April 2016 Corporate Presentation

Transcription

1 April 2016

2 Advisory Forward Looking Information This presentation contains certain forward looking statements within the meaning of applicable United States securities legislation and forward looking information within the meaning of applicable Canadian securities legislation (collectively, forward looking information ), which reflects management s expectations about the Corporation s future growth, results of operations (including future production and capital expenditures), performance (both operational and financial) and business prospects. All information and statements other than statements of historical fact is forward looking information. The information contained in this presentation does not purport to be all inclusive or to contain all information that potential investors may require. In this presentation there is forward looking information in respect of the Corporation s business; anticipated business activities and development plans; projected growth and execution of corporate plans and strategies; timing and success of development and exploitation activities; timing and development of the Corporation s capital projects, including the Cactus Lake and Pirtuk SAGD projects; expectations regarding the Corporation s ability to add production and reserves through exploration, development, exploitation and acquisitions; future oil and gas production levels; planned capital and operating expenditures; future operating costs; expected rate of return; hedging and other risk management plans and strategies; and future commodity prices. In addition, statements relating to reserves and resources are deemed to be forward looking information as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. Although the forward looking information in this presentation reflects management s current beliefs about the Corporation s prospects, based on information currently available to management and on what management believes to be reasonable assumptions, there is no certainty that the actual results achieved will be consistent with such forward looking information. Forward looking information is not a guarantee of future performance and necessarily involves significant known and unknown risks, assumptions and uncertainties, some that are similar to other oil and gas companies and some that are unique to Northern Blizzard, which may cause Northern Blizzard s actual results, performance, prospects and opportunities in future periods to differ materially from those expressed or implied by the forward looking information provided in this presentation. Any changes to the assumptions on which such forward looking information is based could cause actual results, performance or achievements to differ materially from the anticipated results expressed or implied in the forward looking information of the Corporation set out in this presentation. A large number of factors could affect the assumptions on which statements about forward looking information are made in this presentation or the underlying assumptions many of which are beyond the Corporation's control, including: general economic, market and business conditions; competition; fluctuations in oil and natural gas prices; and changes in laws or royalty regimes. Forward looking information is expressly qualified by the foregoing cautionary statements, is stated as of the date of preparation of this presentation and, except as required under applicable laws, Northern Blizzard assumes no obligation to update or revise such information to reflect new events or circumstances. Presentation of Financial Information Unless otherwise noted, all financial information for Northern Blizzard has been prepared in accordance with IFRS, as issued by the International Accounting Standards Board. Non IFRS Measures In addition to using financial measures prescribed by IFRS, references are made in this presentation to EBITDA, net debt, and total payout ratio, which are measures that do not have any standardized meaning as prescribed by IFRS. Accordingly, the Corporation's use of such terms may not be comparable to similarly defined measures presented by other entities. For further details on these non IFRS financial measures, refer to Northern Blizzard s most recent management s discussion and analysis. April

3 Advisory Presentation of Oil and Gas Information All oil and gas information in this presentation has been prepared and presented in accordance with NI adopted by the Canadian securities regulatory authorities. Unless otherwise specified, in this presentation, all production is reported on the basis of the Corporation s working interest ( WI ) (operating and nonoperating) before the deduction of royalties payable. All numbers of wells and acreage information are presented on a gross basis. Unless otherwise indicated, reserves and resources information in this presentation is given as of December 31, For complete NI reserves disclosures, refer to the Annual Information Form dated March 11, Discovered Petroleum Initially in Place or Discovered Oil Initially in Place ( DOIIP ), is defined in the Canadian Oil and Gas Evaluation Handbook as the quantity of oil that is estimated to be in place within a known accumulation prior to production. DOIIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion consisting of production, reserves and contingent resources. There is no certainty that it will be economically viable or technically feasible to produce any portion of the DOIIP except for those portions already produced or identified in the independent reserves report. At December 31, 2015 all DOIIP that has not already been produced or classified as reserves would be classified as contingent resources or unrecoverable DOIIP. There are no contingent resources identified in this presentation. A portion of the quantities currently classified as unrecoverable DOIIP may become recoverable and reclassified as contingent resources or reserves in the future as additional technical studies are performed, commercial circumstances change or technological developments occur. The remaining portion may never be recovered due to the physical or chemical constraints represented by subsurface interaction of fluids and reservoir rocks. The discounted and undiscounted net present value of future net revenues attributable to reserves and resources do not represent the fair market value of such reserves and resources. 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 crude oil, natural gas and NGL reserves and resources provided in this presentation are estimates only and there is no guarantee that the estimated reserves or resources will be recovered. Actual crude oil, natural gas and NGL reserves and resources may be greater or less than the estimates provided in this presentation. The estimates of reserves and future net revenue for individual properties in this presentation may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. The Corporation has adopted the standard of 6 Mcf:1 bbl when converting natural gas to oil equivalent. Boe conversions may be misleading particularly if used in isolation. A boe conversion ratio of 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. As the value ratio natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. April

4 Corporate Highlights Common Shares TSX:NBZ Public Float 29.7 million shares / 26% Management (1) 5.0 million shares / 4% NGP / Riverstone 80.8 million shares / 70% Outstanding, Basic (2) million shares Annual Dividend $0.48 per share Reserves DOIIP (net) (3) ~2.1 billion bbl 2P Reserves (3) 153 million boe PDP / 2P Reserves 38% 1P / 2P Reserves 56% Balance Sheet Credit Facility $475 million (4) Senior Unsecured US$276.3 million (due 2022) Notes Net Debt (5) $400.5 million Net Debt to Funds 2.4x from operations (5)(9) 1. Includes management and directors as reported on SEDI as of Mar 31, As at Mar 31, Discovered Oil Initially In Place; based on an independent reserve report effective Dec 31, Borrowing base review to be completed by May 31, As at Dec 31, Annual Guidance (6) Production 19,000 boe/d Funds from Operations (7) $120 million Capital Expenditures $40 million Total Payout Ratio (8)(9) 80% / 45% Net Debt (9) $334 million Net Debt to Funds from operations (9) 2.8x 6. Guidance issued Feb 12, Including hedging gains. 8. Cash dividends plus capital expenditures divided by funds from operations (including hedging gains). 80% payout assumes full cash dividend and 45% payout assumes an average Stock Dividend Program ( SDP ) participations rate of 74%. 9. Non IFRS measure, see Advisory. April

5 Investment Highlights World Class Oil Resource Base Approximately 2.1 billion bbl DOIIP (1) with ~12% recovered Low corporate decline rate of 17% trending lower Long reserve life index (2P = 21.9 years; PDP = 8.2 years) Large inventory (>2,000) of low risk drilling locations with good capital efficiencies Strong Financial Position Balance Sheet Strength $475 million (2) bank facility Senior unsecured notes US$276.3 million due 2022 No maintenance covenants 2016 year end net debt (3) /funds from operations (4) of 2.8x Active hedging program (5) C$79.50/bbl WTI & C$18.89/bbl WCS differential C$66.50/bbl WTI & 2.6 C$18.37/bbl WCS differential C$60.04/bbl WTI Business Model Private Equity Sponsorship Monthly dividend of $0.04 per common share Capital allocation to projects that support long term value Need approximately US$37/bbl WTI to breakeven and pay cash dividend in % of production cash flow positive at < WTI ~US$30/bbl (6) NBRI is backed by two world class private equity firms Differentiated access to capital Strong business model positioned for growth 1. Discovered Oil Initially In Place; based on an independent reserve report effective Dec 31, Borrowing base review to be completed by May 31, Non IFRS measure. See Advisory. 4. Funds from operations including hedging gains. 5. Based on a CAD/USD rate of Based on Q April

6 World Class Oil Resource Base Significant high quality oil resource Approximately 2.1 billion bbl DOIIP (1) with ~12% recovered Large inventory ( > 2,000) of low risk drilling locations with good capital efficiencies Long life low decline assets Low corporate decline rate of 17% trending lower Long reserve life index 2P = 21.9 years PDP = 8.2 years Lower viscosity heavy oil Ideally suited to EOR techniques (waterflood, polymer flood, SAGD) Assets are located in Saskatchewan High quality low cost asset base underpins sustainability and future growth 1. Discovered Oil Initially In Place; based on an independent reserve report effective Dec 31, April

7 Oil Production Decline 23,000 22,000 21,000 20,000 19,000 18,000 17,000 16,000 15,000 14,000 13,000 Net Base Production 6/1/2016 7/1/2016 8/1/2016 9/1/ /1/ /1/ /1/2016 1/1/2014 2/1/2014 3/1/2014 4/1/2014 5/1/2014 6/1/2014 7/1/2014 8/1/2014 9/1/ /1/ /1/ /1/2014 1/1/2015 2/1/2015 3/1/2015 4/1/2015 5/1/2015 6/1/2015 7/1/2015 8/1/2015 9/1/ /1/ /1/ /1/2015 1/1/2016 2/1/2016 3/1/2016 4/1/2016 5/1/2016 bbl/d Oil (bbl/d) 12% Decline 17% Decline Outlooked Oil (bbl/d) NBRI has one of the lowest decline rates 46% 46% 45% 50% 39% 39% 39% 39% 37% 35% 35% 35% 33% 33% 32% 32% 32% 32% 30% 28% 26% 25% 25% 25% 24% 24% 23% 23% 21% 21% 43% 43% 40% 30% 12% 16% 15% 21% 20% 19% 19% 17% 20% 10% Decline Rate (%) 0% Low decline rate is key to sustainable business model 1. Source: CIBC Research Estimates; Enerplus decline for Canadian assets only. April

8 Credit Capacity & Liquidity Debt Composition Dec 31, 2015 Bank Credit Facility $475.0 million borrowing base Borrowing base to be reviewed in May 2016 NBRI is in compliance with financial covenants: $475.0 million Credit Facility $382.4 million (3) Senior Unsecured Notes Senior Unsecured Notes US$276.3 million (C$382.4 million (3) ) Due Feb 1, 2022 No maintenance covenants Corporate Credit Ratings S&P B/Stable Moody s B2/Negative DBRS B(low)/Negative Dec 31, 2015 Dec 31, 2016 (1) Senior Debt (2) / EBITDA (=< 3.0) EBITDA / Interest Expense (>= 2.5) Credit capacity supports strong financial position 1. Forward looking information. See Advisory. 2. For this calculation, Senior Debt excludes the Senior Unsecured Notes. 3. Amount in CAD at Dec 31, 2015 using CAD/USD of April

9 Active Hedging Program Hedge program supports predictable cash flows C$79.50/bbl WTI & C$18.89/bbl WCS differential C$66.50/bbl WTI & 2.6 C$18.37/bbl WCS differential C$60.04/bbl WTI bbl/d 14,000 12,000 10,000 8,000 6,000 4,000 2, WTI (C$/bbl) Volume Hedged Average Hedge Price Total % Hedged 2016E (oil & gas) 80% 70% 60% 50% 40% 30% 20% 10% 0% $70 69% $64 61% $61 $61 $67 $58 $58 $53 $54 $55 $54 $60 58% $50 $49 $51 $46 39% 36% 36% $34 33% 33% 29% 27% 24% 23% 20% 17% 13% 11% 8% 6% $0 0% 0% 0% 0% PGF NBZ BNP CPG WCP CR VII BTE GXO CJ TVE SGY VET PWT TOU LTS TBE JOY RRX TOG BNE SPE $80 $70 $60 $50 $40 $30 $20 $10 $0 Average Oil Floor Price (US$WTI/bbl) Total % Hedged 2016E Average Floor Price (US$WTI/bbl) Source: CIBC Research, street research and company filings at Apr Excludes differential hedges. ~60% of NBRI s 2016 production is hedged at C$60/bbl WCS April

10 Operating In A Low Oil Price Environment Optimize asset integrity Optimize asset integrity Manage decline rates low decline rate requires less sustaining capital Committed to long life projects (i.e. polymer flood, SAGD) Rigorous cost controls Rigorous cost controls Operating costs of $16.72/boe in 2015, 21% lower than 2014 Capital cost improvements of 20 30% in 2015 Disciplined capital allocation Disciplined capital allocation Large inventory of low risk drilling locations (> 2,000) with strong capital efficiencies Capital allocation to projects that support long term value Operate over 95% of production, which provides ability to control virtually all of our capital expenditures NBRI is well positioned to sustain the current low oil price environment April

11 Operating & Capital Cost Improvements Operating Costs ($/boe) Operating cost improvements Operating costs of $16.72/boe (2015) are 21% lower than 2014 NBRI continues to work to reduce production costs 24% savings 21% savings 30% savings Capital cost improvements Cactus Lake 24% savings Winter 21% savings Coleville 30% savings Focus on cost saving measures has resulted in significant operating and capital cost improvements April

12 2016 Guidance & Sensitivities Guidance (1) Sensitivities WTI (US$/bbl) WCS differential (US$/bbl) (14.25) (14.00) (13.75) CAD/USD Average production (boe/d) 19,000 19,000 19,000 Capital expenditures $40 million $40 million $40 million Funds from Operations (2) $120 million $109 million $97 million Total Payout Ratio (3) full cash dividend 80% 88% 100% Total Payout Ratio (3) SDP(72% participation rate) 45% 50% 56% Year End Net Debt (4) $334 million $353 million $371 million Year End Net Debt (4) / Funds From Operations (2) 2.8x 3.2x 3.8x US$30/bbl scenario is for illustrative purposes only and does not account for possible reductions to capital expenditures, operating costs and/or dividends in that oil price environment 1. Guidance issued Feb 12, Funds from operations includes estimated hedging gains of $105 million (at US$40/bbl WTI), $129 million (at US$35/bbl) and $155 million (at US$30/bbl) 3. Payout ratio is calculated as cash dividends plus capital expenditures divided by funds from operations (including hedging gains). 4. Non IFRS measure. See Advisory. April

13 Focus Assets Cactus Lake, Winter & Coleville Cactus Lake Winter Coleville DOIIP of 409 mmbbls (2) 13% recovered to date Drilling inventory of 311 locations (2) 255 booked 2P (1), 56 unbooked EUR of ~100 mboe per well (2) Upside from infill drilling, waterflood and polymer flood DOIIP of +600 mmbbls (2) < 8% recovered to date (2) Drilling inventory of +450 gross locations (2) 277 (net 201) 2P (1), +173 unbooked EUR of ~53 mbbl per well (1) Upside from infill drilling 10,000 acres in proven Viking fairway Drilling inventory of 311 (2) locations 112 booked 2P (1), 199 unbooked (2) EUR of ~41 mboes per well (1) Upside from horizontal drilling Currently ~60% of production with potential to exceed 20,000 boe/d in the next 5 6 years 1. Based on an independent reserve report effective Dec 31, Internal estimates, gross. April

14 Represents Industry s Top Project Economics Before Tax Rate of Return (%) WTI Strip Price (1) 2016 Guidance (2) Cactus Lake Waterflood w/o Facilities Coleville Viking (Light Oil, crown royalties) Winter Main w/o Facilities 20 Winter South Sec 27,34 &3 Winter South Sec 21&22 w/ Facility 0 $30 $35 $40 $45 $50 $55 $60 $65 $70 $75 WTI (US$/bbl) 1. Source: National Bank Financial as at Apr 6, Guidance issued Feb 12, April

15 Top Quartile Breakeven Economics (15% BT) $100 $90 $29 $34 $36 $38 $39 $39 $39 $39 $41 $42 $42 $43 $43 $43 $43 $44 $44 $45 $45 $46 $46 $46 $47 $47 $48 $48 $49 $50 $50 $50 $51 $51 $52 $52 $53 $53 $53 $53 $54 $54 $54 $55 $55 $55 $56 $56 $56 $56 $56 $57 $57 $58 $59 $59 $59 $59 $60 $60 $63 $64 $66 $67 $68 $69 $69 $69 $70 $72 $73 $74 $76 $76 $80 $70 $60 $50 $40 $30 $20 $10 $0 RMP (Ante Creek) - Montney Oil Crescent Point - Bakken (Waterflood) Surge (Valhalla) - Doig Kelt (La Glace) - Montney Oil Whitecap - Viking Crescent Point - Mississippian Encana - Duvernay Oil ARC (Tower) - Montney Oil Crescent Point - Torquay Northern Blizzard (Cactus) - Mannville Whitecap - Cardium Crescent Point - Bakken Whitecap - Dunvegan Oil Torc - Mississipian Tamarack - Cardium Northern Blizzard - Viking Northern Blizzard (Winter) - Mannville Whitecap (Valhalla) - Montney Oil Spartan - Mississippian Granite - (AB Bakken) Bonterra (East Pem) - Cardium Raging River - Viking Trilogy (Kaybob) - Montney Oil Lightstream - Mississippian Husky - Bakken Trilogy (Volatile Oil) - Duvernay ARC (Ante Creek) - Montney Oil ARC (Pembina) - Cardium Torc - Torquay Encana - Montney Oil Surge - Upper Shaunavon Twin Butte - Dina Cummings Crescent Point - Viking Twin Butte - Sparky Vermilion - Mississippian Lightstream - Bakken Tourmaline - Charlie Lake Baytex - Mannville Heavy Longrun - Viking Spartan - Viking Cardinal - Glauconite Oil Kelt (Karr) - Montney Oil Crescent Point - Lower Shaunavon Trilogy (Condensate/Gas) - Duvernay Torc - Cardium Lightstream (West Pem) - Cardium Pengrowth (Lochend) - Cardium Birchcliff - Charlie Lake Twin Butte - Lloydminster Penn West - Viking Baytex - Peace River Heavy (Cold) Crew (Tower) - Montney Oil Bonavista - Cardium RMP (Waskahigan) - Montney Oil Kelt - Charlie Lake Journey - Glauconite Oil Penn West - Spearfish Penn West - Cardium Surge - Mannville Heavy Husky - Cardium Penn West - Peace River Heavy (Cold) Vermilion (West Pem) - Cardium Long Run - Montney Oil Lightstream - Swan Hills Crescent Point - Swan Hills Pengrowth - Swan Hills Baytex - Peace River Heavy (Thermal) Long Run - Cardium Bellatrix Cardium Torc (AB Bakken) Athabasca - Duvernay Penn West - Slave Point Breakeven Oil Price (C$/bbl Ed. Par) Source: CIBC Research. 1. Assumes ~US$4/bbl Edmonton Par WTI differential, US$12/bbl heavy WTI differential. FX of $US $C. AECO gas prices of C$2.78/Mcf in year 1, C$3.40/Mcf (2017E) and C$3.13/Mcf (2018E) thereafter. 2. NBZ play types use NBZ specific play blending and transportation costs. All other company plays use CIBC reserve estimates. April

16 Cactus Lake April

17 Cactus Lake Overview 1. Management estimate as at Dec 31, Based on an independent reserve report effective Dec 31, Producing wells only. Sparky DOIIP 16 mmbbl Rex, Bakken DOIIP 393 mmbbl Highlights DOIIP (1) 409 mmbbls bbl Recovered to date 13% 2P Reserves (2) 52 million boe Est production 7,897 boe/d Wells drilled to Dec 31, (3) 311 locations Drilling inventory (>18% unbooked) 50% IRR at Economics US$50/bbl WTI Play characteristics 100% operator NBRI s largest field by production and reserves Low viscosity, floodable heavy oil Bakken and Lower Mannville (Rex) commingled for production and injection Exploitation strategy Repeatable vertical / directional drilling at 10 acre spacing Waterflood Polymer flood April

18 Cactus Lake Repeatable Development Calendar Day Oil Rate (bbl/d) Infill Performance vs Type Curve Waterflood Type Curve Polymer flood Type Curve Month Gross TC (WF) Gross TC (PF) Phase 1 Phase 2A Phase 2B Phase 3A Phase 3B Phase 4 Phase 5 Phase ID Drill Vintage Polymer Started Well Count Phase , Phase 2A Phase 2B 2012, Phase 3A Phase 3B 2014 Waterflood 41 Phase , 2014 Waterflood 44 Phase Waterflood Development Drills Oil Rate (bbl/d) Dec 15 1 Mar 16 1 Jun 16 1 Sep 16 1 Dec 16 Daily Rate Type Curve April

19 Cactus Lake Opportunity Base 352 Basal Mannville Bakken production wells drilled to date 311 remaining inventory locations identified Average DOIIP in remaining sections expected to be in line with developed sections to date Infill production and reserves repeatability anticipated to be consistent with results to date 2 successful step out wells drilled in Basal Mannville Bakken Drilling Inventory NTD: update map; no white net pay 250 Well Count Drilled to Date PV UD PB UD Unbooked Inventory April

20 Cactus Lake Polymer Update 50% of DOIIP and field production currently under polymer injection Largest North American non horizontal polymer flood by injection volumes Initial production response materialized in 2015 Phase 3A commissioned in March 2015 Cactus Lake Polymer Injection 50,000 Rex/Bakken Sparky Polymer Injection Rate, bbl/d 45,000 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 Project MMbbl Sparky 2.58 Rex/Bakken Total Sparky Injection Commencement: Sparky HZ: Q Phase 1: Q4/12, 2013 Phase 2A: 2014 Phase 2B: 2014 Phase 3A: 2015/03 April

21 Cactus Lake Why Polymer Flood Works Normalized comparison between polymer flood (PF) and waterflood (WF) areas Oil Rate (bbl/d) PF WF Oil Rate Water Rate Oil rates are comparable Water Rate (bbl/d) Polymer flood has lower total fluid rates Phase 2B Phase 4 Location (Section) N27, S34 35 Flood Type Polymer Water Infill Drill Timing Avg Net Pay (m) WOR Water Oil Ratio (WOR) Lower WOR demonstrates improved sweep efficiency Improved sweep efficiency of polymer flood provides opportunity to increase ultimate reserve recovery April

22 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 April Jan 15 Jan 00 Jul 00 Jan 01 Jul 01 Jan 02 Jul 02 Jan 03 Jul 03 Jan 04 Jul 04 Jan 05 Jul 05 Jan 06 Jul 06 Jan 07 Jul 07 Jan 08 Jul 08 Jan 09 Jul 09 Jan 10 Jul 10 Jan 11 Jul 11 Jan 12 Jul 12 Jan 13 Jul 13 Jan 14 Jul 14 (bbl/d) Jul 15 Jan 16 Cactus Lake Consistent Demonstrated Growth Cactus Lake Area Oil Production Demonstrated production growth 19% CAGR Polymer and waterflood focus providing low decline, stable production base Sparky Base

23 Cactus Lake Reduced Operating Costs, Strong NOI (1) 2015 Highlights: 12% year over year production growth Polymer production response Limited infill drilling 32% reduction in operating costs Strong free cash flow (2) generated 2016 Guidance: $14.9 million capital expenditures 70% polymer powder Flat production Polymer to offset decline $11.21/boe operating costs boe/d 10,000 Producers Drilled $ million 8,000 6,000 4,000 2, Average Daily Production and Operating Costs E Production Operating Cost Capital Expenditures and Net Operating Income E $/boe 1. Net operating income (NOI) is revenue less royalties, operating costs and transportation 2. Free cash flow is net operating income less capital expenditures Capital Expenditures Net Operating Income April

24 Winter April

25 Winter Overview Highlights +600 mmbbls bbl(1) Recovered to date < 8% gross estimate 2P Reserves(2) 22 million boe Est production +2,770 boe/d Wells drilled to Mar 31, gross +450 gross locations Drilling inventory (>38% unbooked) +50% IRR at Economics US$50/bbl WTI NBRI CNRL DOIIP Play characteristics Oil over active water system Exploitable through horizontal drilling Repeatable infill drilling Internal estimate, gross Based on an independent reserve report effective Dec 31, April

26 Winter Value Creation Repeatable Horizontal Drilling Consistent performance 182 horizontal wells drilled for production on 25 meter spacing since 2010 (Dec 31, 2015) Superior economics Winter development provides better economics than the Viking play Repeatable development +450 locations identified on 25 meter spacing Only 277 locations have been recognized by independent reserves evaluator due to timing Down spacing opportunity Further down spacing to 12.5 meter spacing which could increase locations to nearly 1,000 April

27 Winter Reduced Operating Costs, Strong NOI (1) 2015 Highlights: Average Daily Production and Operating Costs Operating costs continue to decline Flat year over year production with minimal capital expenditures Significant free cash flow (2) generation in 2015 Drilled 10 net producers in 2015 boe/d 4,000 3,000 2,000 1, E $/boe 2016 Guidance: $5.0 million capital expenditures 2,770 boe/d production $17.24/boe operating cost Net Producing Hz Wells Drilled $ million Production Operating Cost Capital Expenditures and Net Operating Income E 1. Net operating income (NOI) is revenue less operating costs, royalties and transportation 2. Free cash flow is net operating income less capital expenditures Capital Expenditures Net Operating Income April

28 Coleville April

29 Coleville Viking 10,000 Acres in Proven Fairway Raging River Whitecap Novus Teine Ish Crescent Point Penn West Other Operators Company Land Smiley and Whiteside are expected to provide average peak production rates of 60 boe/d and greater With capital reductions and strong netbacks a 44% BT IRR can be provided at US$50/bbl WTI price Source: The Playbook: Ranking North America s Oil & Gas Plays Sixth Edition, September 2015, Scotiabank April

30 Coleville Development Opportunity One of the largest tight oil plays in western Canada NBRI drilled 48 wells from Jan 2014 to Dec 2015 ~650 boe/d estimated for 2016 ~$9.50 per boe operating costs estimated for 2016 Over $26.00 per boe field netback estimated for 2016 Opportunity to develop +300 locations 112 low risk drilling locations recognized in independent reserves report Source: The Playbook: Ranking North America s Oil & Gas Plays Sixth Edition, September 2015, Scotiabank Production (boe/d) Viking Oil NBRI Production Growth 3,000 2,500 2,000 1,500 1, Jan '14 Jan '15 Jan '16 Jan '17 Jan '18 Jan '19 Jan '20 Pre April

31 SAGD Plover North SAGD Plant A6P A3P A4P A5P A6I A5I A4I A3I April

32 SAGD Development Repeatable Opportunities Large oil in place Technology driven recovery Long life assets Huge upside potential Significant advantages from existing infrastructure Est DOIIP 176 mmbbls April

33 Plover North SAGD Cumulative Steam and Oil 250, ,000 Cumulative Oil, bbl 150, ,000 50, , , , , , , ,000 Cumulative Steam, bbl A3 A4 A5 A6 April

34 Analog Project/NBRI Comparison Recovery Factor (%) Steam Injection vs Recovery Factor A3 A4 A5 A6 Analog Well 1 Analog Well 2 Analog Well 3 Analog Well HCPV (m3/m3) Steam Injection vs Time A3 A4 A5 A6 Analog Well 1 Analog Well 2 Analog Well 3 Analog Well HCPV (m3/m3) Time (days) April

35 Saskatchewan SAGD Well Performance vs. Steam Rate 600 NBRI Plover Lake Pad A Baytex Kerrobert Baytex Kerrobert CNRL Senlac Pad CNRL Senlac Pad 2 CNRL Senlac Pad 3 CNRL Senlac Pad 4 CNRL Senlac Pad 5 2yr Average Steam Rate, sm3/d CNRL Senlac Pad 6 Husky Bolney Pad 33 Husky Bolney Pad 56 Husky Bolney Pad 06 Husky Bolney Pad 7S Husky Bolney Pad 7N Husky Celtic Pad 1 Husky Celtic Pad 2 Husky Celtic Pad 3 Husky Celtic Pad 4 Husky Celtic Pad 5 Husky Celtic Pad 6 Husky Celtic Pad Husky Celtic Pad 8 Husky Paradise Hill Pad 1 Husky Pikes Peak Pad 1 Husky Pikes Peak South Pad yr Average Oil Rate, bbls/d 1. Data sourced from Accumap and public company filings as at April 6, Husky Pikes Peak South Pad 2 Husky Pikes Peak South Pad 3 Husky Pikes Peak South Pad 4 Husky Pikes Peak South Pad 5 April

36 Corporate Information AUDITOR ENGINEERING CONSULTANTS INVESTOR CONTACTS KPMG LLP Ryder Scott Company Canada John Rooney, Chairman & CEO Michael Makinson, VP Finance & CFO 1900, Avenue SW, Calgary, AB T2P 4K9 (403) April