Delivering and Improving on the Five Year Plan

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2 Delivering and Improving on the Five Year Plan 2017 Achievements a a a a a a Downstream: increase heavy oil processing capacity Superior Refinery acquired November incremental FCF of $500MM Sunrise: 14 new well pairs tied in by year-end Indonesia: First production at BD Project in 2H/2017 Atlantic In-fill Program: Efficiencies in 2017 drilling leads to the acceleration of two 2018 wells in Q Liwan 29-1: Field sanctioned. Development to commence in First production in 2021 Thermal bitumen production growth: Edam Central and Westhazel thermal projects sanctioned. 2 x 10,000 bbls/day capacity on stream in 2021 Total of 60,000 bbls/day of to be developed and on stream by 2021 Key Metrics Investor Day Targets 2017F Production (mboe/day) F Delivery Status Funds from operations (FFO) 1 $3.3B $3.2-$3.3B Free cash flow (FCF) 1 $750M $900M Upstream operating cost/bbl $14.25 ~$14 Downstream realized margins/bbl (CAD) $15.00 ~$14 Earnings break-even oil price (US WTI) 2 ~$43.60 ~43 Cash break-even oil price (US WTI) 2 ~$33.50 ~33 Ranges and Targets Sustaining capital $1.8B $1.8B Capital spending 3,4 $2.5-$2.6B $2.2-$2.3B 5-year avg. proved reserve replacement ratio Target >130% >150+% Net debt to FFO 5 < 2x ~1.0x 1,2,3,4,5 see Slide Notes and Advisories a a a a r a a a a a a 2

3 Value Proposition Returns-focused growth Investing in a large inventory of low cost projects Low and improving earnings and cash break-evens Key Metrics 18F 21F Production (mboe/d) (7% CAGR) Funds from operations (FFO) 1 >$4B Free cash flow (FCF) 1 >$1B Upstream operating cost/bbl $ < $12 Upgrading & U.S refining operating costs ($CAD) $6 - $7 $6 - $7 Earnings break-even oil price (US WTI) ~$42 < $37 Cash break-even oil price (US WTI) ~$32 < $32 Strong growth in funds from operations and free cash flow Resilient to volatile market conditions while preserving upside Ranges and Targets 18F 17F - 21F Sustaining capital $1.8 - $1.9B Avg. $1.9B Capital expenditures $2.9 - $3.1B Avg. $3.3B Five-year avg. proved reserve replacement ratio _ Target >130% Net debt to FFO ~ 1.0 < 2x 1 see Slide Notes and Advisories 3

4 2018 Guidance Overview Funds from Operations ($ billion): > $4.0 Capital Spending ($ billion): $2.9 - $3.1 Free Cash Flow ($ billion): ~ $1.0 Production Range (mboe/day): % YoY increase Downstream Throughputs (mbbls/day): % YoY increase Operating Costs ($/boe) $ $ % YoY decrease Price Assumptions WTI ($US/bbl) $55 Chicago 321 Crack (US$/bbl) $15.00 AECO Natural Gas ($/mmcf) $2.50 Fx CAD/USD Production by Business Segment 21% Thermal Operations Asia Pacific Gas & NGLs 40% Canadian Gas 11% Atlantic Oil Non thermal heavy, medium, light, NGLs 15% 14% 2018 Capital Spending By Business Segment 30% Thermal Operations 3% Atlantic Oil Non thermal heavy, medium, light, NGLs 25% Asia Pacific Gas & NGLs 25% Resource Gas Downstream 7% 5% 5% Corporate 4

5 2018 Capital Program Self Funding at $50 US WTI ~$450 Million Free Cash Flow at $50 US WTI, ~$1 Billion Free Cash Flow at $55 US WTI 2018 FFO and Capital Spending 4.5 $ billions ~ $1 Billion FCF FCF FFO Portfolio Investment Downstream Sustaining Capital Upstream Sustaining Capital F F US$50 WTI F US$55 WTI 2 1, 2 see Slide Notes and Advisories 5

6 Five-Year Plan Milestones All Projects On / Ahead Schedule 6

7 Returns-Focused Growth New Project Hurdle of >10% IRR at Flat $45 US WTI and/or Flat $2.50 AECO Atlantic Infill Well (2) Atlantic Infill Well (2) Atlantic Infill Well (2) Atlantic Infill Well (2) Sunrise - Debottleneck 2 Tucker D West Sustaining Pad - Thermal Sunrise - Debottleneck 1 CHOPS - Optimization Rush Lake 2 (10 mb/d) Dee Valley (10 mb/d) Spruce Lk North (10 mb/d) Spruce Lk Central (10 mb/d) Heavy Oil - Horizontal Edam Central (10 mb/d) Westhazel (10 mb/d) Lloyd Thermal (10 mb/d) Lloyd Thermal (10 mb/d) Lloyd Thermal (10 mb/d) Lloyd Thermal (10 mb/d) Lloyd Thermal (10 mb/d) Lloyd Thermal (10 mb/d) Sunrise - Debottleneck 3 West White Rose Lloyd Thermal (5 mb/d) Lloyd Thermal (5 mb/d) Lloyd Thermal (5 mb/d) Lloyd Thermal (5 mb/d) Lloyd Thermal (5 mb/d) Lloyd Thermal (5 mb/d) Heavy Oil - Cold EOR Sunrise East - A (20 mb/d) Sunrise East - B (20 mb/d) Sunrise East - C (20 mb/d) Sunrise East - D (20 mb/d) Sunrise South - A (20 mb/d) Sunrise South - B (20 mb/d) Heavy Oil - CHOPS McMullen Thermal McMullen Thermal McMullen Thermal McMullen Thermal Kakwa (Wilrich) Ansell (Wilrich) MDA (Madura) MBH (Madura) Liuhua 29-1 MDK (Madura) Madura Dry Gas Asphalt Expansion COF (Lima) Capital Spending 17-21F $16B $80 $60 Price Required to Generate 10% IRR Oil Portfolio 1 (WTI US $/bbl) Gas Portfolio 1,2 ($/mcf ) Asia Pacific Gas ($US) $10 $8 Downstream Portfolio 3 (IRR) Short to Medium Cycle 2/3 Of Planned Capital Spend $40 $20 WTI US $45/bbl Canadian Gas ($ Cdn.) $6 $4 $2 10% $0 $0 0% Project Inventory Projects Included Plan Spending Period WTI Oil Price 1,2,3,4 see Slide Notes and Advisories 7 4

8 Capital Investment Lowers Cost Structure Costs Down Netbacks And Margins Up $/boe Upstream Operating Costs 17-21F 17% 30 Upstream Operating Netbacks 1 $/boe 17-21F 23% '17F '18F '19F '20F '21F 2017 Operating Netback Asset Improvement Commodity Price Impact $/bbl Downstream Margins 17-21F 12% '17F '18F '19F '20F '21F 10 1 see Slide Notes and Advisories '17F '18F '19F '20F '21F 2017 Margin Asset Improvement Commodity Price Impact 8

9 Capital Investment Lowers Cost Structure Improving Break-Even Oil Price and Sustaining Capital Requirements Break-Evens Sustaining Capital vs. Production 45 $US WTI 3.0 $B 400 Sustaining Capital 17-21F ~$1.9B Annual Average 40 mboe/d Upstream Sustaining Cost/Boe 17-21F ~$11 Annual Average Cash Break-Even 17-21F ~$32 (US WTI) Annual Average '17F '18F '19F '20F '21F 0.0 '17F '18F '19F '20F '21F 200 Earnings Break-Even Cash Break-Even Total Sustaining Capital Daily Production (mboe/d) 9

10 Healthy Balance Sheet Net Debt 8 $B Net debt of $3.0 billion (Q3 17) '15 '16 '17F '18F - '21F Net Debt to Trailing FFO 1 5 times Husky A B Peer CGroup D E Liquidity $4.0B $2.5B As at Sept 30, 2017 undrawn credit facilities cash & cash equivalents Debt Maturity Schedule $1.4 $ billions $1.2 $1.0 $0.8 $0.6 $0.4 $0.2 $0.0 '18 '19 '20 '21 '22 '23 '24 '25 '26 '27 '37 USD Bonds ($/US$) CAD Bonds ($) Preferred Shares ($) 1,2 see Slide Notes and Advisories 2 Credit Ratings Moody s Baa2 ; Stable S&P BBB+; Stable DBRS A (low); Stable 10

11 Strong Focus on Safety and ESG 6.0 Safety Performance Critical & Serious Incidents # per 200K hours worked ESG Performance and Ratings Results Disclosure '10 '11 '12 '13 '14 '15 ' Total Recordable Incident Rate # per 200K hours worked '10 '11 '12 '13 '14 '15 '16 Rigorous emissions controls in all operations Leading developments of carbon capture and injection technology Supplying low CO 2 intensity natural gas for power generation in Asia, displacing coal 11

12 Two Businesses Integrated Corridor Offshore Resource Plays Thermal Asia Pacific Downstream Atlantic 12

13 Rob Symonds Chief Operating Officer

14 Integrated Corridor Unique and Physically Integrated Assets Production (Q3 17) 248 mboe/d 117 mboe/d thermal bitumen Sunrise 20 mboe/d Tucker 21 mboe/d Lloyd Upgrader Sunrise Thermal Lloyd & Tucker Thermal Asphalt Refinery Superior Refinery Lloyd 76 mboe/d Reserves Base (YE 16) 2.4 billion boe of proved and probable reserves Heavy Processing Capacity (Q3 17) 160 mbbls/d Finished Products (Q3 17) 54 mbbls/d of sweet synthetic oil 16 mbbls/d of asphalt 107 mbbls/d of diesel / distillates 137 mbbls/d of gasoline Hardisty & Lloyd Storage Terminals Gathering System Long-term Pipeline Capacity Lima Refinery Toledo Refinery 14

15 Growing/Expanding the Integrated Corridor Reservoir to Refined Products Heavy Oil & Thermal Bitumen Production (boe/day) Q3 ' F Lloyd thermal 76, ,000 Tucker 21,100 30,000 Sunrise 20,200 37,000 Non-thermal (heavy oil) 49,900 29,000 Total 167, ,000 Thermal bitumen as % of total 70% 87% Western Canada Production (boe/day) Q3 ' F Resource plays 30,000 50,000 Other W. Canada production 49,900 30,000 Total 79,900 80,000 Resource plays as % of total 38% 63% Downstream Throughputs Capacity (bbls/day) Q3 ' F Heavy oil processing capacity 1 160, ,000 Light oil processing capacity 1 190, ,000 Total upgrading and refining capacity 1 350, ,000 Heavy oil capacity as % of total 46% 56% Sunrise Production Growth 30 mbbls/day F 2018E Tucker Production Growth 30 mbbls/day F 2018E 1 see Slide Notes and Advisories 15

16 Downstream Connectivity Downstream assets offer optionality of feedstock, product mix and distribution markets Bitumen and Heavy Oil Growth matched with Heavy Oil Processing Capacity 1, mbbls/d '18F '19F '20F Upstream Heavy Oil Blend Downstream Heavy Oil Blend Throughput Capacity Integration of over 85% of heavy oil produced Mitigates exposure to light / heavy differentials 1, 2 see Slide Notes and Advisories 16

17 Lloyd Advantage Full Value Chain Netback Low cost thermal production Low cost refining and upgrading Higher value, more diverse basket of finished products 1,2 Higher finished product yield (98%) Extensive local market demand Lloyd Value Chain Operating Netback 3 (per bbl) Lloyd complex avg. realized price $64.98 Operating costs $14.10 Royalties $2.83 Transportation costs $2.81 Lloyd complex avg. processing costs $7.41 Est. Lloyd Value Chain Operating Netback $37.83 Actual Upstream Operating Netback $22.46 * All figures as Q Includes Lloyd thermal, non-thermal and Tucker thermal production $15.37 (per bbl) Additional Netback From Integrated Operations 1,2,3 see Slide Notes and Advisories 17

18 Sunrise to Toledo One-Step Refining, No Upgrading Required Toledo high-tan project added processing capacity for all Sunrise crude Dilbit delivered directly to Toledo no upgrading cost, no volume lost High finished product yield (~104% in Q3 17) 1,2 Sunrise Value Chain Operating Netback (per bbl) Full Capacity Toledo realized product price (Q3 '17) $77.82 Expected Sunrise operating costs (at full capacity) ~ $12.00 Royalties ~ $0.50 Typical blending cost ~ $8.00 Typical transportation cost ~ $14.00 Typical Midwest refining cost ~ $8.00 Illustrative Sunrise Value Chain Operating Netback $35.32 Sunrise Upstream Operating Netback (at full capacity) $19.63 ~$15.00 (per bbl) Additional Netback From Integrated Operations * Full Capacity reflects estimates of cost at Sunrise plant capacity of 60,000 bbls/day 1,2 see Slide Notes and Advisories 18

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20 Asia Pacific High operating netback production Fixed-price contracts at favourable prices Cumulative Free Cash Flow Generated 17-21F $4.2B Liwan: $13.05 per mcf BD: $9.50 per mcf Free Cash Flow Growth 1.5 $ billion $ billion 4.5 Q operating netback of $61.81/boe Low level of investment required for growth over the five-year plan ($0.9 B) Defined growth for next 5 years Current gas production of 200 mmcf/day with 8,000 boe/day of liquids Production to rise to over 270 mmcf/day of gas with 9,000 boe/day of liquids by 21 Mix of near, mid and long-term development and exploration opportunities 0.0 (0.5) 0.0 (1.5) '17F '18F '19F '20F '21F Funds From Operations Capital Spending Cumulative FCF 20

21 Low Volatility Growth In Asia Pacific Fixed Price Gas Projects In Growing Gas Demand Regions Liwan 3-1, Liuhua 34-2 & 29-1 (China) Current production of ~170 mmcf/d (3-1 & 34-2) Take-or-pay contract mmcf/day (net) Full project payout forecast in 18 Liuhua 29-1 field sanctioned, first gas in 2021 Development plan to utilize subsea infrastructure Gas sales agreement reached Exploration cost recovery BD Project (Madura Strait, Indonesia) Gas sales began in July, initial liquids lifting in October Peak: 40 mmcf/day gas, 2,400 bbls/day liquids (net) MBA-MDH, MDK Fields (Madura Strait, Indonesia) First gas in 2019, Peak: 60 mmcf/day gas (net) Seven development wells planned for 2018 Five-Year Production Profile mmcfe/d Production Growth >50% 0 '17F '18F '19F '20F '21F Wenchang Liwan 3-1, Liuhua 34-2 Liuhua 29-1 Liuhua 29-1 Cost Recovery BD (Indonesia) MDA-MBH & MDK (Indonesia) 21

22 Fixed Price Contracts Provide FFO Stability High Asian Gas Prices Deliver $60+ per boe Operating Netbacks Asia Pacific Realized Gas Price High Operating Netback $Cdn/mcf $Cdn/boe Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 0 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 0 '14 '15 '16 '17 '15 '16 '17 Husky Realized Asia Gas Price AECO gas benchmark 1 see Slide Notes and Advisories Asia Pacific Netback Brent Oil 22

23 Atlantic Canada Proven Track Record: Long history of operations in region High operating netback production $35.86 per boe operating netback (Q3 17) Production receives Brent+ pricing Mizzen Bay du Nord Bay de Verde Harpoon Baccalieu Investment economics enhanced through tiebacks to existing infrastructure Defined growth into next decade Exploration upside opportunities Northwest White Rose Hibernia Hebron White Rose Terra Nova 23

24 Next Stages of Atlantic Growth Short, Mid and Long Cycle Projects Project South White Rose Extension infill wells Project Capital To First Production ~$70M per well Net Peak Production ~4,500 bbls/day per well After-Tax IRR 1 Plan Pricing Assumption >30% Atlantic Production Profile 80 mbbls/d Future Field Extension Opportunities West White Rose ~$2.2B ~52,500 bbls/day ~17% West White Rose 20 Infill and Development Wells White Rose Base Production Terra Nova 0 '17F '18F '19F '20F '21F '22F '23F '24F '25F '26F 1 see Slide Notes and Advisories 24

25 Value Proposition Returns-focused growth Investing in a large inventory of low cost projects Low and improving earnings and cash break-evens Key Metrics 18F 21F Production (mboe/d) (7% CAGR) Funds from operations (FFO) >$4B Free cash flow (FCF) >$1B Upstream operating cost/bbl $ < $12 Upgrading & U.S refining operating costs ($CAD) $6 - $7 $6 - $7 Earnings break-even oil price (US WTI) ~$42 < $37 Cash break-even oil price (US WTI) ~$32 < $32 Strong growth in funds from operations and free cash flow Resilient to volatile market conditions while preserving upside Ranges and Targets 18F 17F - 21F Sustaining capital $1.8 - $1.9B Avg. $1.9B Capital expenditures $2.9 - $3.1B Avg. $3.3B Five-year avg. proved reserve replacement ratio _ Target >130% Net debt to FFO ~ 1.0 < 2x 25

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27 Slide Notes Slide 2 1. Funds from operations and free cash flow, as referred to throughout this presentation, are non-gaap measures. Please see Advisories for further detail. 2. Earnings break-even and cash break-even prices, as referred to throughout this presentation, are non-gaap measures. Please see Advisories for further detail. 3. Capital spending, as referred to throughout this presentation, excludes asset retirement obligations and capitalized interest unless otherwise indicated. 4. Capital expenditures in Asia Pacific exclude amounts related to the Husky- CNOOC Madura Ltd. joint venture, which is accounted for under the equity method for financial statement purposes. 5. Net debt and net debt to funds from operations, as referred to throughout this presentation, are non-gaap measures. Please see Advisories for further detail. Slide 3 1. Funds from operations and free cash flow forecast for 2018 based on WTI price of $55 US per barrel, CAD$2.50/mmbtu gas price, 0.78 US/CAD exchange rate and US$15 Chicago crack spread. Slide 5 1. Funds from operations and free cash flow forecast for 2018 based on WTI price of $50 US per barrel, CAD$2.50/mmbtu gas price, 0.78 US/CAD exchange rate and US$15 Chicago crack spread. 2. Funds from operations and free cash flow forecast for 2018 based on WTI price of $55 US per barrel, CAD$2.50/mmbtu gas price, 0.78 US/CAD exchange rate and US$15 Chicago crack spread. Slide 7 1. Other than as indicated in the Advisories, 10% IRR calculations are based on proved and probable reserves. 2. Gas portfolio break-even prices include assumed associated liquids prices based on a US$40 WTI price scenario. 3. Downstream portfolio IRR is not directly tied to oil or gas price. See Advisories for further detail. 4. Projects Included in Plan Spending Period reflect projects that the Company will allocate capital spending to during the timeframe. Slide 8 1. Upstream operating netback, as referred to throughout this presentation, is a non-gaap measure. Please see Advisories for further detail. Slide Net debt to trailing funds from operations, as referred to throughout this presentation, is a non-gaap measure. Please see Advisories for further detail. All figures as of September 30, Husky has redemption option on Preferred Shares. Slide Includes acquisition of the Superior Refinery, which closed in Q

28 Slide Notes Slide Production volumes represent blended heavy oil volumes (bitumen, heavy oil and diluent). 2. Throughput represents Husky s 100% interest in the heavy processing capacity at the Prince George Refinery, Lloydminster Refinery, Lloydminster Upgrader, Lima Refinery, Superior Refinery and 50% interest in the Toledo Refinery. Slide Product variability can be influenced by several factors, including seasonal demand, access to feedstock and distribution system interruptions, among others. 2. Products include Husky Synthetic Blend, asphalt and Ultra Low Sulphur Diesel (ULSD), among others. 3. Value chain operating netback, as referred to throughout this presentation, is a non-gaap measure. Please see Advisories for further detail. Slide Product variability can be influenced by several factors, including seasonal demand, access to feedstock, distribution system interruptions, among others. 2. Products include gasoline, distillate, Ultra Low Sulphur Diesel (ULSD), propane, benzene, Sulfur, LPG, LVGO, HVGO, heavy fuels, petro-chemicals and various other by-products. Slide Q Operating Netback reflects the impact of a price adjustment for natural gas from the Liwan 3-1 and Liuhua 34-2 fields, per the Heads of Agreement ("HOA") signed by the Company with CNOOC Limited in Q The price adjustment under the HOA is effective as of November 2015 and a retroactive adjustment was recognized in Q Slide After-Tax IRRs are calculated using Price Planning Assumptions as shown on slide 33 and, other than as indicated in the Advisories, are based on proved and probable reserves. Slide Capital expenditures include exploration capital in each business unit. 2. Asia Pacific oil & NGLs operating costs and capital expenditures reflected in Asia Pacific natural gas. 3. Capital expenditures in Asia Pacific exclude amounts related to the Husky- CNOOC Madura Ltd. joint venture, which is accounted for under the equity method for financial statement purposes. 4. Downstream capital expenditures include scheduled turnarounds. 5. Lloyd and Tucker thermal operating costs include energy and non-energy costs. 6. Downstream operating costs excludes the impact of scheduled turnarounds in Slide Husky has a 50% working interest in the Toledo Refinery. 28

29 Advisories Forward-looking Statements and Information Certain statements in this presentation, including "financial outlook", are forward-looking statements and information (collectively "forward-looking statements"), within the meaning of the applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The forward-looking statements contained in this presentation are forward-looking and not historical facts. Some of the forward-looking statements may be identified by statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as "will likely result", "are expected to", "will continue", "is anticipated", "is targeting", "estimated", "intend", "plan", "projection", "could", "aim", "vision", "goals", "objective", "target", "schedules" and "outlook"). In particular, forward-looking statements in this presentation include, but are not limited to, references to: with respect to the business, operations and results of the Company generally: the Company s general strategic plans and growth strategies; forecasted production, FFO, FCF, upstream operating cost per barrel, downstream realized refining margins/bbl, earnings break-even oil price and cash break-even oil price for 2017, 2018 and by 2021 and range and targets for sustaining capital, capital spending, five-year average proved reserve replacement ratio and net debt to FFO from 2017 to 2021; forecast production compound annual growth rate from 2018 to 2021; forecast downstream throughputs for 2018 and 2021; forecast 2018 production by business unit and 2018 capital spending by region; forecast 2018 FCF, FFO, portfolio investment and sustaining capital at US$50 WTI and US$55 WTI per barrel; forecast 2018, 2019 and 2020 heavy oil processing capacity; forecast production from the Company s Integrated Corridor in 2021; forecast sustaining capital and annual average for 2017 to 2021, including annual average upstream sustaining cost per boe, sustaining capital and cash break-even for such period; forecast net debt for the period from 2017 to 2021; forecast break-evens for the years 2017 to 2021; five-year plan milestones in respect of the Company s Integrated Corridor and Offshore projects; capital spending for the years 2017 to 2021; forecast upstream operating costs, upstream operating netbacks and downstream margins for 2017 to 2021; Integrated Corridor and Offshore FFO generation and cash capital less asset retirement obligations at flat $50 US WTI for the years 2017 to 2021; forecast FFO, sustaining capital, discretionary capital and net debt to FFO assuming $35 US WTI for 2017 and 2021; forecast thermal, non-thermal and Western Canada production for 2021, broken down by thermal project; prices required to generate targeted IRR for the Company s listed in-flight and future projects; and total spending for in-flight and future projects and percentage spent in short to mid-cycle; with respect to the Company's thermal developments in the Integrated Corridor: Sunrise plant capacity; expected Sunrise operating costs at full capacity; and forecast Sunrise and Tucker production growth for 2017 and 2018; with respect to the Company's Offshore business in Asia Pacific region: forecasted FFO, capital spending and FCF for the years 2017 to 2021; expected production in 2021; five-year production profile for Wenchang, Liwan 3-1 and Liuhua 34-2, Liuhua 29-1, Liuhua 29-1 Cost Recovery, BD (Indonesia) and MDA-MBH & MDK (Indonesia); and expected timing for full project payout for Liwan 3-1 and Liuhua 34-2 and 29-1; and with respect to the Company's Offshore business in the Atlantic region: after-tax IRR, capital and peak production at the South White Rose extension infill wells and West White Rose; and 10-year production profile for the region broken down by project. 29

30 Advisories In addition, statements relating to "reserves" "and" "resources" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves or resources described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of reserves and resources and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from reserve, resource and production estimates. Certain of the information in this presentation is financial outlook within the meaning of applicable securities laws. The purpose of this financial outlook is to provide readers with disclosure regarding the Company s reasonable expectations as to the anticipated results of its proposed business activities. Readers are cautioned that this financial outlook may not be appropriate for other purposes. Although the Company believes that the expectations reflected by the forward-looking statements presented in this presentation are reasonable, the Company s forward-looking statements have been based on assumptions and factors concerning future events, including timing of regulatory approvals, that may prove to be inaccurate. Those assumptions and factors are based on information currently available to the Company about itself and the businesses in which it operates. Information used in developing forward-looking statements has been acquired from various sources including third party consultants, suppliers, regulators and other sources. Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to Husky. The Company s Annual Information Form for the year ended December 31, 2016 and other documents filed with securities regulatory authorities (accessible through the SEDAR website and the EDGAR website describe risks, material assumptions and other factors that could influence actual results and are incorporated herein by reference. New factors emerge from time to time and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon management s assessment of the future considering all information available to it at the relevant time. Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. 30

31 Advisories Non-GAAP Measures This presentation contains certain terms which do not have any standardized meanings prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other issuers. None of these measurements are used to enhance the Company's reported financial performance or position. With the exception of funds from operations and free cash flow, there are no comparable measures to these non-gaap measures in accordance with IFRS. The following non-gaap measures are considered to be useful as complementary measures in assessing Husky's financial performance, efficiency and liquidity: "Funds from operations" or "FFO" is a non-gaap measure which should not be considered an alternative to, or more meaningful than, "cash flow operating activities" as determined in accordance with IFRS, as an indicator of financial performance. Funds from operations is presented in the Company s financial reports to assist management and investors in analyzing operating performance by business in the stated period. Funds from operations equals cash flow operating activities plus items not affecting cash, which include settlement of asset retirement obligations, deferred revenue, income taxes received (paid), interest received and change in non-cash working capital. "Free cash flow" or "FCF" is a non-gaap measure which should not be considered an alternative to, or more meaningful than, "cash flow operating activities" as determined in accordance with IFRS, as an indicator of financial performance. Free cash flow is presented in this presentation to assist management and investors in analyzing operating performance by business in the stated period. Free cash flow equals funds from operations less capital expenditures. "Net debt" is a non-gaap measure that equals total debt less cash and cash equivalents. Total debt is calculated as long-term debt, long-term debt due within one year and short-term debt. Net debt is considered to be a useful measure in assisting management and investors to evaluate the Company's financial strength. "Net debt to funds from operations" is a non-gaap measure that equals net debt divided by funds from operations. Net debt to funds from operations is considered to be a useful measure in assisting management and investors to evaluate the Company's financial strength. "Net debt to trailing funds from operations" is a non-gaap measure that equals net debt by the 12-month trailing funds from operations as at September 30, Net debt to trailing funds from operations is considered to be a useful measure in assisting management and investors to evaluate the Company's financial strength. Upstream operating netback" is a common non-gaap metric used in the oil and gas industry. This measure assists management and investors to evaluate the specific operating performance by product at the oil and gas lease level. Upstream operating netback is calculated as realized price less royalties, operating costs and transportation costs on a per unit basis. 31

32 Advisories Value chain operating netback" is a non-gaap metric used in the oil and gas industry. This measure assists investors to evaluate the operating performance of the Integrated Corridor. Value chain operating netback is calculated as an average realized price of synthetic crude and other refined products less royalties, operating costs, transportation costs and processing costs on a per unit basis. "Earnings break-even" reflects the estimated WTI oil price per barrel priced in US dollars required in order to generate a net income of Cdn $0 over a 12-month period ending December 31. This assumption is based on holding several variables constant throughout the period, including: foreign exchange rate, light-heavy oil differentials, realized refining margins, forecast utilization of downstream facilities, estimated production levels, and other factors consistent with normal oil and gas company operations. Earnings break-even is used to assess the impact of changes in WTI oil prices on the net earnings of the Company and could impact future investment decisions. "Cash break-even" reflects the estimated WTI oil price per barrel priced in US dollars required in order to generate funds from operations equal to the Company s sustaining capital requirements in Canadian dollars over a 12-month period ending December 31. This assumption is based on holding several variables constant throughout the period, including: foreign exchange rate, light-heavy oil differentials, realized refining margins, forecast utilization of downstream facilities, estimated production levels, and other factors consistent with normal oil and gas company operations. Cash break-even is used to assess the impact of changes in WTI oil prices on the net earnings of the Company and could impact future investment decisions. Disclosure of Oil and Gas Information Unless otherwise indicated: (i) reserves and resources estimates in this presentation have been prepared by internal qualified reserves evaluators in accordance with the Canadian Oil and Gas Evaluation Handbook, have an effective date of December 31, 2016 and represent the Company's working interest share; (ii) projected and historical production volumes provided represent the Company s working interest share before royalties; and (iii) historical production volumes provided are for the year ended December 31, The Company has disclosed its total reserves in Canada in its Annual Information Form for the year ended December 31, 2016, which reserves disclosure is incorporated by reference in this presentation. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. IRR calculations shown in this presentation are based on holding several variables constant throughout the period, including estimated WTI oil price per barrel priced in US dollars, foreign exchange rate, light-heavy oil differentials, realized refining margins, forecast utilization of downstream facilities, estimated production levels, and other factors consistent with normal oil and gas company operations. This measure is used to assess potential return generated from investment opportunities and could impact future investment decisions. This measure does not have any standardized meaning and should not be used to make comparisons to similar measures presented by other issuers. IRR calculations in this presentation are based on proved and probable reserves, except for the IRR calculations for the projects described below, in which cases the IRR calculations are based on resources. 32

33 Advisories Husky s Lloydminster Heavy Oil and Gas thermal bitumen unrisked best estimate contingent resources consist of 268 million barrels of economic development pending, 164 million barrels of economic development unclarified and 554 million barrels of economic status undetermined development unclarified. The figures represent Husky s working interest volumes. The development pending category consists of 11 steam assisted gravity drainage (SAGD) projects and one combined SAGD and cyclic steam stimulation (CSS) project that have been scheduled for initial production starting in 2019 through to The first three projects have a total capital cost to first production of $1.1 billion based upon the pre-development studies. The estimated total capital to fully develop these 12 development pending projects is approximately $8 billion. The economic and economic status undetermined development unclarified projects require additional technical and commercial analysis of the conceptual SAGD or CSS studies. Of these, the first project requires $0.4 billion to achieve commercial production in The remaining projects are to be developed over more than 50 years in accordance with the conceptual studies for this large resource. In total, 311 million barrels of thermal bitumen are based upon pre-development studies while an additional 675 million barrels of thermal bitumen are based upon conceptual plans. This oil is reported as thermal bitumen and has viscosities ranging from 12,800 centipoise (cp) to as high as 600,000 cp with gravities between 9 and 12 degrees API. Specific contingencies preventing the classification of contingent resources at the Company s Lloydminster Heavy Oil thermal contingent resources as reserves include the need for further reservoir studies, delineation drilling, verification of sub-zone continuity and quality that would enable feasible implementation of a thermal scheme, the formulation of concrete development plans and facility designs to pursue development of the large inventory of opportunities, the Company s capital commitment, development over a time frame much greater than the reserve timing window and regulatory applications and approvals. Positive and negative factors relevant to the contingent resource estimates include potential reservoir heterogeneity in sub-zones which may limit the applicability of thermal schemes, a higher level of uncertainty in the estimates as a result of lower drilling density in some projects and current lack of development plans in the unclarified contingent resources. The main risks are the low well density and the associated geological uncertainties in certain projects, the production performance and recovery long term, future commodity prices and the capital costs associated with wells and facilities planned over an extended future period of time. McMullen contains unrisked best estimate economic development pending contingent resources of 44 million barrels of bitumen for Phase 1 of the development with a further 1.3 billion barrels of bitumen of unrisked best estimate economic status undetermined development unclarified contingent resources. McMullen is a thermal play in the Wabiskaw formation covering over 130 sections southwest of Wabasca. Husky has a working interest of 100 percent. The cost to first production for Phase 1, based upon the pre-development study, is approximately $452 million for the initial commercial demonstration facility and horizontal cyclic steam stimulation (HCSS) wells in The results of the commercial demonstration will be utilized to refine the subsequent phases that are based upon a conceptual development plan at this time and each has the same capital estimate with initial production scheduled for 2028 for Phase 2. The total commercial facilities and wells will be developed over more than 50 years at an estimated total cost of $40 billion in accordance with the conceptual study for this large resource. The development of these projects depends on the results of the technical analysis, future bitumen prices and the Company s commitment to dedicate capital to this large inventory of projects. Specific contingencies preventing the classification of contingent resources at the McMullen thermal development project as reserves include the need for further reservoir studies, delineation drilling, facility design, preparation of firm development plans, regulatory applications and approvals and Company approvals. Positive and negative factors relevant to the estimates of these resources include a higher level of uncertainty in the estimates as a result of lower core-hole drilling density. The main risks are the low well density and the associated geological uncertainties, the production performance and recovery long term and the capital costs associated with wells and facilities planned over an extended future period of time. 33

34 Advisories The Ansell liquids-rich natural gas resource play is located in the deep basin Cretaceous formations of west-central Alberta, and Husky has an average 92 percent working interest. Husky is actively developing Ansell. This producing property contains unrisked best estimate economic development pending contingent resources of 248 million barrels of oil equivalent, consisting of 1.4 Tcf of natural gas and 14 million barrels of natural gas liquids (NGL). Ansell also includes unrisked best estimate economic development on hold contingent resources of 174 million barrels of oil equivalent from the Cardium formation, consisting of 0.8 Tcf of natural gas and 35 million barrels of NGL from approximately 300 potential drilling opportunities. The initial contingent resource fracture stimulated horizontal wells are scheduled to be drilled starting in 2024, following the development of the proved and probable reserves. The cost to achieve initial commercial production is the cost of the first well of $4.5 million. The remaining development pending drilling opportunities (259 working interest) will be drilled over the next 10 to 20 years in accordance with the pre-development study for the resource play. Specific contingencies preventing the classification of contingent resources in the Ansell liquids-rich resource play as reserves include the timing of development which is outside the timing allowed for booking as reserves and final Company approvals of capital expenditures. Positive and negative factors relevant to the estimate of Ansell contingent resources include a lower level of uncertainty in the estimates as a result of the large number of producing wells, extensive production history from the property, Husky s large contiguous land base and Husky s ownership of existing infrastructure in the area. Key risks include the performance of future wells when the play is expanded and reducing costs to achieve optimal results in a low gas and NGL price environment. Liuhua 29-1, located in the South China Sea approximately 300 km southeast of the Hong Kong Special Administrative Region, contains unrisked best estimate economic development pending contingent resources of 28 million barrels of oil equivalent, consisting of 139 Bcf of natural gas and 5 million barrels of condensate. Husky has a working interest of 49 percent. The project uses conventional offshore gas wells and will be connected to the producing Liwan gas field. Based on the pre-development study, the cost to first production to complete and tie-in the well is approximately $650 million with an on-stream date in The development of this project depends on the Company's and its partners commitment to dedicate capital to the project. Specific contingencies preventing the classification of contingent resources for Liuhua 29-1 are the signing of a gas sales agreement and regulatory approvals. Positive and negative factors relevant to the estimates of these resources include a higher level of certainty in the estimates as a result of extensive appraisal drilling and testing. The main risk is the production performance and recovery long term. Husky's Lloydminster Heavy Oil cold heavy oil production with sand (CHOPs) and Horizontal well opportunity includes 189 million barrels (Husky s working interest) of unrisked economic best estimate contingent resources in the development pending sub-class and a further 593 million barrels (Husky s working interest) of unrisked best estimate contingent resources in the development unclarified sub-class with the economic status undetermined. A typical CHOPS well has a cost estimate to drill, complete and equip of $580,000, while a five-well horizontal pad has a cost estimate of $7.1 million with the first developments online in 2026 based on a pre-development study. This is a continuation of the CHOPs and horizontal well development programs which have been proven to be successful in the Lloydminster area. The timing of development and Company approvals are the main contingencies preventing the booking of these volumes as reserves. Positive and negative factors relevant to these contingent resources include a lower level of uncertainty in the estimates as a result of the large number of producing wells, extensive production history from the property, Husky's large contiguous land base and Husky's ownership of existing infrastructure in the area. The key risk is the execution of a multiyear program and reducing capital and operating costs in a low heavy oil price environment. 34

35 Advisories Heavy Oil Cold EOR, located in the Lloydminster area, contains 307 million barrels (Husky s working interest) of unrisked economic status undetermined best estimate contingent resources in the development unclarified sub-class. Cold EOR Solvent Injection is a cyclic process utilizing CO2 which has been demonstrated to be technically successful in the area. The wells and area have been identified in the conceptual development study, but more detailed development plans are required for each field. The first phase of the projects is planned for 2021 with a capital cost of $207 million to reach first oil production in one of the identified fields. The timing of development, regulatory and Company approvals are the specific contingencies preventing the booking of these volumes as reserves as well as the need for additional assessment for the area where the economic status is undetermined. Positive and negative factors include the extensive land base and infrastructure while the ultimate recovery for this technology is still being evaluated in the field. Key risks include the range of uncertainty in the ultimate recovery and accessing a long term supply of CO 2 for the projects. The Company uses the term "barrels of oil equivalent" (or "boe") and "thousand cubic feet of gas equivalent" (or "mcfe"), which are consistent with other oil and gas companies disclosures. Boe amounts have been calculated by using the conversion ratio of 6 mcf of natural gas to 1 bbl of oil and mcfe amounts have been calculated by using the conversion ratio of 1 bbl of oil or NGL to 6 mcf of natural gas. A boe conversion ratio of 6 mcf: 1 bbl and an mcfe conversion ratio of 1 bbl: 6 mcf are based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent value equivalency at the wellhead. Readers are cautioned that the terms boe and mcfe may be misleading, particularly if used in isolation. "Sustaining cost per boe" is the additional development capital that is required by the business to maintain production and operations at existing levels on a per unit basis. It is calculated as sustaining capital divided by EUR. Sustaining cost per boe does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers. The Company uses the term "reserve replacement ratio", which is consistent with other oil and gas companies disclosures. Reserve replacement ratios for a given period are determined by taking the Company's incremental proved reserve additions for that period divided by the Company's upstream gross production for the same period. The reserve replacement ratio measures the amount of reserves added to a company's reserve base during a given period relative to the amount of oil and gas produced during that same period. A company's reserve replacement ratio must be at least 100 percent for the company to maintain its reserves. The reserve replacement ratio only measures the amount of reserves added to a company's reserve base during a given period. EUR (estimated ultimate recovery) estimates referred to in this presentation have been prepared by internal qualified reserves engineer and in accordance with COGEH. EUR reflects the unrisked proved plus profitable estimate. Note to U.S. Readers The Company reports its reserves and resources information in accordance with Canadian practices and specifically in accordance with National Instrument Standards of Disclosure for Oil and Gas Activities, adopted by the Canadian securities regulators. Because the Company is permitted to prepare its reserves and resources information in accordance with Canadian disclosure requirements, it may use certain terms in that disclosure that U.S. oil and gas companies generally do not include or may be prohibited from including in their filings with the SEC. All currency is expressed in Canadian dollars unless otherwise directed. 35

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37 2018 Guidance Planning Assumptions Updated December 4, 2017 Upstream Capital Expenditures 1 Production Corporate Costs ($ millions) Upstream Operating Costs ($/bbl) Oil and Liquids ($ millions) (mbbls/day) Corporate Capital Lloyd and Tucker thermal Lloyd & Tucker thermal bitumen Total Capital Budget 2,940-3,125 Atlantic Region light oil Sunrise thermal bitumen ($/mcfe) Lloyd Non-Thermal Other ($ millions) Resource Play Natural Gas Atlantic light Capitalized Interest Asia Pacific Region Gas W. Canada Light, medium, heavy & NGL Corporate SG&A Asia Pacific light & NGLs 2, Total Crude Oil and Liquids 1,785-1, Sustaining Capital ($ millions) Total Upstream Operating Costs Upstream 1,275-1,325 Natural Gas ($ millions) (mmcf/day) Downstream Downstream Operating Costs 6 ($/boe) Canada Total Sustaining Capital 1,775-1,875 Lloyd Upgrader Asia Pacific US Refineries Total Natural Gas ($ millions) (mboe/day) Total Upstream 2,130-2, ($/boe) Throughput Pricing Assumptions Downstream ($ millions) (mbbls/day) WTI, Cushing ($US/bbl) Canada downstream Chicago Crack ($US/bbl) U.S. downstream Natural Gas, AECO ($Cdn/mcf) Downstream Total Exchange Rate ($US/$Cdn) ,2,3,4,5,6 see Slide Notes and Advisories 37

38 Today vs. 2021: What We Could Do at $35 US WTI As Assets Improve, Funds from Operations, Free Cash Flow and Debt Capacity Increase Today s Portfolio $35 US WTI $12 US Chicago Crack 2021 Portfolio $35 US WTI $12 US Chicago Crack <2x Net Debt / FFO $1.9B FFO $1.8B Sustaining Capital <2x Net Debt / FFO $3.1B FFO $2.1B Sustaining Capital $0.1B Discretionary $1.0B Discretionary 38

39 Downstream Assets Lloyd Complex U.S. Refining & Marketing Pipelines & Storage 110,000 bbls/day processing capacity Physically connected to Lloyd and Tucker production 290,000 bbls/day processing capacity Product marketing footprint centered in Ohio Five million barrels tank storage 75,000+ bbls/day takeaway capacity Lloyd Upgrader Asphalt Refinery Capacity: 80 mbbls/d Produces Husky Synthetic Crude (HSB) Low operating costs Capacity: 30 mbbls/d Supplies ~4% of asphalt manufactured in North America Lloyd feedstock provides for premium quality Transportation by rail Lima Refinery Toledo Refinery Superior Refinery Capacity: 160 mbbls/d Light oil refinery Access to diverse crude supply Capacity: 80 mbbls/d 1 Configured to process high- TAN Sunrise crude Husky markets its products as well as secondary products on behalf of JV Capacity: 50 mbbls/d Light / Heavy oil refinery Asphalt, diesel, gasoline Hardisty & Lloyd Storage Terminals Gathering System 3.1 mmbbls at Hardisty 1.0 mmbbls at Lloyd Profitable blending business Increases flexibility in marketing crude Firm takeaway commitments Connections to several main pipelines ensure Husky crude can reach market 1 see Slide Notes and Advisories 39