CORPORATE PRESENTATION

Transcription

1 CORPORATE PRESENTATION December 2013

2 TSX: CPG 2013 Exit Production: 124,000 boe/d (>90% oil weighted) (1) 2014 Exit Production: 135,000 boe/d (>90% oil weighted) (2) Netback: $51.25/boe (3) Yield: 7.2% (4) Annual Dividend: $2.76/share Payout Ratio: 53% (2)(5) Market Capitalization: $15.2 billion (4) Enterprise Value: $17.1 billion (4)(6) P+P Reserves: million boe (RLI: 13.2 years) (7) Drilling Inventory: >6,600 locations (8) (11.1 years of inventory) (9) 1. FOOTNOTES LOCATED AT THE BACK OF THE PRESENTATION AS ENDNOTES. 2

3 2014 CAPITAL PROGRAM FOCUS Building on the successes of technology advances 25-stage cemented liner completions in the Bakken and Shaunavon plays Improved production performance Lower decline rates Unconventional Resource Play waterfloods Increased recovery factors on large oil in place assets Lower F&D costs and higher recycle ratios Lower decline rates 3

4 2014 CAPITAL PROGRAM SUMMARY $1.75 billion capital expenditures program 126,500 boe/d annual average production rate (6% increase over 2013 guidance) 135,000 boe/d exit production rate (9% increase over 2013 exit guidance) <$30,000 per flowing boe organic growth capital efficiency (excluding facilities, land and seismic) 604 net wells planned Total of 53 producing wells to be converted to water injection wells in the Bakken and Shaunavon plays 4

5 BAKKEN, SHAUNAVON & UINTA BASIN CAPITAL FOCUS 2014 Capital Budget Net Capital ($MM) Net Wells Drilling, completions and production optimization Viewfield Bakken & Flat Lake $ Shaunavon $ Uinta Basin $ Other $ Total drilling, completions and production optimization $1, Facilities, land and seismic $330 - Total $1, Converting 30 Viewfield Bakken producing wells to water injection wells Waterflood currently affecting approximately 5,000 boe/d with 56 injection wells Converting 23 Shaunavon horizontal wells to water injection wells More than doubling the number of Shaunavon horizontal water injection wells Uinta Basin waterflood approval received in Q Water injection anticipated to start in early

6 BUSINESS STRATEGY Develop and exploit Increase recovery factors through infill drilling, waterflood optimization and improved technology Acquire Focus on high-quality, large resource-in-place pools with production and reserves upside Manage risk Maintain strong balance sheet, significant unutilized bank line capacity and 3 ½-year hedging program 6

7 FOCUSED RESERVE BASE Key Value Highlights: 25-stage cemented liner completion technique being further refined in the Bakken and Shaunavon resource plays; lowering declines and reducing water consumption by up to 45% per well Waterfloods in both Viewfield Bakken and Shaunavon plays continue to outperform Entire Shaunavon completion program transitioned to 25-stage cemented liner technology Several field optimization projects underway in Uinta Basin to improve production rates and ultimate recoveries 7

8 VIEWFIELD BAKKEN OIL RESOURCE PLAY Viewfield Bakken Type Well Economics (5) : 1,935 locations in drilling inventory (1) >1,000 additional locations from infill drilling (1) 4.6 billion barrels OOIP with only 2.3% recovered to date (2) >2,300 gross wells on production, 125 million bbls produced to date (3) Possible upside reserves potential of >200 million bbls on primary recovery (4) Type Well EUR Production (bbl/d) 1 st Month Avg Production (bbl/d) 1 st Year Avg. 10% Rate of Return Payout (Months) 75 mbbls $1,676 80% mbbls $5, % 6 Crescent Point Lands Viewfield Bakken future drilling location 75 mbbls EUR type well contour curve 175 mbbls EUR type well contour curve 1. FOOTNOTES LOCATED AT THE BACK OF THE PRESENTATION AS ENDNOTES. 8

9 SHAUNAVON OIL RESOURCE PLAY 1,875 locations in drilling inventory (1) >1,000 additional drilling locations through infill drilling (1) 4.3 billion bbls OOIP with 0.8% recovered to date (2) Approximately 600 gross wells on production, 24 million bbls produced to date (3) Government approval received for Lower Shaunavon waterflood unitization Possible upside reserves potential of >250 million bbls on primary recovery (4) Shaunavon Type Well Economics (5) : Type Well EUR Production (bbl/d) 1 st Month Avg Production (bbl/d) 1 st Year Avg. 10% Rate of Return Payout (Months) 84 mbbls $1,515 45% mbbls $3, % 11 Crescent Point Lands Shaunavon Drilling Inventory 84 mbbls EUR type well contour curve 168 mbbls EUR type well contour curve 1. FOOTNOTES LOCATED AT THE BACK OF THE PRESENTATION AS ENDNOTES. 9

10 UINTA BASIN OIL RESOURCE PLAY Uinta Basin future drilling locations Crescent Point Lands >1,000 locations identified on Crescent Point lands (1) Current production >10,000 boe/d (2) 5.2 billion bbls of OOIP with only 0.2% recovered to date (3) Possible upside reserves potential of >100 million bbls on primary recovery (4) Randlett Vertical Type Well Economics (5) : Type Well EUR Production (bbl/d) 1 st Month Avg Production (bbl/d) 1 st Year Avg. 10% Rate of Return Payout (Months) 100 mbbls $884 40% mbbls $2, % 8 1. FOOTNOTES LOCATED AT THE BACK OF THE PRESENTATION AS ENDNOTES. 10

11 11 YEARS OF RESERVES GROWTH 2012 Reserves Oil & NGLs (MMbbls) Natural Gas (bcf) Proved (1) P+P (1) Boe (MMboe) year P+P RLI (2) Light and medium oil weighted asset base offers attractive economics and capital efficiencies 5-year weighted average F&D of $17.34/boe (3) 5-year weighted average recycle ratio of 2.8 times Reserves (P+P MMboe) Annual average per share growth of 18% FOOTNOTES LOCATED AT THE BACK OF THE PRESENTATION AS ENDNOTES. 11

12 LARGE OIL IN PLACE Play OOIP (1) (Mmbbls) Recovery to Date Independent Recovery Factor P+P (2) Analog Pools Recovery Factor Possible Reserves (3) (Net Incremental to P+P Reserves Mmbbls) Bakken 4, % 9.4% 19.0% Shaunavon 5, % 3.5% 10.0% Uinta Basin 5, % 1.8% 6.0% Alberta 1, % 4.2% 14.9% 79.9 Various % 22.5% 29.1% 44.8 Cantuar % 21.9% 35.0% 35.5 Battrum % 34.6% 50.0% , % 6.5% 13.9% Predictable production and reserve base with infill drilling/waterflood upside Current P+P reserves of MMboe (2) Low recovery factor to date relative to analogous pools Estimates do not include expected potential for enhanced recovery due to waterflood projects at Viewfield, Shaunavon, Uinta Basin and Viking 1. FOOTNOTES LOCATED AT THE BACK OF THE PRESENTATION AS ENDNOTES. 12

13 LOW RISK/HIGH RETURN INVENTORY Area Net Wells Total Capital (1) ($MM) Total Reserves (2) (Mboe) Resource Plays Production Rate (boe/d) (3) Risked F&D ($/boe) Risked $ per Producing Boe (3) Bakken 2,835 $10, , ,250 $22.41 $18,656 Shaunavon 1,875 $3, , ,375 $21.75 $17,028 Uinta Basin (4) 660 $1,268 77,038 85,800 $16.46 $14,779 Emerging Plays (5) 1,310 $1,941 86,274 95,826 $22.50 $20,255 TOTAL 6,680 $17, , ,251 $21.69 $18,070 $17.3 Billion of risked development inventory drives future growth with over 950,000 boe/d production additions Risked F&D of $21.69/boe and $18,070 per flowing boe with a recycle ratio of 2.4 times (6) 6,680 locations on existing assets all defined by internal geology and engineering (7) Additional 3,400 potential locations through infill drilling in Uinta Basin, Shaunavon and Bakken plays (7) 1. FOOTNOTES LOCATED AT THE BACK OF THE PRESENTATION AS ENDNOTES. 13

14 2014 PRODUCTION GUIDANCE Oil & NGLs (bbls/d) 115,000 Gas (mcf/d) 69,000 TOTAL 6:1) 126,500 Forecast exit of 135,000 boe/d Top quartile netback of $51.25/boe (2) >90% oil weighted 130, , , ,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10, Production (Boe/d) (¹) Annual average per share growth of 7% 2014(²) 1. FOOTNOTES LOCATED AT THE BACK OF THE PRESENTATION AS ENDNOTES. 14

15 HEDGING STRATEGY Oil Hedges bbl/day 70,000 60,000 50,000 40,000 30,000 20,000 10, (¹)% 56% 26% 18% 2% Q4 13 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16 Q % 70% 60% 50% 40% 30% 20% 10% 0% Provide greater stability to dividends Over 60,000 bbl/d of rail capacity Swaps Collars Puts % Hedged $/boe Average Oil Hedge Price Q4 13 Q1 14 Q2 14 Q3 14 Q4 14 Q1 15 Q2 15 Q3 15 Q4 15 Q1 16 Q2 16 Q3 16 Q4 16 Q ,000 bbl/d of fixed WTI price differentials for first half of 2014 provide stability to Western Canadian differentials Market Hedge Price 1. FOOTNOTES LOCATED AT THE BACK OF THE PRESENTATION AS ENDNOTES. 15

16 2014 FUNDS FLOW FORECAST Funds Flow Funds Flow: $2.1 billion (1) Dividend: ($5.24/share) $1.1 billion ($2.76/share) $2,400 $2,200 $2,000 $1,800 $1,600 $1,400 $1,200 Funds Flow ($MM) 2014 Capital: $1.75 billion $1,000 $800 $600 Operations $400 $200 Royalties: 18% Netback: $51.25/boe (1) $ (¹) 2014(²) Net debt to projected average 12-month funds flow of approximately 1.2 times Annual average per share growth of 19% 1. FOOTNOTES LOCATED AT THE BACK OF THE PRESENTATION AS ENDNOTES. 16

17 SUMMARY Proven management team Proven track record of reserves, production and cash flow growth 5-year weighted average F&D of $17.34/boe (1) Excellent balance sheet 3½-year hedging program to provide cash flow stability Balance sheet strength and significant unutilized bank line capacity High-quality reserve base >6,600 (2) net locations in drilling inventory Potential to double P+P reserves over time 1. FOOTNOTES LOCATED AT THE BACK OF THE PRESENTATION AS ENDNOTES. 17

18 ENDNOTES SLIDE 2, CRESCENT POINT ENERGY: market guidance market guidance guidance based on US$95.00/bbl WTI, Cdn$3.25/mcf AECO and US$/Cdn$0.94 exchange rate. 4. Q trading data with a volume weighted average price of $38.29 per Crescent Point share. 5. Payout ratio is calculated as dividends paid or declared (including the value of dividends paid pursuant to the Company s dividend reinvestment plans) divided by funds flow from operations. 6. Net debt as of September 30, Reserve Life Index calculated using 2014 guidance annual average production of 126,500 boe/d. 8. Internally estimated. 9. Inventory Life Index is calculated using 2014 guidance of 604 net drill locations. SLIDE 8, VIEWFIELD BAKKEN OIL RESOURCE PLAY: 1. Internally identified locations. 2. Original Oil in Place (OOIP) is equivalent to Discovered Petroleum Initially-in-Place (DPIIP) as defined in this presentation. 3. Wells producing and cumulative production through the end of September Estimate does not include potential for enhanced recovery due to waterflood projects. 5. Internally evaluated using an October 1, 2013 GLJ Petroleum Consultants ( GLJ ) price deck. SLIDE 9, SHAUNAVON OIL RESOURCE PLAY: 1. Internally identified locations. 2. Original Oil in Place (OOIP) is equivalent to Discovered Petroleum Initially-in-Place (DPIIP) as defined in this presentation. 3. Wells producing and cumulative production through the end of September Estimate does not include potential for enhanced recovery due to waterflood projects. 5. Internally evaluated based on October 1, 2013 GLJ price deck. 18

19 ENDNOTES SLIDE 10, UINTA BASIN OIL RESOURCE PLAY: 1. Inventory accounts for internally identified locations on both operated and non-operated lands. 2. Production current to October 1, Original Oil in Place (OOIP) is equivalent to Discovered Petroleum Initially-in-Place (DPIIP) as defined in this presentation. 4. Estimate does not include potential for enhanced recovery due to waterflood projects. 5. Internally evaluated based on a October 1, 2013 GLJ price deck. SLIDE 11, 11 YEARS OF RESERVES GROWTH: 1. December 31, 2012 reserves. 2. Reserve Life Index calculated using 2014 guidance annual average production of 126,500 boe/d. 3. As of December 31, 2012, excluding the change in future capital development. SLIDE 12, LARGE OIL IN PLACE: 1. Original Oil in Place (OOIP) is equivalent to Discovered Petroleum Initially-in-Place (DPIIP) as defined in this presentation. 2. December 31, 2012 reserves. 3. Internally estimated by Qualified Reservoir Engineers. SLIDE 13, LOW RISK/HIGH RETURN INVENTORY: 1. Total Capital includes facilities, land and seismic. Reserves and production are risked values. 2. Internally estimated by Qualified Reservoir Engineers. 3. Based on first month average. 4. Uinta inventory accounts for operated identified locations in Randlett and does not account for identified locations on non-operated lands. 5. Includes 2 wells per section in Beaverhill Lake. 6. Based on US$95.00/bbl WTI, Cdn$3.25/mcf AECO and US$/Cdn$0.94 exchange rate. 7. Internally identified locations. 8. Numbers may not add due to rounding. 19

20 ENDNOTES SLIDE 14, 2014 PRODUCTION GUIDANCE: guidance based on US$98.00/bbl WTI, Cdn$3.00/mcf AECO and US$/Cdn$0.97 exchange rate guidance based on US$95.00/bbl WTI, Cdn$3.25/mcf AECO and US$/Cdn$0.94 exchange rate. SLIDE 15, HEDGING STRATEGY: 1. Including natural gas hedges, the Company has hedged 68% of its total production, adjusted for royalties, for the balance of SLIDE 16, 2014 FUNDS FLOW FORECAST: guidance based on US$95.00/bbl WTI, Cdn$3.25/mcf AECO and US$/Cdn$0.94 exchange rate. SLIDE 17, SUMMARY: 1. As of December 31, 2012, excluding the change in future capital development. 2. Internally estimated. 20

21 DEFINITIONS 1. Original Oil In Place (OOIP) is equivalent to Discovered Petroleum Initially-In-Place (DPIIP). 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 based on current accepted technology and prepared by Crescent Point s Qualified Reservoir Engineers. 21

22 FORWARD-LOOKING STATEMENTS This presentation contains "forward-looking statements" 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). Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those reflected in the statements. Forward-looking statements are based on the estimates and opinions of the Company's management at the time the statements are made. Crescent Point assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change. 22

23 NON-GAAP FINANCIAL MEASURES Throughout this presentation, the Company uses the terms funds flow, funds flow per share, payout ratio, netback, market capitalization, net debt and enterprise value. 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 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. Payout ratio is calculated on a percentage basis as dividends paid or declared (including the value of dividends issued pursuant to the Company s dividend reinvestment plan) divided by funds flow. 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. Market capitalization is an indication of enterprise value and is calculated by applying a recent volume weighted average share trading price to the number of diluted shares outstanding. Net debt is calculated as current liabilities plus long-term debt less current assets and long-term investments, but excludes derivative asset, derivative liability 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. Enterprise value is calculated as market capitalization plus net debt. Enterprise value is used by management to assess the amount of debt leverage used in the Company s capital structure. 23

24 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 Ltd Olympia Trust Company Trent Stangl, VP Marketing & IR Rob Willson, Investor Relations Cindy Gray, Investor Relations (Toll Free) Suite 2800, 111-5th Avenue SW, Calgary, Alberta T2P 3Y6 T: F: TF: (Canada & USA)