January Crescent Point Energy Corporate Presentation

Transcription

1 January 2016 Crescent Point Energy Corporate Presentation 1

2 FORWARD-LOOKING STATEMENTS 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 following: the Company's anticipated 2016 capital budget and average daily production; ability to monetize hedges in 2016; expected impact of Alberta royalty review; living within cash flow; payout ratios; flexibility to adjust capital plans; waterflood plans; opportunity to expand economic boundaries of core resource plays; half-cycle capital efficiencies; corporate decline rate reductions; F&D costs; impact of reallocated capital on average production in 2016; using internal funding to complete future acquisitions; potential additional cost savings in 2016; estimated Viewfield Bakken drilling and completion costs; planned reduction or elimination of fresh water usage during completions in Viewfield Bakken and Shaunavon; improving differentials in Uinta; the ability of the Company to maintain its balance sheet strength; type well economics and performance; drilling inventory and reserve life index expectations; the anticipated impact of technical advancements and waterflood activities; the Company s strategy to increase recovery factors; the Company's waterflood goals and injection well plans; the ability of the Company to manage the current low oil price environment; the Company s hedging program; the Company s business strategy (including development, enhancement, acquisition and risk management); capital allocation; 2016 capital expenditure scenarios; CAGR predictions; sustainability of growth; free cash flow; future commodity prices and production; capital cost and type well scenarios, cost per well, NPV, rate of return and payout; increased recovery given mobility levels; plans for injection wells; production and reserve growth; outperformance of large oil in place pools; and the Company s expected ongoing emphasis on prudent cost and risk management. Statements relating to "reserves" are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. 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 costs, all of which may vary materially. Actual reserve values may be greater than or less than the estimates provided herein. All forward-looking statements are based on Crescent Point s beliefs and assumptions based on information available at the time the assumption was made. The material assumptions are disclosed in the presentation, in the Management s Discussion and Analysis for the year ended December 31, 2014, under the headings Dividends, Capital Expenditures, Decommissioning Liability, Liquidity and Capital Resources, Critical Accounting Estimates, Changes in Accounting Policies and Outlook, and in the Management s Discussion and Analysis for the period ended September 30, 2015, under the headings Dividends, Capital Expenditures, Decommissioning Liability, Liquidity and Capital Resources, Changes in Accounting Policies and Outlook. 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 presentation 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 and Form 40-F under Risk Factors and our Management s Discussion and Analysis for the year ended December 31, 2014, under the headings Risk Factors and Forward-Looking Information, and risk factors described in other documents we file from time to time with securities regulatory authorities, all of which are available on SEDAR or sedar.com, EDGAR or and Crescent Point Energy s website as In addition, risk factors include: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations; pipeline restrictions; blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; failure to realize the anticipated benefits of acquisitions; general economic, market and business conditions; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry. These 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 risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent. Crescent Point assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change. Certain information contained herein have been prepared by third-party sources. The information provided herein has not been independently audited or verified by the Company. 2

3 HIGH-QUALITY, LOW-COST PRODUCER: CPG (TSX AND NYSE) Market Capitalization $8.2 billion (508.6 million shares fully diluted) (1) Net Debt* Enterprise Value $4.2 billion (incl. hedged USD$ denominated debt) $12.4 billion 2016 Average Production 165,000 to 172,000 boe/d (~90% oil weighted) Annual Dividend $1.20/share Proved + Probable Reserves million boe (RLI: 15.5 years) (2)(3) Proved Reserves million boe (RLI: 10.1 years) (2)(3) Drilling Inventory** ~7,460 locations (>12 years of inventory) (3)(4) * As of September 30, ** Excludes net locations from Legacy Oil + Gas Inc. and Coral Hill Energy Ltd. Maximize shareholder return with long-term growth and dividend income FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 3

4 BUSINESS STRATEGY Develop and Enhance Assets Increase recovery factors through step-out and infill drilling, waterflood optimization and improved technology Acquire Focus on high-quality, large resource-in-place pools with the potential for upside in production, reserves, technology and value Utilize internal funding to complete future acquisitions Manage Risk Maintain strong balance sheet, significant unutilized bank line capacity (~$1.4 billion), no material near-term debt maturities and a 3½-year hedging program 4

5 Oil volumes (bbl/d) Oil volumes (bbl/d) Percent hedged HEDGING STRATEGY Current Oil Hedges 50,000 40,000 30,000 20, average: 34% 2016 average floor price ~ CAD $83.00/bbl 2017 average floor price ~ CAD $81.00/bbl 2018 average floor price ~ CAD $80.00/bbl 2017 average: 11% 2018 average: 6% 40% 30% 20% 10,000 10% - Q1 16 Q2 16 Q3 16 Q4 16 Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 Swaps Percent Hedged w/o Extendables Flexibility in a lower oil price environment 0% 80,000 60, potential average hedge: ~50% Ability to optimize long-term hedge book in ,000 20,000 - Q1 16 Q2 16 Q3 16 Q4 16 Current '17/18 hedge crystallization Potential hedging gains of ~$130 million from crystallizing 2017/2018 oil and gas WTI US$/Cdn$0.72 exchange for 2016 Implied 2016 average hedge floor US$40/bbl WTI = ~ CAD $80.00/bbl As of January, Percentage of 2016 guidance is based on mid-point of 2016 budget range. Disciplined hedging strategy reduces volatility 5

6 FOCUSED GROWTH: LARGE OIL IN PLACE ~22 billion barrels of Original Oil in Place ~3% recovered to date Viewfield Bakken Shaunavon Flat Lake / Midale Viking Conventional Saskatchewan focused (~75% of production) No material impact from ongoing Alberta royalty review (~10% of production) OOIP >6.8 billion barrels OOIP >6.4 billion barrels High-return drilling program Top-quartile netbacks supported by low operating costs and favourable CAD/US dollar exchange rate Approximately two-thirds of 2016 program pays out in 2 years or less* OOIP >5.2 billion barrels Uinta Basin Focused on long-term value creation Shallow nature of reservoirs create a waterflood advantage Advancing core plays through step-out drilling and new technology Financing growth with cash flow *Well payouts are based on October 1 st GLJ price deck: 2016 WTI US$50/ Cdn$0.75 exchange 6

7 2016 CAPITAL BUDGET: LIVING WITHIN CASH FLOW Capital Expenditures ($) Disciplined Capital Spending Plan 2016 Guidance Range Production (boe/d) 165, ,000 Total Capital Expenditures Capital Expenditures $950 million $1.3 billion ~$1.3 billion Total Payout Ratio* 100% 94% Debt to Funds Flow from Operations * 2.8x 2.1x * Ranges for total payout ratios and debt to funds flow from operations are based on WTI US$40/bbl to US$60/bbl. US$40/bbl scenarios include the expected impact of monetizing 2017/2018 oil and gas hedges in Strong first-half capital program; will adjust second-half spending based on commodity price outlook Spring Break-up ~$950 million Annual production up 1% to 5% over 2015 guidance and capital expenditures down 16% to 39% compared to 2015 estimates Capital budget focused on: Protecting balance sheet, production levels and dividend Strong first-half capital program with flexibility to adjust second-half spending and production in response to commodity prices Accelerating waterflood programs; >120 water injection conversion wells planned for 2016, up 70% from 2015 Expanding economic boundaries of core resource plays ~84% of capital expenditures allocated to drilling and completions 7

8 EFFICIENT ALLOCATION OF CAPITAL 2016 Budget: Key Focus Areas % of 2016 Capital Budget (% of 2015 Guidance) Half-Cycle Capital Efficiency ($/boe/d) (5) Corporate Inventory (net locations) Inventory In Years Viewfield 23% (25%) ~$17,000 ~1,400 ~12 years Shaunavon 18% (17%) ~$19,000 ~1,800 ~18 years Flat Lake / Unconventional Midale 16% (18%) ~$18,000 ~860 ~14 years Viking 11% (9%) ~$28,000 ~1,000 ~7 years Conventional 10% (12%) ~$20,000 ~1,000 ~14 years Uinta 7% (12%) ~$20,000 ~1,400 >50 years Percentage of 2016 guidance based on the mid-point of budget range, and 2014 net well inventory count. Capital allocation by area is based on economic returns, the life-cycle of each play and the Company s long-term strategic initiatives Significant drilling inventory with attractive capital efficiencies FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 8

9 COST-FOCUSED Viewfield Bakken Play: Drilling & Completion Cost Reductions Long-Term Operational Efficiencies: $2.0M $1.4M $0.4M due to cost savings (~67%) $0.2M due to efficiencies (~33%) $1.3M ~1/3 of cost savings are a result of company initiatives to improve processes and practices Efficiencies are expected to be retained as commodity prices increase Locking in Savings: Increased Q4/15 drilling activity in order to lock-in realized cost savings and to enter 2016 in an even stronger position 2014 Current ~30% improvement versus E Expect an additional 5% to 10% savings Expect additional cost savings to materialize should commodity prices remain depressed Costs and efficiencies continue to adjust to the current environment 9

10 Payout (Months) HIGH-RETURN, QUICK-PAYOUT ASSET BASE 60 Type Well Payouts by Play Current capital costs 10% reduction 48 26% Rate of Return 36 Payouts: less than 3 Years 24 Payouts: less than 2 Years % Rate of Return Viewfield Bakken SE SK Conventional Flat Lake Torquay Midale Unconventional SK Viking Shaunavon (Upper & Lower) Swan Hills Uinta (Vertical) ~2/3rds of 2016 program at current capital costs* Type Well 85 Type Well Type Well Type Well Type Well Type Well Type Well Type Well Well payouts are based on October 1 st GLJ price deck: 2016 WTI US$50/ Cdn$0.75 exchange High-return asset base provides capital flexibility during current environment 10

11 Cumulative Injection well count* Corporate Decline Rate (%) WATERFLOOD SCALE AND STRATEGY Water Injection Well Conversions and Corporate Decline Rate Horizontal Waterflood Comparison 300 ~285 45% Tight Oil Unconventional Resource Plays Province E&P Companies Total Affected Waterflood Production (bbl/d) Pilot Initiated Viewfield Bakken SK CPG ~22, % 28% 35% Shaunavon SK CPG ~11, Shaunavon SK 1 E&P ~ Cardium AB 4 E&Ps ~6, % Slave Point AB 4 E&Ps ~5, Viking SK 3 E&Ps ~4, % 2011A B 2016A2016E 2016B Cumulative Water Injection Well Count Corporate Decline Rate Reduced corporate decline rate due to waterflood development and disciplined capital activity Waterflood advancement has the potential to reduce the relative corporate decline by ~4% to ~7% per year over the next several years Montney AB 5 E&Ps ~4, Swan Hills AB 2 E&Ps ~2, Swan Hills AB CPG ~1, Viking AB 2 E&Ps ~ Viking AB CPG ~ TOTAL ~56,300 Source: GeoScout Canada. Waterflood affected production based on horizontal injection wells Plans for waterflood development in each of the company s core oil plays by the end of 2016 *Water injection well conversions for Viewfield Bakken and Shaunavon Viewfield Bakken is the largest unconventional oil pool in North America currently under commercial waterflood, with plans for expansion to ~30,000 bbl/d (Wood Mackenzie Canada Ltd.) Waterfloods lower decline rates, increase recovery factors and generate significant free cash flow 11

12 Oil Rate (bbl/d) VIEWFIELD BAKKEN WATERFLOOD 160 Viewfield Waterflood Offset Well EURs ~3x greater versus Primary (6)(7) Example of Per Section Bakken Recoveries and Economics OOIP (MMbbls) Estimated Recovery Factor (8) Incremental EURs (mbbls) Cumulative F&D costs (per bbl) 100 Development EUR (mbbls) 4-well Spacing 6.1 ~10% 615 ~$ Primary Infill 100 $1.8M Waterflood Indirect offset 125 $2.3M Waterflood Direct Offset 350 $5.0M Years EUR: 350 mbbls EUR: 125 mbbls EUR: 100 mbbls 8-well Spacing 6.1 ~19% 553 ~$13 Waterflood 6.1 ~30% 676 ~$9 Waterflood 6.1 ~40% 615 ~$7 Includes historical land acquisition costs of $1M per section, primary well costs of $1.8M and waterflood injector conversions of $0.4M per well. Current primary well costs are ~$1.4M. 100mbbl Infill Direct Offsets Indirectly Affected Indirect = 125mbbl DO = 350mbbl Currently producing from ~180 direct offset wells in the Viewfield Bakken *October 1 st GLJ price deck: 2016 WTI US$50/ Cdn$0.75 exchange FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 12

13 Average Production (boe/d) FOCUSED ON LONG-TERM SUSTAINABILITY Improving Long-Term Sustainability 2016 Capital Budget Break-Down (In $Millions) 2016E Range Long-Term Capital >$ , ,000 $2.1 B 165, ,000 $2.50 $2.00 Waterflood Injection Well Conversions Step-Out Drilling New Completions Technology 120,000 80,000 $1.2 B 73,799 $1.50 $950 M- $1.3 B $1.00 Land and Seismic Drilling Capital Efficiencies* ~$21,000 / boe 40,000 $0.50 Drilling Capital Efficiencies (ex. Long-Term Capital)* ~$19,000 / boe E** 2016E** $0.00 Production (boe/d) Development Capital ($Billions) Reallocating capital from long-term projects to highergrade drilling would add up to ~3,000* boe/d to 2016 average production guidance Over the last 5 years: Reduced decline rate by ~20% (from 35% to 28%) Improved capital efficiencies by ~30% (driven by both cost reductions and capital efficiencies) Capital expenditures plans during 2016 are comparable to 2011 levels, when the company averaged only ~74,000 boe/d * Based on mid-point of 2016 guidance ** Based on capital expenditures estimate 13

14 Production (boe/d) SUSTAINABLE ORGANIC GROWTH 250,000 4-Year CAGR Production per share of 3% to 5% + Dividend Yield 200, , ,000 4-Year CAGR Production per share of 7% + Dividend Yield ~210,000* ~194,000** Estimated cumulative free cash flow, after dividends, of up to ~$800 million by 2019 available for debt repayment or additional growth capital 50, scenarios exclude accretive acquisitions or benefits from waterflood E 2019E Organic Scenarios D/CF 1.3x 1.3x 2.1x 1.1x 1.8x * ~210,000 boe/d of 2019 production assumes: 2015E WTI US$49.48, 2016 WTI US$50.00, 2017 WTI US$60.00, 2018 WTI US$70.00, 2019 WTI US$ **~194,000 boe/d of 2019 production based on Oct. 1, 2015 GLJ price deck: 2015E WTI US$49.48, 2016 WTI US$50.00, 2017 WTI US$55.00, 2018 WTI US$60.00, 2019 WTI US$ Strong organic per share growth plus income 14

15 SUMMARY Proven Management Team Proven track record of per share reserves, production and cash flow growth 5-year weighted average F&D of $19.33 per 2P boe of reserves (2.6 times recycle ratio) (9) Cost-focused producer with strong netbacks and capital efficiencies Excellent Balance Sheet Conservative and flexible capital budget to live within cash flow and maintain balance sheet strength Utilize internal funding to complete future acquisitions 3½-year hedging program provides cash flow stability and balance sheet protection High-Quality Reserve Base Efficiently allocating capital across high-quality asset base ~7,460 net locations in drilling inventory primarily within low cost, high-return basins (4) >12 years of low-risk drilling inventory with a large inventory of potential unbooked upside (3) Large OOIP of ~22 billion barrels with only ~3% recovered to date FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 15

16 APPENDIX 16

17 ORIGINAL OIL IN PLACE ~22 BILLION BARRELS Key Focus Areas OOIP (mmbbls) Recovery to Date* Independent Recovery Factor (P+P)** Shaunavon 5, % 3.9% Uinta Basin 5, % 3.5% Viewfield Bakken 4, % 10.3% Viking 1, % 5.2% Midale Unconventional 1, % 3.3% Turner Valley 1, % 20.8% Flat Lake % 4.4% Swan Hills % 9.2% Cantuar % 20.8% Battrum % 35.8% Other % 22.9% TOTAL 21, % 7.4% *As of December 31, 2014 ** Calculated by dividing CPGs net OOIP by reserves assigned by independent engineering evaluators 17

18 LARGE UNBOOKED INVENTORY Key Focus Areas Total Net locations (4) Proved Locations Probable Locations Remaining Unbooked Internally Identified Locations (4) Shaunavon ~1, ~1,007 Viewfield Bakken ~1, ~545 Uinta ~1, ~1,029 Conventional ~1, ~562 Viking ~1, ~460 Flat Lake / Midale Unconventional ~ ~635 Proved and probable locations evaluated by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 18

19 VIEWFIELD BAKKEN Q3/15 production: ~62,000 boe/d ~1,400 net drilling locations ~4.6 billion barrels of Original Oil in Place with recovery to date of 3.5% Continue to implement new completions technology resulting in improved overall returns, recovery factors and water consumption Producing oil wells directly offsetting injection wells demonstrating significant improvements in decline rates and approximately three times the estimated ultimate recovery Crescent Point Energy lands Viewfield Bakken edge Waterflood Unit outline (Four Units in total) Waterflood affected area Completed first unitization of Stoughton Unit during Q1/15 with three additional unitizations in progress; budgeted injection conversions of ~50 wells in 2016 up from ~30 in 2015 Working towards eliminating the use of fresh water during the completions process 60/40 Crown/Freehold; 0% GOR, Type Well October 1 st GLJ price deck 2016 WTI US$50 and US$/Cdn$0.75 exchange Capital Cost Scenario Type Well (mbbls) Cost per well ($M) 10% ($M) Rate of Return (%) Payout (months) Current capital costs $1.4 $1.1 to $ to to 19 10% reduction $1.3 $1.2 to $ to to 15 19

20 Production (boe/d) STRATEGIC ASSET BASE WITH STRONG ECONOMICS Viewfield Bakken Infill Type Well (75 mbbls) Comparison Viewfield North Dakota Land Majority crown Majority freehold Royalties Crown holiday, No holiday, ~10% royalty ~30% royalty Efficiencies Multi-well batteries, no day camps Single-well batteries, camps for workers Year Capital Shallower wells, lower cost wells Deeper wells, higher cost wells 75 mbbls infill type well 60/40 Crown/Freehold; 0% GOR, Type Well October 1 st GLJ price deck 2016 WTI US$50 and US$/Cdn$0.75 exchange Average Production (boe/d) Average Oil Production (bbl/d) Average Oil Price (C$/bbl) Average Royalty (%) Average Op Cost ($/boe) Average Netback ($/boe) Cumulative Cash Flow (M$) (excl. initial capital) Year $ $6.30 $41.14 $951 Year $ $9.22 $41.38 $1,409 Drilling and completion capital costs of $1.4 million 20

21 SHAUNAVON Q3/15 production: ~25,000 boe/d ~1,800 net drilling locations ~5.3 billion barrels of Original Oil in Place with recovery to date of 1.0% Upper Shaunavon wells exceeding expectations Producing oil wells directly offsetting injection wells demonstrating significant improvements in decline rates and approximately two times the estimated ultimate recovery Continue to advance waterflood with ~30 injection well conversions planned for 2016 Working towards eliminating the use of fresh water during the completions process (50% of wells completed during Q3/15 did not use fresh water) Crescent Point Energy lands Lower Shaunavon edge Upper Shaunavon edge Waterflood affected areas Type Well October 1 st GLJ price deck 2016 WTI US$50 and US$/Cdn$0.75 exchange Capital Cost Scenario Type Well (mbbls) Cost per well ($M) 10% ($M) Rate of Return (%) Payout (months) Waterflood Voluntary Unit Current capital costs $1.5 - $1.6 $0.8 to $ to to 40 10% reduction $1.4 $0.9 to $ to to 32 Based on Upper and Lower Shaunavon type well economics 21

22 Oil Rate (bbl/d) SHAUNAVON WATERFLOOD Shaunavon Waterflood Offset Well EURs ~2x greater versus Primary (6)(7) Development EUR (mbbls) Primary Infill 84 $0.8M Waterflood Indirect offset 100 $1.1M Waterflood Direct Offset 160 $1.9M Example of Per Section Shaunavon Recoveries and Economics OOIP (MMbbls) Estimated Recovery Factor (8) Incremental EURs (mbbls) Cumulative F&D costs (per bbl) 4-well Spacing 13.5 ~6% 810 ~$ mbbl Infill Years Direct Offsets EUR: 160 mbbls EUR: 100 mbbls EUR: 84 mbbls Indirectly Affected 8-well Spacing 13.5 ~10% 540 ~$14 Waterflood 13.5 ~15% 675 ~$10 Includes land acquisition costs of $1.5M per section, primary well costs of $2.5M and waterflood injector conversions of $0.4M per well. Current primary well costs are ~$1.6M. OOIP per section based on lower Shaunavon OOIP estimates only. Indirect = 100mbbl DO = 160mbbl Currently producing from ~77 direct offset wells in the Shaunavon The Shaunavon waterflood is at an earlier stage of development in comparison to the Viewfield Bakken waterflood *October 1 st GLJ price deck: 2016 WTI US$50 / Cdn$0.75 exchange FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 22

23 FLAT LAKE / MIDALE UNCONVENTIONAL Q3/15 area production: ~16,000 boe/d Viewfield Bakken Flat Lake: (Torquay/Three Forks, Bakken and Ratcliffe) ~460 net drilling locations ~1 billion barrels of Original Oil in Place with recovery to date of ~0.6% ~290 net sections in the core boundary; continues to expand New Ratcliffe zone (low capital costs / un-fracked wells) First waterflood pilot to be initiated during 2016 Flat Lake Flat Lake/Midale lands Crescent Point Energy lands Flat Lake/Midale edge USA border Midale Unconventional Midale: (Midale, Torquay/Three Forks and Bakken) >400 net drilling locations >1 billion barrels of Original Oil in Place with recovery to date of ~0.4% Increasing water injection wells in 2016, building on success of initial pilots Torquay (Three Forks) economics Type Well October 1 st GLJ price deck 2016 WTI US$50 and US$/Cdn$0.75 exchange Midale unconventional economics Type Well October 1 st GLJ price deck 2016 WTI US$50 and US$/Cdn$0.75 exchange Capital Cost Scenario Type Well (mbbls) Cost per well ($M) 10% ($M) Rate of Return (%) Payout (months) Capital Cost Scenario Type Well (mboe) Cost per well ($M) 10% ($M) Rate of Return (%) Payout (months) Current capital costs $2.3 $1.3 to $ to to 31 10% reduction $2.0 $1.6 to $ to to 23 Based on 1-mile horizontal well economics Current capital costs $1.7 $1.2 to $ to to 21 10% reduction $1.5 $1.4 to $ to to 17 Based on an average type well for the Steelman / Pinto Midale area 23

24 UINTA BASIN Multi-Zone Basin Blacktail Ridge Rocky Point Greater Monument Butte Randlett Ouray Valley Gusher Aurora Horseshoe Bend Lake Canyon Crescent Point Energy lands Q3/15 production: >15,000 boe/d Zones tested horizontally since late 2014 ~1,400 net low-risk vertical drilling locations 5.2 billion barrels of Original Oil in Place with recovery to date of 0.5% Oil price differentials continue to improve Type Well October 1 st GLJ price deck 2016 WTI US$50 and US$/Cdn$0.75 exchange Capital Cost Scenario Type Well (mbbls) Cost per well (US$M) 10% (US$M) Rate of Return (%) Payout (months) Current capital costs $1.4 - $1.6 $0.9 to $ to to 43 10% reduction $1.1 - $1.3 $1.2 to $ to to 27 Advancing waterflood pilot during 2016 Based on Randlett North and South (tribal and non-tribal) vertical economics 24

25 CREATING LONG-TERM VALUE FOR SHAREHOLDERS Growth + Dividend Strategy CPG Base Business Waterflood Expansion Technology Initiatives M&A Large OOIP resources with low recovery to date High-return asset base Control of infrastructure Manage risk (i.e. hedging and strong balance sheet) Lower decline rates and future capital requirements Increase ultimate recoveries over primary development Increase recoveries and capital efficiencies Expand programs from vertical into larger horizontal opportunities Allows for discovery of new plays History of creating value on a per share basis - reserves, cash flow and production - while also adding quality drilling locations Opportunity to lever technical expertise Dividend provides capital discipline Unlocking value irrespective of commodity prices 25

26 PF (2) E 2016E PROVEN TRACK RECORD 200,000 Production Growth (boe/d) $3,000 Funds Flow (millions) 160,000 $2, ,000 80,000 $2,000 $1,500 $1,000 40,000 $500 0 $0 1,000 P+P Reserves (MMboe) 3.0x Debt to Cash Flow x x x Proven track record of delivering growth and income FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 26

27 PER SHARE FOCUS Production per Share 2P Reserves per Share CAGR 6.7% + Dividend Yield CAGR 6.1% + Dividend Yield E 2016E* PF (2) Integrated strategy of organic development and acquisitions has consistently generated growth on a per share basis Historical five-year 2P F&D of $19.33/boe with a recycle ratio of 2.6 times (9) Declared $30.94 of dividends per share to shareholders from inception to September 30, 2015 Suspended the dividend reinvestment plans (DRIP and SDP) effective August, 2015, further enhancing per share growth * Ranges for production per share based on WTI US$40/bbl to US$60/bbl. US$40/bbl scenarios include the expected impact of monetizing 2017/2018 oil and gas hedges in Continue growing on a per share basis FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 27

28 FAVOURABLE WATERFLOOD RESERVOIRS Low Mobility Ratios* Enhance Waterflood Oil Recovery Crescent Point benefits from shallow, low-cost reservoirs with characteristics attractive for waterflood development Majority crown ownership and unitization accelerates waterflood implementation and efficiency Viewfield Bakken Shaunavon Battrum Mobility Ratio Recovery to Date 3.5% 1.0% 26.3% New resource plays with attractive mobility provide opportunity for increased recovery *Mobility ratio is defined as the oil s ability to move within the rock; permeability divided by viscosity 28

29 Reserve additions (Mmboe) ORGANIC VERSUS ACQUISITION GROWTH to P Reserve Additions Organic: 491 MMboe (10) Acquired: 447 MMboe Technical Reserve Additions (Mmboe) Acquired Reserves (Mmboe) Organic technical reserve additions have been a consistent contributor to Crescent Point s long-term success due to step-out and infill drilling, waterflood optimization and improved technology Crescent Point pursues a balanced strategy of organic development and acquisitions FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 29

30 ACQUISITION HISTORY: RESERVES MORE THAN DOUBLED Property Initial 2P Reserves (Mboe) Estimated Production (Mboe) Current 2P Reserves (Mboe) Total 2P Reserves (Mboe) Increase in 2P Reserves (Mboe) % Increase in Reserves Sounding Lake 2,437 4,119 3,312 7,431 4, % Manor/Tatagwa Unit 8,167 15,385 18,004 33,389 25, % Little Bow 2,872 2,873 2,352 5,225 2,353 82% Subtotal 13,476 22,377 23,668 46,045 32, % SW Sask 132,077 44, , , ,934 84% Viewfield Resource 103,071 96, , , , % Flat Lake Resource 3,178 3,746 33,572 37,318 34,140 1,074% Canada Subtotal 251, , , , , % Utah 61,787 9,013 88,393 97,406 35,619 58% North Dakota 3,547 4,571 37,418 41,989 38,442 1,084% CPG TOTAL 317, , , , , % As of December 31, 2014 as evaluated by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. Excludes reserves from Legacy Oil + Gas Inc. and Coral Hill Energy Ltd. Total 2P reserves = estimated production plus current 2P reserves. Increased 2P reserves by >482 million boe (152%) Large oil in place pools have outperformed initially estimated recoveries over time 30

31 PIONEER IN ADVANCING NEW TECHNOLOGY Completed first cemented liner in the Bakken oil resource play 8 stages Initiated waterflood pilots in the Bakken oil resource play to increase recovery factors and reduce decline rates Began to transfer technology know-how to the Shaunavon oil resource play including first waterflood pilot Became the largest horizontal driller in the Canadian Bakken oil resource play Expanded waterflood area within the core of the Bakken oil resource play and increased production response Increased stage counts in the Shaunavon and Bakken oil resource play. Reduced sand tonnage in the Bakken play Increased recoveries and reduced per well costs Committed to 100% cemented liner completions in the Bakken play after developing, proving and refining the technology Became the largest driller of horizontal wells in Canada Committed to 100% cemented liner completions in the Shaunavon play after transitioning the technology from the Viewfield Bakken resource play Early to adopt and utilize a two-mile coil tubing cemented liner completion in a tight rock play in North America New closeable sliding sleeve technology allows for the ability to control and divert water within the well-bore while also limiting sand flow-back Adopted new completion fluids and propants in the Viewfield Bakken and Flat Lake resource plays 372 Gross Wells Drilled 1,484 Gross Wells Drilled 2,249 Gross Wells Drilled* *As of Q

32 Mbbl % change since 2012 (MMboe) VIEWFIELD BAKKEN TECHNOLOGY ADVANCEMENTS 300 Viewfield Bakken Independent type well changes (11) (Primary recovery 3 twp core) 40% Change in Ultimate Recoverable Reserves (MMboe) assigned by Independent Evaluators due to waterflood (12) (Secondary Recovery) % 26% % 16% % 0 Surgi Frac 16 stage packer Frac 16 stage cemented liner 25 stage cemented liner 0% Technology has shown to be a significant value creator over time; net present value (@ 10%) per-well has more than tripled with technology evolutions (October 1 st GLJ 2016 WTI US$50 and US$/Cdn$0.75) New closable sliding sleeve technology allows for: Second consecutive year of waterflood reserve additions recognized by independent engineers New Closable Sliding Sleeve Technology Potentially lower costs by minimizing sand flow-back (primary recovery) Greater efficiency and productivity of waterflood programs through increased control of water placement, potentially leading to enhanced recovery factors (secondary recovery) Source: NCS Multistage Technology advancements continue to be transferred to our emerging plays FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES 32

33 Stages per well Tonnage per stage Rate of Return % Water (m3) per well Days per well IMPACT OF TECHNOLOGY IMPROVEMENTS Viewfield Bakken Fresh Water Usage Viewfield Bakken Drilling Progression Spud to Rig Release Targeting to eliminate fresh water usage during completions by yearend YTD YTD 30 Viewfield Bakken Stage and Tonnange Evolution Viewfield Bakken well ROR (3 twp core) October 1 GLJ price deck 2016 WTI US $50 and Us$/Cdn $0.75 exchange >500% increase in rate of return YTD 0 0 Surgifrac 16 Stage Packers Plus 16 Stage Cemented Liner 25 Stage Cemented Liner 33

34 Million $ CAD BALANCE SHEET STRENGTH Debt Composition 250 Senior Guaranteed Notes Maturity Schedule $1.8B Senior Guaranteed Notes* $1.4B Unutilized Credit Capacity $2.2B Drawn from Bank Credit Facilities Less than 1 year 1-3 Years 3-5 Years Bank credit facility = C$3.6 billion (~$1.4 billion unutilized) Unsecured, covenant-based with current borrowing rate <4% Renewal date June 2018 Senior unsecured notes = C$1.8 billion* Private placement market Notes are designated NAIC 2 and rank equally with bank credit facility; weighted average interest rate of 4.6% No material debt maturities due near-term *As at September 30, 2015,including cross-currency interest rate swaps on $USD senior guaranteed notes Significant amount of liquidity and financial flexibility 34

35 Operating Costs ($) / boe QUARTERLY OPERATING COST ANALYSIS $15.00 $12.61 $0.49 $0.88 $0.17 ($1.40) $12.75 $10.00 $5.00 $0.00 Q3/14 A Impact from cost structure of recent acquisitions Timing of annual property taxes and other fees Impact of $USD appreciation on U.S. assets Operating cost savings Q3/15 A ~11% reduction in operating costs year over year when excluding one-time adjustments, $USD appreciation and the impact from recent acquisitions A significant portion of operating costs are fixed Operating costs are expected to continue to improve due to ongoing cost saving initiatives and synergies realized from recent acquisitions 35

36 G&A/boe G&A as a % of operating netback INDUSTRY LOW G&A CPG G&A History and 2014 Peer Comparison $3.00 8% $2.50 $2.00 7% 6% 5% $1.50 $1.00 $0.50 $ PEER AVG G&A/boe G&A as a % of operating netback 4% 3% 2% 1% 0% Top-quartile netbacks enhanced by industry low G&A costs Oil-weighted peers include: ARC Resources, Baytex Energy, Bonavista Energy, Cenovus Energy, Continental Resources, Enerplus Resources, Pengrowth Energy, Penn West Petroleum and Whiting Petroleum 36

37 ENDNOTES 1. Fully diluted shares outstanding as of September 30, Based on December 31, 2015 market closing price of $ Directors and officers ownership represents 0.7% of issued and outstanding shares as of November 2, As of December 31, 2014 plus reserves effective June 30, 2015 from the acquisition of Legacy Oil + Gas Inc. and reserves effective July 31, 2015 from the acquisition of Coral Hill Energy Ltd., as independently evaluated by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. 3. Calculated using 2015 guidance production of 163,500 boe/d and the drilling of 583 net wells. 4. Approximately 7,460 net drilling locations, of which 2,391 net are proved and 934 net are probable reserve locations as independently evaluated by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. The remaining net locations are internally identified locations that are unbooked. 5. Half-cycle capital efficiencies are based upon the 2016 drilling program, current capital costs and annual average production per well. Capital costs exclude land and facilities. 6. The non-waterflood infill profile is based on an internal evaluation of existing, 200 meter direct offset infill drilled wells where no waterflood influence has occurred, normalized to start of production. 7. Waterflood reserve additions represent internally evaluated incremental reserves over the average primary type curve described above. 8. Estimated recovery factors are based on independent (P+P) reserves, comparable analog pools, independent studies commissioned by Crescent Point Energy and company targets. 9. As of December 31, 2014, excluding the change in future development capital and based on the five year average netback (prior to realized derivatives) of $50.58 per boe. 10. Positive reserve revisions include reserves obtained from Discoveries, Extensions, Infill Drilling, Improved Recovery, Technical Revisions and Economic Factors as defined in COGEH. 11. Well results are based on independently generated curves by Sproule Associates Limited. Results are indicative of typical Estimated Ultimate Recovery levels based on proved plus probable reserves for each completion type. 12. Waterflood reserve additions represent reserves over primary, as evaluated by independent reserve evaluators, for areas that are directly under waterflood. 37

38 DEFINITIONS / NON-GAAP FINANCIAL MEASURES DEFINITIONS: 1. Original Oil in Place (OOIP) is equivalent to Discovered Petroleum Initially-In-Place (DPIIP) as at December 31, 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. 2. OOIP/DPIIP estimates and recovery rates are as at December 31, 2014 and are based on current accepted technology and prepared by Crescent Point s qualified reservoir engineers. 3. Cash flow equates to funds flow from operations. Cash flow from operations equals funds flow from operations per share. 4. Net present values disclosed in this presentation are calculated before tax. 5. Enhanced Ultimate Recovery relates to the extraction of additional crude oil, natural gas, and related substances from reservoirs through a production process other than natural depletion, which includes both secondary and tertiary recovery processes such as pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. 6. Dividend reinvestment plans include the Dividend Reinvestment Plan (DRIP) and Share Dividend Plan (SDP). 7. Type wells are internally generated based on actual well results and data that is interpreted by internal qualified reserves evaluators. NON-GAAP FINANCIAL MEASURES: Throughout this presentation, the Company uses the terms funds flow, funds flow per share, half-cycle capital efficiency, market capitalization, net debt, net debt to funds flow from operations and total payout ratio. These terms do not have any standardized meaning as prescribed by International Financial Reporting Standards ( IFRS ) and, therefore, may not be comparable with the calculation of similar measures presented by other issuers. Funds flow is calculated based on cash flow from operating activities before changes in non-cash working capital, transaction costs and decommissioning expenditures. Funds flow per share is calculated as funds flow divided by the number of weighted average diluted shares outstanding. Management utilizes funds flow as a key measure to assess the ability of the Company to finance dividends, operating activities, capital expenditures and debt repayments. 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. Netback is calculated on a per boe basis as oil and gas sales, less royalties, operating and transportation expenses. Netback is used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis. Half-cycle capital efficiency is calculated as the capital expenditure required to replace a barrel equivalent (boe) of oil. Management utilized half-cycle capital efficiency as a key measure to assess the economic viability of a particular well. 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. 38

39 DEFINITIONS / NON-GAAP FINANCIAL MEASURES Net debt is calculated as long-term debt plus accounts payable and accrued liabilities and dividends payable, less cash, accounts receivable, prepaids and deposits and long-term investments, excluding the equity settled component of dividends payable and unrealized foreign exchange on translation of US dollar senior guaranteed notes. Management utilizes net debt as a key measure to assess the liquidity of the Company. Net debt to funds flow from operations is calculated as the net debt divided by funds flow from operations. The ratio of net debt to funds flow from operations 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. Total payout ratio is calculated on a percentage basis as annual capital expenditures and annual dividends paid divided by annual funds flow from operations. Total payout ratio is used by management to monitor the dividend policy and the Company s capital reinvestment, as a percentage of the amount of funds flow from operations. 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. 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 refer to the Company s most recent annual Management s Discussion & Analysis ( MD&A ) available on SEDAR as sedar.com, or EDGAR as and on our website as OIL AND GAS METRICS: This presentation includes oil and gas metrics including drilling inventory, finding and development costs, netback, mobility ratio and recycle ratio. 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 calculated in years as net well count guidance divided by remainder of inventory. Drilling inventory and current inventory are used by management to assess the amount of available drilling opportunities. Finding and development costs (or F&D ) are calculated in dollars by dividing the capital required by the number of barrels being produced. Finding and developments costs are the amounts spent to locate, and establish commodity reserves. Netback is calculated on a per boe basis as oil and gas sales, less royalties, operating and transportation expenses. Netback is used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis. Mobility ratio is defined as the oil s ability to move within the rock and is calculated by dividing the permeability of the reservoir s rock by the viscosity of the fluid within the reservoir. It is used to determine the ease of which OOIP may be extracted. Recycle Ratio is calculated as [the profit per barrel divided by the total cost of discovering and extracting the barrel. For the purposes of this presentation the recycle ratio is calculated as netback divided by finding and development costs per barrel. It is used in determining the profitability of the Company. 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. 39

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