Corporate Presentation

Transcription

1 January Budget Corporate Presentation CRESCENT POINT

2 2019 Highlights Disciplined budget of $ $1.30 billion ~30% lower than 2018 Continued focus on key value drivers of balance sheet improvement, disciplined capital allocation and reductions in costs Flexible capital allocation strategy with ability to revise budget based on commodity price outlook Focus on returns and living within cash flow Share repurchase program to enhance shareholder value Realized cost reductions to date and targeting additional improvements in overall efficiencies 2

3 2019 Capital Allocation and Production Guidance Capital expenditures reduced ~30% vs. 2018E Capital Expenditures Annual Avg. Production Annual average production unchanged vs. 2018E Returns-focused budget vs. simple production growth $1.745B $1.74B ~30% $1.2B - - $1.3B 177 mboe/d mboe/d Unchanged YoY production (net of dispositions) Key focus areas to include combination of low-risk, high-return drilling, waterflood programs and new infrastructure to support future growth 2018E 2019E 2018E 2019E 2018 Dispositions Reduced spending in Emerging and Early-Stage plays due to limited market access in Uinta Basin and riskadjusted returns at current oil prices in East Shale Duvernay. Ability to increase spending in these plays as they advance or as oil prices improve 45% 25% Capital Allocation ($MM) +10% -10% 55% 15% ~70% of capital spending directed to Key Focus Areas and Emerging & Early-Stage plays Capital allocation to Other areas remain unchanged year-over-year due to their strong risk-adjusted returns 30% 30% 2018E 2019E Key Focus Areas Emerging & Early-Stage Other Capital expenditures and capital allocation figures are approximates and 2019 figures based on mid-point of 2019 capital expenditures guidance 3

4 Maintaining Flexibility in Various Commodity Price Environments High-Cycle Returns-based capital allocation Mid-Cycle Live within cash flow Maintain or enhance balance sheet strength Low-Cycle Return capital to shareholders through dividends / share repurchases Flexible 2019 capital allocation strategy with ability to revise budget based on returns and outlook for commodity prices Ongoing portfolio optimization, asset dispositions and cost reduction initiatives Risk management including hedging Revised dividend strategy to protect balance sheet, increase FCF generation and enhance shareholder returns (including NCIB) Allocate capital based on returns including drilling and potential share repurchases 4

5 Transition Plan to Create Shareholder Value Reducing # of Operating Areas Dispositions Focused Asset Base Stronger Balance Sheet Decline Mitigation Improved Returns Cost Reductions Disciplined Capital Allocation 5

6 Improving Cost Structure Capital Costs 2019 budget incorporates realized capital cost reductions to date of ~5% on average through reduced drilling days, completion optimization and improved logistics Returns-focused capital allocation and more consistent level of spending and activity G&A Workforce reduction of ~17% in 2018 with savings across both G&A and operating expenses Streamlined executive team with reduced NEO compensation Operating Expenses Reduced controllable operating costs by ~$35 million to date during transition plan Targeting additional cost reductions through efficiency improvements, including field automation and reduced downtime, as well as a more focused asset base. Total savings are expected to offset fixed cost increases Realized year-over-year improvement in overall efficiencies G&A savings of ~10% in 2019 Cost improvements as part of operations excellence 6

7 Targeting Improved Balance Sheet Strength Optimal Leverage Scenarios (D/CF) Low-Cycle D/CF 2.0X Tools for Balance Sheet Improvement: D/CF >2.0X 1. Dispositions Identified ~50,000 boe/d of high-return upstream assets at time of strategic review Evaluating other opportunities to create value, including infrastructure monetization Q Prior to Transition Plan Mid-Cycle D/CF 1.5X High-Cycle D/CF 1.0X 2. Enhanced FCF and Cost Reductions Improved capital allocation and decline rate mitigation Realigned organizational structure; capital cost reductions; identifying areas for additional cost savings, including field automation Transition plan announced September 5, 2018 D/CF represents net debt to adjusted funds flow 7

8 Oil Hedge Volume (bbl/d) Commodity Hedging Strategy 80,000 51% H % H % Q $ ,000 60,000 $ ,000 40,000 30,000 $70.00 $ CAD per bbl 20,000 $ ,000 0 Q1 19 Q2 19 Q3 19 Q4 19 Q1 20 Swaps 3-Way Collars Floor Hedge Price (3-way collars at market price) $50.00 As at January 9, Floor hedge price is calculated using the forward strip for the 3-way collar hedges Floor hedge price of 3-way collar hedges are subject to change based on forward oil and f/x prices 2019 & 2020 percentage hedged figures based on mid-point of 2019 annual average liquids production guidance net of royalties 8

9 CAD$/bbl CRESCENT POINT CORPORATE PRESENTATION Canadian Market Access and Pricing Advantage Canadian oil differentials have recently been volatile CPG less impacted due to location and quality of its assets ~90% of oil production either downstream of recent apportionment or in the United States Light-oil weighted, with majority of production receiving a premium to MSW Edmonton light pricing Diversified transportation methods including pipeline, rail and trucking No impact to CPG production from recent Alberta government imposed volume curtailments Shaunavon Viewfield & Flat Lake Cromer Clearbrook Superior St. Paul Sarnia Corporate Oil Production Breakdown by Pricing Stream CPG Corporate Realized Oil Pricing vs. CDN Index Prices Chicago WTI UHC 25% (US) $90 $60 Cushing Patoka Light Oil (80%) LSB 45% $30 Medium Oil (20%) (premium to WCS) MSW FOS 10% 20% 100% $0 Jan-18 Apr-18 Jul-18 Oct-18 Jan-19 CPG Realized Oil Price CPG Expected Oil Price MSW WCS Major Pipeline CPG CDN Focus Areas WCS = Western Canadian Select, FOS = Fosterton, MSW = Mixed Sweet Blend, LSB = Light Sour Blend, UHC = Sweet at Clearbrook CPG s SE Saskatchewan production is priced off LSB at Cromer vs. MSW at Edmonton CPG s Utah production is priced at a negotiated discount to WTI 9

10 Focused Asset Base Key Focus Areas Three high-quality resource plays located in Saskatchewan Large resource in place with ~13 billion bbl of OOIP Significant drilling inventory with ~1.65 million net acres of land AB SK Emerging & Early-Stage Resource Plays Strong growth potential with >650,000 net acres of land Light oil focused, high-impact producing wells Uinta Basin East Shale Duvernay Strong economics to date with potential for enhanced returns as each play continues to advance UT Shaunavon Viewfield Company Statistics (all areas) Flat Lake OOIP (bbls) 27 billion Key Focus Areas Emerging & Early-stage Resource Plays Net Acres 4.1 million Net Risked Inventory ~6,850 Land, risked inventory and OOIP as at YE 2018 Risked inventory not comparable to YE 2017 given number of locations converted from 1-mile to 2-mile at YE 2018 and dispositions in

11 Million $ CAD CRESCENT POINT CORPORATE PRESENTATION Viewfield Bakken Significant free cash flow generation Infill economics within top quartile of corporate inventory Increased waterflood scalability and cost optimizations through ongoing unitization and new injector conversions Bakken pool boundary Waterflood unit boundary Key Statistics OOIP (bbls) 4.6 billion Net Acres 600,000 % of Corporate Production (2019) 25% $1,500 $1,250 $1,000 $750 NOI vs. Capex 2019 Drill Count (net) 105 $500 Risked Inventory (net) 850 $250 Pricing Stream LSB OOIP, risked inventory and net acres as at YE 2018 Capital expenditures (capex) includes drilling & development, facilities and seismic and excludes land NOI = Net operating income All figures are approximates unless otherwise specified $ E 2019E US$WTI $93 $49 $43 $51 $65 $50 NOI Capex 11

12 Million $ CAD Shaunavon Low-risk, high-return drilling inventory with reserves upside Low operating costs with established infrastructure Free cash flow positive Consistent implementation of waterflood $500 NOI vs. Capex $400 $300 Shaunavon pool boundary Waterflood unit boundary $200 $100 $ E 2019E US$WTI $93 $49 $43 $51 $65 OOIP, risked inventory and net acres as at YE 2018 Capital expenditures (capex) includes drilling & development, facilities and seismic and excludes land NOI = Net operating income All figures are approximates unless otherwise specified NOI Capex $50 Key Statistics OOIP (bbls) 5.5 billion Net Acres 500,000 % of Corporate Production (2019) 15% 2019 Drill Count (net) 95 Risked Inventory (net) 1,750 Pricing Stream FOS 12

13 Flat Lake Multi-zone resource play with organic drilling growth Near-term free cash flow neutral to slightly positive Strong reserves upside with significant unbooked running room Opportunity to enhance efficiencies and returns by utilizing new facilities, pad drilling, longer laterals and reducing costs Advancing waterflood programs for increased recovery factors Torquay pool boundary Key Statistics OOIP (bbls) 2.9 billion Online 2018 Net Acres 550,000 % of Corporate Production (2019) 15% 2019 Drill Count (net) 105 Risked Inventory (net) 1,400 Pricing Stream LSB Online 2018 Oil Sales Pipeline Future Oil Sales Pipeline Gas Sales Pipeline Future Gas Pipeline B Battery Oil Storage Tank Gas Plant * Gathering pipelines not shown OOIP, risked inventory and net acres as at YE 2018 All figures are approximates unless otherwise specified 13

14 CRESCENT POINT CORPORATE PRESENTATION Emerging Play: Uinta Basin Multi-zone resource play with a current focus on developing the Wasatch, Uteland Butte and Castle Peak zones Strong well results to date with an opportunity to enhance returns through stacked, multi-well pads and 2-mile Hz wells Improved drilling days and optimized completion design to realize reduced capital costs of over 10% CPG continues to pursue new opportunities for increased market access CPG drilled Hz wells to date Industry drilled Hz wells to date Stacked Horizontal Development Key Statistics OOIP (bbls) 8.5 billion Net Acres 300,000 % of Corporate Production (2019) 12% 2019 Drill Count (net 2-mile Hz) 12 Risked Inventory (net)* 500 Castle Peak Uteland Butte Wasatch Pricing Stream % of WTI *Risked inventory includes Hz wells only and is composed of 1-mile and 2-mile wells (majority 2-mile) OOIP, risked inventory and net acres as at YE 2018 Capital expenditures (capex) includes drilling & development, facilities and seismic and excludes land All figures are approximates unless otherwise specified Drilled well Future undrilled well 14

15 Early Stage Play: East Shale Duvernay Strategically targeted oil window based on thicker pay, higher pressure, depth and maturity Bigoray Drilled several wells (operated and non-operated) to date with encouraging results Completion optimization targeting increased recoveries and efficiencies Disciplined capital allocation; continue to monitor well results Knob Hill Joffre / Ferrybank Key Statistics OOIP per Section (mmbbls) Gilby Net Acres 355,000 % of Corporate Production (2019) 1% % of Corporate Budget (2019) 3% Risked Inventory (net)* 300 Elnora / Twining Pricing Stream MSW OOIP and risked inventory as at YE Duvernay budget includes a mix stratigraphic and Hz wells Risked inventory is composed of all 2-mile Hz wells identified to date through initial delineation program with potential to increase as this early-stage play is further developed All figures are approximates unless otherwise specified 15

16 Investment Summary Deep value at current share prices relative to underlying fundamental value Applying for NCIB for up to 7% of public float High netback asset base with significant positions in large OOIP resource pools ~$25.50/boe operating netback in 2019 at US$50/bbl WTI Transitioning to become a more focused and efficient company with a stronger balance sheet Realized G&A, operating expense and capital cost reductions with an increased cost focus for additional savings New management s capital allocation process centered on returns with flexibility at various commodity prices Reduced 2019 capital expenditures by ~30% with unchanged annual average production vs Disciplined disposition program of upstream and infrastructure assets Potential catalysts associated with asset packages to be marketed in early

17 Forward Looking Information This presentation contains "forward-looking statements" within the meaning of applicable securities legislation, such as section 27A of the Securities Act of 1933 and section 21E of the Securities Exchange Act of 1934, including estimates of future production, cash flows and reserves, business plans for drilling and exploration, the estimated amounts and timing of capital expenditures, the assumptions upon which estimates are based and related sensitivity analyses, and other expectations, beliefs, plans, objectives, assumptions or statements about future events or performance (often, but not always, using words or phrases such as "expects" or "does not expect", "is expected", "anticipates" or "does not anticipate", "plans", "estimated" or "intends", or stating that certain actions, events or results may", "could", "would", "might" or "will" be taken, occur or be achieved). In particular, this presentation contains forward-looking statements pertaining to the Company s: continued focus on key value drivers of balance sheet improvement, disciplined capital allocation and cost reductions; plan to follow a flexible capital allocation strategy; ability to revise its budget based on commodity price outlook; plans to drive further cost reductions and improve efficiencies; expected capital expenditure savings compared to 2018; expected annual average production in 2019 compared to 2018; drilling, waterflood and infrastructure plans for its key focus areas; plans to reduce spending in its emerging and earlier stage plays and its ability to increase spending as each plan advances; expected capital spending devoted to key focus areas and emerging and early-stage plays; plans to live within cash flow, maintain or enhance its balance sheet strength and return capital to shareholders; ability to revise its budget based on returns and commodity price outlook; ongoing portfolio optimization, asset disposition and cost reduction plans; expectation that its revised dividend strategy will protect its balance sheet, increase free cash flow generation and enhance shareholder returns; transition plans and its core elements; expectation that G&A savings of approximately 10% will be achieved in 2019; additional cost reduction plans (through efficiency improvements and a more focused asset base and the expectation that these savings will offset fixed cost increases; ongoing evaluation of opportunities to create value, including through upstream asset dispositions and infrastructure monetization; expectation that recent Alberta government imposed volume curtailments will have no impact; expected oil price; OOIP, drilling inventory and expected 2019 corporate production and cash flow generation from its key focus areas and the Company s belief in the strong growth potential and potential for enhanced returns of its emerging and early stage resource plays; expectation that the waterflood scalability of the Viewfield Bakken play may be increased and cost optimization achieved through ongoing unitization and new injector conversions; expected NOI vs. Capex for 2018 and 2019 for the Viewfield Bakken and Shaunavon plays; belief in the reserves upside associated with the Shaunavon play; view of the reserves upside, unbooked running room, opportunity to enhance efficiencies and returns and the Company s waterflood program enhancement plans for Flat Lake; development focus and its opportunities to enhance returns, improve drilling days, optimize completion design, reduce capital costs and pursue new market access opportunities in the Uinta Basin; completion optimization and development plans for East Shale Duvernay; the Company s plan to seek TSX approval for its NCIB; expectation that operating expense savings and capital cost reductions will be achieved in 2019; expectation that its reduced 2019 capital program will have minimal impact on annual average production when compared to 2018; 2019 capital expenditures, annual average production, adjusted funds flow netback and adjusted funds flow sensitivity (to WTI); expected economics associated with its 2019 capital program; expectation that proceeds from dispositions will be directed to debt reduction and enhancing shareholder value versus acquisitions; capital allocation process expectations; believe that the its transition plan will improve full-cycle and corporate returns; waterflood conversion plans for 2019; ongoing commitment to achieving its transition plan deliverables; expectation that at least two new independent members will be added to the Board by 2019 and the new directors will build on the skillsets of retiring Board members. There are numerous uncertainties inherent in estimating crude oil, natural gas and NGL reserves and the future cash flow attributed to such reserves. The reserve and associated cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating expenses, all of which may vary materially. Actual reserve values may be greater than or less than the estimates provided herein. Also, estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates and future net revenue for all properties due to the effect of aggregation. Information relating to "reserves" is deemed to be forward-looking information, as it involves the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and that the reserves described can be profitably produced in the future. All required reserve information for the Corporation is contained in its Annual Information Form for the year ended December 31, 2017, which is accessible at With respect to disclosure contained herein regarding resources other than reserves, there is uncertainty that it will be commercially viable to produce any portion of the resources and there is significant uncertainty regarding the ultimate recoverability of such resources. All forward-looking statements are based on Crescent Point s beliefs and assumptions based on information available at the time the assumption was made. Crescent Point believes that the expectations reflected in these forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this report should not be unduly relied upon. By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements, including those material risks discussed in the Company s Annual Information Form for the year ended December 31, 2017 under "Risk Factors," in our Management s Discussion and Analysis for the year ended December 31, 2017, under the headings "Risk Factors" and "Forward-Looking Information" and for the quarter ended September 30, 2018 under Derivatives, Liquidity and Capital Resources, Changes in Accounting Policy and Outlook. The material assumptions are disclosed in the Management s Discussion and Analysis for the year ended December 31, 2017, under the headings "Capital Expenditures", "Liquidity and Capital Resources", "Critical Accounting Estimates", "Risk Factors", "Changes in Accounting Policies and "Outlook" and are disclosed in the Management s Discussion and Analysis for the quarter ended September 30, 2018 under the headings Derivatives, Liquidity and Capital Resources, Changes in Accounting Policy and Outlook. In addition, with respect to forward-looking information contained in this presentation, assumptions have been made regarding, among other things: future crude oil and natural gas prices; future interests rates and currency exchange rates; future cost escalation under different pricing scenarios; the Corporation's future production levels; the applicability of technologies for recovery and production of the Corporation's reserves and improvements therein; the recoverability of the Corporation's reserves; Crescent Point s ability to market its production at acceptable prices; future capital expenditures; future cash flows from production meeting the expectations stated in this presentation; future sources of funding for the Corporation's capital program; the Corporation's future debt levels; geological and engineering estimates in respect of the Corporation's reserves; the geography of the areas in which the Corporation is conducting exploration and development activities; the impact of competition on the Corporation; the Corporation's ability to obtain financing on acceptable terms. These assumptions, risks and uncertainties could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements. The impact of any one assumption, risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent. Except as required by law, Crescent Point assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change. Certain information contained herein has been prepared by third-party sources. Included in this presentation are Crescent Point s preliminary 2019 guidance in respect of capital expenditures, average annual production, drilling capital efficiency, adjusted funds flow netback, total payout ratio and adjusted funds flow sensitivity, which are based on various assumptions as to production levels, commodity prices and other assumptions and are provided for illustration only and are based on budgets and forecasts that have not been finalized and are subject to a variety of contingencies including prior years' results. To the extent such estimates constitute a financial outlook or future oriented financial information in this presentation, as defined by applicable securities legislation, such information has been approved by management of Crescent Point in September Such financial outlook or future oriented financial information is provided for the purpose of providing information about management s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes. 17

18 October 2018 Appendix

19 Capital Markets Summary and 2019 Guidance Capital Markets Summary CPG (TSX and NYSE) 2019 Guidance Trading Price (Jan 9, 2019) C$4.56 (TSX), US$3.45 (NYSE) Capital Expenditures $ $1.30 billion Shares Outstanding million Annual Average Production 170 to 174 mboe/d Avg. Daily Trading Volume ~9.7 million Dividend (Yield) $0.01 per quarter (~1.0%) Market Capitalization $2.5 billion Adjusted Funds Flow Netback Adjusted Funds Flow Sensitivity (US$1/bbl WTI) ~$24.00 / boe ~$50 million Net Debt Enterprise Value $4.0 billion $6.5 billion Capital expenditures excludes any potential net land and property acquisitions and ~$35 million of capitalized G&A Adjusted funds flow netback based on US$50/bbl WTI, CAD/USD fx of 0.75, MSW differential of -US$8.75/bbl and WCS differential of -US$18.00/bbl Adjusted funds flow sensitivity net of hedging based on mid-point of 2019 guidance Unutilized Credit Capacity $1.7 billion Net debt and unutilized credit capacity as of September 30, 2018 Market capitalization and dividend yield based on share price as of market close on January 9, 2019 Shares outstanding is based on fully diluted shares as of September 30, 2018 Avg. daily trading volume based on CDN and US volumes from trailing 6-months as of January 9, 2019 Unutilized credit capacity includes cash of $65.5 million 19

20 Economics Potential to further improve economics due to improvements in cost structure and overall efficiencies Key Focus Areas Type Well (EUR) (mbbl) Cost per well ($MM) PI Ratio $50 WTI $55 WTI Payout (months) PI Ratio Payout (months) Viewfield Bakken Shaunavon Flat Lake Torquay (1-mile) Flat Lake Torquay (2-mile) Flat Lake - Conv. Ratcliffe Emerging Resource Play Uinta Basin (2-mile Hz) ($US) Type Well (EUR) (mbbl) Cost per well ($MM) PI Ratio Payout (months) PI Ratio Payout (months) All figures are approximates and in CAD unless otherwise noted The company also factors in risks in its overall capital allocation process Capital costs per well include drilling, completion, equipment and tie-in expenditures Economics by play represent type wells expected to be drilled in 2019 program PI is profit to investment = present value of future cash flows discounted at 10%, divided by the cost per well The US$50 WTI scenario assumes annual price escalation of 2% per year 20

21 Million $ CAD Balance Sheet Composition Debt Composition ($CAD) as of September 30, 2018 $250 Near-Term Senior Guaranteed Notes Maturity Schedule* $224 $1.9B Senior Guaranteed Notes* $2.0B Drawn on Bank Credit Facilities (55% utilized) $1.7B Cash & Unutilized Credit Capacity $200 $150 $100 $50 $0 $185 $158 $ *Includes underlying currency swaps 21

22 Million $ CAD Committed to Strengthening Balance Sheet $400 $300 $200 $100 New management team focused on dispositions with proceeds directed to debt reduction and enhancing shareholder value vs. acquisitions $ Acquisitions Dispositions 22

23 Disciplined Capital Allocation Process RISK-ADJUSTED RETURNS CONSISTENT CAPITAL & ACTIVITY LEVELS LONG-TERM DEVELOPMENT GOALS DECLINE MITIGATION RISK-ADJUSTED RETURNS CONSISTENT CAPITAL & ACTIVITY LEVELS LONG-TERM DEVELOPMENT GOALS DECLINE MITIGATION Increased focus on risks and asset stage of life in decision making process Bottom-up approach based on individual type wells Not focused on top-line volume growth Creating a more sustainable production profile versus achieving targets at a point in time (i.e. exit rate) Additional benefits to costs, staffing, logistics and safe operations Appropriate mix of capital related to longer-term priorities such as step-out drilling, pilot programs, expiries, etc. Advancing decline mitigation techniques to moderate future capital requirements Waterflood programs will compete for capital based on full-cycle returns 23

24 Improving Returns Facilities Infrastructure Monetization Single-Well Economics (Half-Cycle) 35% - 60% IRR Production Optimization Land & Seismic Corporate G&A Full Cycle Economics ~10% - 25% IRR Cost Reductions Disciplined Capital Allocation Reduced # of Operating Areas Transition plan expected to improve full-cycle and corporate returns Single-well economics IRR reflects the average well return in the Company s prior 5-year capital drilling program Returns based on US$50/bbl US$60/bbl WTI Post transition returns are not to scale and meant for illustrative purposes only 24

25 INJECTOR PRODUCER CRESCENT POINT CORPORATE PRESENTATION Decline Mitigation Benefits Increase production, reserves, recovery factor Low F&D cost Increases NPV, high P/I ratio Decreases voidage, lowers decline rate Challenges Not widely understood by market Sacrifice short-term production Takes time to fully implement Changes to Capital Allocation Process for Decline Mitigation Programs Targeted waterflood approach enhancing efficiencies and results Compete for capital with all opportunities within the Company 2019 guidance includes ~145 new waterflood conversions (up from 70 in 2018) Full-Cycle Economics Comparison Example Viewfield Bakken Type Well (EUR) (mbbl) Cost Per Well ($MM) 10% ($MM) P/I Payout (years) Implied F&D ($/boe) Waterflood (Incremental economics) 150 $0.3 $ <3 years ~$2.00 Economics are based on flat US$55/bbl WTI pricing F&D is finding and development costs 25

26 Transition Plan Deliverables Crescent Point has established the following deliverables FOCUS ASSET BASE WITH FEWER OPERATING AREAS NET DEBT REDUCTION INCREASE ADJUSTED FUNDS FLOW NETBACK INCREASE FREE CASH FLOW GENERATION Dispose select upstream assets to focus asset base Net debt to adjusted funds flow ratio of 1.3x (in the context of commodity prices) >6% increase through improvements to cost and capital structure Improved capital efficiencies, cost reductions, decline mitigation and disciplined capital allocation Target net debt to adjusted funds flow ratio assumes a WTI price of US$65/bbl and adjusted funds flow netback assumes a WTI price of US$65/bbl WTI and netback of $32.05/boe 26

27 Actions to Date Shareholder Value Creation Applying for NCIB for up to 7% of total shares o/s based on current market conditions $355 million of dispositions in 2018, with continued focus on a disciplined disposition program in 2019 Cost Reductions Organizational restructuring resulting in G&A and operating expense savings in 2019 Reduced capital costs by ~5% driving improved overall efficiencies Disciplined Capital Allocation Reduced 2019 capital by ~30% with flat annual average production driven by return-focused and flexible capital allocation strategy On track to meet or exceed 2018 production guidance with capital expenditures below budget 27

28 Governance: Board Renewal Process new independent members since 2014 At least 2 new independent members to be added by 2019 Other key diversity enhancements: International experience Industry Gender Capital markets Over 7 Years Tenure Under 7 Years Tenure Ongoing and Deliberate Board Renewal Process Added 7 new members since process began in 2014 Following the 2019 annual general meeting, the Company will have completed a full board renewal since inception New directors build on skillsets of retiring members in the coming year New Chairman of the Board Robert (Bob) Heinemann appointed chairman effective September 2018 (served on Crescent Point s board since 2014) Significant public board leadership experience Professional engineer with over 30 years of oil and gas experience Previously President & CEO of Berry Petroleum Co. from 2004 to 2013 and prior to that, worked for Haliburton Company and Mobil Company in a number of operational, technology, management and executive roles of increasing responsibility 28

29 Disclosure Committee NOTE TO READER REGARDING DISCLOSURE In addition to obtaining all necessary Board approvals, the Company s long-established Disclosure Committee s mandate is to review and confirm the accuracy of the data and information contained in the documents, including this presentation, Crescent Point uses to communicate to the public. This review and confirmation process is formally completed prior to any such disclosure being released. This Committee is comprised of senior representatives (including officers) from each of the following departments: accounting and finance; engineering and operations (including drilling and completions, environment, health and safety and regulatory); exploration and geosciences; investor relations; land; legal; marketing and reserves. This presentation contains "forward-looking statements" within the meaning of applicable securities legislation, such as section 27A of the Securities Act of 1933 and section 21E of the Securities Exchange Act of 1934, including estimates of future production, cash flows and reserves, business plans for drilling and exploration, the estimated amounts and timing of capital expenditures, the assumptions upon which estimates are based and related sensitivity analyses, and other expectations, beliefs, plans, objectives, assumptions or statements about future events or performance. Please see the Forward-Looking Statements section of this presentation for additional details regarding such statements. 29

30 Definitions / Non-GAAP Financial Measures Non-GAAP Measures Throughout this presentation the Company uses the terms adjusted funds flow, adjusted funds flow netback, operating netback, profit to investment ratio, market capitalization, net debt, enterprise value, net debt to adjusted funds flow and free cash flow. These terms do not have any standardized meaning as prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other issuers. Adjusted funds flow is equivalent to adjusted funds flow from operations. Adjusted funds flow is calculated based on cash flow from operating activities before changes in non-cash working capital, transaction costs and decommissioning expenditures. Adjusted funds flow netback is calculated based on cash flow from operating activities before changes in non-cash working capital, transaction costs and decommissioning expenditures on a per boe basis. Transaction costs are excluded as they vary based on the Company s acquisition activity and to ensure that this metric is more comparable between periods. Decommissioning expenditures are excluded as the Company has a voluntary reclamation fund to fund decommissioning costs. Management utilizes adjusted funds flow from operations as a key measure to assess the ability of the Company to finance dividends, operating activities, capital expenditures and debt repayments. Adjusted funds flow as presented is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. Net operating income is calculated as oil and gas sales, less royalties, operating and transportation expenses. Operating netback is calculated based on net operating income on a per boe basis. Net operating income and operating netback are common metrics in the oil and gas industry and are used by management to measure operating results, including on a per boe basis, to better analyze performance against prior periods on a comparable basis. Profit to investment (PI) ratio is calculated as the present value discounted at 10% divided by capital cost. PI ratio is used by management to assess the Company s profitability on capital investments. Market capitalization is an indication of enterprise value and is calculated by applying a recent share trading price to the number of diluted shares outstanding. Market capitalization is an indication of enterprise value. Net debt is calculated as long-term debt plus accounts payable and accrued liabilities, dividends payable and long-term compensation liability, less cash, accounts receivable, prepaids and deposits and long-term investments, excluding the unrealized foreign exchange on translation of US dollar long-term debt. Management utilizes net debt as a key measure to assess the liquidity of the Company. Enterprise value is calculated as market capitalization plus net debt. Management uses enterprise value to assess the valuation of the Company. Net debt to adjusted funds flow is calculated as the net debt divided by adjusted funds flow for the trailing four quarters. The ratio of net debt to adjusted funds flow is used by management to measure the Company s overall debt position and to measure the strength of the Company s balance sheet. Crescent Point monitors this ratio and uses this as a key measure in making decisions regarding financing, capital spending and dividend levels. Free cash flow (FCF) is calculated as adjusted funds flow less capital expenditures. Management utilizes free cash flow as a key measure to assess the ability of the Company to finance dividends, potential share repurchases, debt repayments and returns-based growth. Management believes the presentation of the Non-GAAP measures above provide useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance against prior periods on a comparable basis. This information should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. For definitions of the non-gaap measures listed above along with reconciliations from the non-gaap measure to the most directly comparable GAAP measure, each of which is incorporated by reference please see the Company s most recent annual Management s Discussion & Analysis ( MD&A ) available on SEDAR at sedar.com, or EDGAR as and on our website as 30

31 Definitions / Non-GAAP Financial Measures Oil and Gas Metrics This presentation includes oil and gas metrics including drilling inventory and operating netback. Such metrics do not have a standardized meaning and as such may not be reliable, and should not be used to make comparisons. Drilling inventory and current inventory are used by management to assess the amount of available drilling opportunities. Internally identified unbooked drilling locations may include infill, lease-edge and undrilled tracts, based on current land holdings, geologic, geophysical and engineering analysis that result in mapped type-well groupings and optimized scheduling. Operating netback is calculated based on net operating income on a per boe basis. Operating netback is a common metric in the oil and gas industry and is used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis. Oil and Gas Definitions 1. Barrels of oil equivalent ( boe ) 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. 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 oil, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. 2. Original Oil-In-Place (OOIP) means Discovered Petroleum Initially-In-Place (DPIIP) as at December 31, 2018, but excluding gas. DPIIP, as defined in the Canadian Oil and Gas Evaluations Handbook (COGEH), is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of DPIIP includes production, reserves and contingent resources; the remainder is unrecoverable. OOIP/DPIIP estimates and recovery rates are as at December 31, 2018, and are based on current accepted technology and have been prepared by Crescent Point s qualified reservoir engineers. There is significant uncertainty regarding the ultimate recoverable OOIP/DPIIP. For further information see Crescent Point s Annual Information Form for the year-ended December 31, There is significant uncertainty regarding the ultimate recoverable OOIP/DPIIP. For further information see Crescent Point s Annual Information Form for the year-ended December 31, Net present values disclosed in this presentation are calculated before tax. 5. Cash flow equates to adjusted funds flow. 31

32 Definitions / Non-GAAP Financial Measures Drilling Locations This presentation discloses drilling locations as risked locations, which includes a total of booked and unbooked locations. The booked locations are derived from the Corporation's most recent independent reserves evaluation as prepared by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited, both as at December 31, 2017, and were aggregated by GLJ and account for drilling locations that have associated proved and/or probable reserves, as applicable, unless otherwise stated. Of the ~6,850 risked total net corporate undrilled locations disclosed in this presentation as of December 31, 2018, ~3,460 are booked as of December 31, The remaining net locations are internally identified and are unbooked. Of the approximately ~850 risked net Viewfield Bakken locations disclosed in this presentation as of December 31, 2018, ~650 are booked as of December 31, The remaining net locations are internally identified and are unbooked. Of the approximately ~1,750 risked net Shaunavon locations disclosed in this presentation as of December 31, 2018, ~675 are booked as of December 31, The remaining net locations are internally identified and are unbooked. Of the approximately ~1,400 risked net Flat Lake locations disclosed in this presentation as of December 31, 2018, ~425 are booked as of December 31, The remaining net locations are internally identified and are unbooked. Of the approximately ~500 risked net Uinta horizontal locations disclosed in this presentation as of December 31, 2018, ~60 are booked as of December 31, The remaining net locations are internally identified and are unbooked. Of the approximately ~300 risked net Duvernay horizontal locations disclosed in this presentation as of December 31, 2018, 4 are booked as of December 31, The remaining net locations are internally identified and are unbooked. Unbooked locations are internal estimates based on the Corporation's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Corporation's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Corporation will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Corporation will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. The total unbooked location inventory contains risked future drilling locations that have a greater certainty of success due to these risked locations relative close proximity to current existing wells. 32

33 Definitions / Non-GAAP Financial Measures Type Wells All type well information, including single-well economics presented herein has been prepared by qualified reserves evaluators in accordance with the COGE handbook. The type curves reflect a proved plus probable (2P) reserve level. Hedging Hedges extend into end of Q

34 BANKER AUDITOR LEGAL COUNSEL EVALUATION ENGINEERS REGISTRAR & TRANSFER AGENT INVESTOR CONTACTS Bank of Nova Scotia PricewaterhouseCoopers LLP Norton Rose Fulbright Canada LLP GLJ Petroleum Consultants Ltd. Sproule Associates Limited Computershare Trust Company (Toll Free) Suite 2000, 585 8th Ave SW, Calgary, AB T2P 1G1 T: F: TF: (Canada & USA)