,715 10,755 5,665 2,277 Operating netback $/boe Proved Plus Probable Producing Total Reserves mboe 44,283 41,673 30,952 23,873 16,908 6,258 Reserves additions mboe 10,951 17,273 12,085 10,890 12,717 4,006 FD&A $/boe Recycle Ratio Reserves Replacement 131% 264% 241% 277% 615% 605% RLI (years) Proven Plus Probable Total Reserves mboe 106,652 93,989 76,361 63,565 42,729 17,164 Reserves additions mboe 21,003 24,180 17,800 24,750 27,619 12,380 Change in FDC ($000) 155,391 66,240 (43,900) 305, , ,435 FD&A $/boe Recycle Ratio Reserves Replacement 252% 369% 356% 630% 1336% 1868% RLI (years)

33 Historic Operational Excellence Quarter Q4/17 Q3/17 Q2/17 Q1/17 Q4/16 Q3/16 Q2/16 Q1/16 Q4/15 Q3/15 Q2/15 Q1/15 Financial (thousands of dollars except share data) WTI (US$/bbl) MSW (Cdn$/bbl) Funds Flow from Operations 83,867 60,407 64,965 72,752 64,561 49,726 43,999 29,904 40,708 43,630 49,535 33,480 Basic Shares Outstanding End of Period 231, , , , , , , , , , , ,206 Annualized CF/Share Basic Quarterly CF/Share growth 39% -7% -11% 13% 30% 11% 47% -31% -12% -13% 47% -47% Net Earnings 19,950 5,929 18,595 15,343 18,986 6,758 5,320 (7,852) 5,120 10,893 12, Annualized Quarterly Earnings per Basic Share N/A Average Daily Production 23,676 23,011 22,015 22,755 20,447 18,612 16,002 16,505 14,771 13,418 13,347 13,310 Operating Netback ($/boe) Funds Flow Netback ($/boe) TSX:RRX 33

34 Waterflood Works Gleneath Legacy WF Gleneath Waterflood Area OOIP ~ 155 mm bbls Current Recovery 15% Ultimate Recovery >24% Waterflood Initiated 1966 Massive drop in GOR and original producers have more than doubled primary production > 10 years of Flat Production Strong results - above Tier 9 tracking to EUR>>100 mstb per well One of the most mature patterns in Gleneath 25% Recovery Factor has been achieved Ultimate recovery expected at 35-45%! 34