Corporate Presentation February 2017 Crescent Point Energy is one of - - PowerPoint PPT Presentation
Crescent Point Energy Corporate Presentation February 2017 Crescent Point Energy is one of Canadas largest light and medium oil producers, based in Calgary, Alberta. 1 The Company is focused on growing its significant resource base in the
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Crescent Point Energy is one of Canada’s largest light and medium oil producers, based in Calgary, Alberta. The Company is focused on growing its significant resource base in the Williston Basin, Southwest Saskatchewan and the Uinta Basin in Utah.
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: estimates of 2017 average and exit production and capital expenditures and expected 2017 decline rates; the Corporation’s plan to test the new Injection Control Device waterflood technology system in the first half of 2017 with production data expected in the second half of 2017; expected percentage change in organic production growth; plans to test and advance new technologies; plans to expand upon new play development by advancing the horizontal drilling program in the Uinta Basin and accelerating Flat Lake development; target increase in corporate drilling inventory; plans to explore further asset disposition opportunities to fund the additional growth program; debt reduction; continued focus on risk management and improved investor communication; expected 2017 production growth including the opportunity for additional upside; expected 2017 capital expenditures; expected total payout ratio with U.S. WTI prices and expected flexibility to increase capital budget and growth targets at higher oil prices; the Corporation’s business strategy to develop and enhance assets, acquire and manage risk; expected impact of the Corporation’s hedging program on adjusted funds flow volatility and dividend and capital spending stability; estimated years of drilling inventory; expected well payouts; estimated number of wells in 2017 drill program and percentage of 2017 capital expenditures budget; plans to expand in Viewfield Bakken and Flat Lake; the expected focus on efficiency gains in Flat Lake; the expected focus on building off success of recent down-spacing program and increasing efficiencies through pad drilling in North Dakota; plans to optimize the stage/tonnage during completions and add new infrastructure in Shaunavon to accommodate future growth plans; expected Lower Shaunavon 30+ Stage completion outperformance; plans to increase well density; testing of extended reach horizontal wells and implementing closeable sliding sleeves in Viking; expected scalability across multiple zones and increased efficiencies; expected horizontal type curve economics in the Castle Peak Zone; the 2017 budget risk factor; the expected focus on increasing the efficiency of waterflood by testing new multiple-stage segregated strings technology for field-wide implementation and expecting production results by the second half of 2017; 2017 free cash flow as a percentage of enterprise value; estimated adjusted funds flow for every WTI US$1/bbl increase; 2017 Viewfield Bakken Land position; 2017 Viewfield Bakken capital expenditures versus adjusted funds flow from operations; targeted recovery rate on primary in Viewfield Bakken; secondary waterflood development plans for Viewfield Bakken, including targeted recovery rate and F&D and the expected implementation of waterflood technology to enhance production and recovery rates; confirmation of no material near-term debt maturities along with 2019 renewal date for bank credit facilities; expected exit production per share growth; planned 2017 governance engagements; targeting events with investment community; planned conferences and investor road shows; planned hiring to add bench strength and expected board changes in 2017-2019. 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
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
be greater than or less than the estimates provided herein. Unless otherwise noted, reserves referenced herein are given as at December 31, 2016. 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. 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. All required reserve information for the Company is contained in its Annual Information Form for the year ended December 31, 2016, which is accessible at www.sedar.com. 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, 2016 under the headings, “Capital Expenditures”, “Liquidity and Capital Resources”, “Critical Accounting Estimates”, “Risk Factors”, “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, 2016, 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 www.sec.gov and Crescent Point Energy’s website as www.crescentpointenergy.com. 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;
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. 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. The information provided herein has not been independently audited or verified by the Company. Any “financial outlook” or “future oriented financial information” in this presentation, as defined by applicable securities legislation, has been approved by management of Crescent Point. Such financial outlook or future
may not be appropriate for other purposes.
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2017 production, capital expenditures and expected decline rate are based on guidance as of December 2016. Net debt as of December 31, 2016. Funds flow represents funds flow from operations.
Largest Canadian producer in Williston Basin (Top 5 including US producers)1
~644 million boe of organic reserves additions. Have never missed a production target
Top-quartile netbacks supported by low well costs and quick payouts1
Bakken waterflood is the largest tight oil pool under commercial waterflood in North America1
SEE FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES.
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SEE “DEFINITIONS / NON-GAAP FINANCIAL MEASURES” FOR DETAILS ON OOIP DEFINITION. SEE FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES.
0% 5% 10% 15% 20% 25% 5 10 15 20 25 2013 2014 2015 2016 Cumulative 2P Waterflood Reserves (mmboe) % of Organic 2P Reserves Attributed to Waterflood
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2P Reserves (MMboe) Recycle Ratio
0.0x 1.0x 2.0x 3.0x 4.0x
200 400 600 800 2010 2011 2012 2013 2014 2015 2016
Cumulative Technical Reserve Additions (MMboe) Recycle Ratio (2P incl. change in FDC)
MMboe % of 2P Reserves
“2P” Reserves is defined as Proved plus Probable reserves. “FDC” is defined as future development capital. “F&D” costs is defined as Finding and Development costs.
additions to date
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All figures are approximate.
8 167,000 >170,000 183,000
2016 Exit Q1 2017 2017 Exit
Production (boe/d)
E
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As of February 20, 2017. 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 market prices. 2017 percentage hedged figures based on 2017 annual average oil production guidance. 2018 percentage hedged figures based on 2017 exit guidance of 183,000 boe/d 9
Oil Hedge volume (bbl/d) $ CAD
$50.00 $60.00 $70.00 $80.00 $90.00 10,000 20,000 30,000 40,000 50,000 60,000 Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 Swaps 3-Way Collars Floor Hedge Price (3-way collars at market price)
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Williams Divide Burke McKenzie Mountrail Dunn
five within the Williston basin1
SEE “DEFINITIONS / NON-GAAP FINANCIAL MEASURES” FOR DETAILS ON OOIP DEFINITION.
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FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
Williston Basin: Viewfield Bakken Williston Basin: Flat Lake Uinta Basin: Recent horizontal wells Williston Basin: SE SK Conventional SW Saskatchewan: Shaunavon SW Saskatchewan: Viking Other: Swan Hills Williston Basin: North Dakota
Well Payouts
Flat Pricing assumption: US $55.00 WTI / 0.75 CAD/USD fx
(Based on Internal Rates of Return at US $50 WTI)
Sourced from Scotiabank GBM September 2016 “The Playbook”. CPG Shaunavon IRR is an average of the Upper and Lower zones
1st 3rd 4th 6th 10th SE Sask Conventional Tower Montney Viewfield Bakken SK Viking Gordondale Montney Shaunavon Karnes Trough Eagle Ford Ferguson Bakken/Exshaw Karr Dunvegan Flat Lake East Pembina Cardium Fort Berthold Bakken/Three Forks Permian Midland STACK Maramec/Woodford Permian Regan/Upton SCOOP Woodford
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Viewfield Bakken Flat Lake
Williams Divide Burke McKenzie Mountrail Dunn
2016 Exit Production (boe/d) ~102,500 2017 Exit Production (boe/d) ~108,000 (↑5%) Net Acres ~2.3 million OOIP (barrels) >8.5 billion Recovery to Date 3.3% Drilling Inventory (net locations)9 3,470 2017 Net Drill Program ~350 % of 2017 Capital Expenditures Budget 51% Q4 2016 Average Netback ($CAD/boe) ~$29.00 2017E Decline Rate ~29% 100 200 300 400 500 1-Jan-15 1-Mar-15 1-May-15 1-Jul-15 1-Sep-15 1-Nov-15 1-Jan-16 1-Mar-16 1-May-16 1-Jul-16 1-Sep-16 1-Nov-16 1-Jan-17 Cumulative Oil (Mbbl)
Actual Cumulative Oil (Mbbl) Expected Cumulative Oil (Mbbl)
Outperforming expected type wells by ~30%
(~$0.5 billion expected in 2017 @ US$55 WTI)
expansion of the play’s economic boundary
increase efficiencies through pad drilling (Bakken/Three Forks)
program and strategic acquisition, targeting continued expansion in 20178
sharing of infrastructure between various producing zones
Williston Basin includes: Viewfield Bakken, Flat Lake, North Dakota and SE SK Conventional
15,000 30,000 45,000 $0 $125 $250 $375 $500 $625 2012 2013 2014 2015 2016 2017E boe/d Cash Flow & Capex ($M)
Cash Flow Capex Production
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Shaunavon SK Viking Battrum/Cantuar
2016 Exit Production (boe/d) ~39,000 2017 Exit Production (boe/d) ~43,000 (↑10%) Net Acres ~960,000 OOIP (barrels) >7.8 billion Recovery to Date 2.5% Drilling Inventory (net locations)10 3,375 2017 Net Drill Program ~270 % of 2017 Capital Expenditures Budget 25% Q4 2016 Average Netback ($CAD/boe) ~$29.00 2017E Decline Rate ~26%
(i.e. cemented liner, closeable sliding sleeves, waterflood, completion fluid systems)
(similar to results observed in Viewfield and Shaunavon resource plays)
SW Saskatchean includes: Shaunavon, Battrum/Cantuar, AB and SK Viking
$US WTI $94 $93 $49 $43 $55 $98
horizontal wells greater than one-mile in length
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All figures and comparisons are in USD. Capital cost reduction based on vertical well capital expenditures
2016 Exit Production (boe/d) ~12,500 2017 Exit Production (boe/d) ~19,000 (↑50%) Net Acres ~170,000 OOIP (barrels) >5.2 billion Recovery to Date 0.7% Drilling Inventory (net locations)11 830 2017 Net Drill Program ~30 % of 2017 Capital Expenditures Budget 18% Q4 2016 Average Netback ($CAD/boe) ~$22.00 2017E Decline Rate ~27%
Blacktail Ridge Lake Canyon Randlett North Monument Butte Aurora Rocky Point Gusher
Ouray Valley
Horseshoe Bend
Vertical to horizontal development
2017 drilling program includes vertical wells
20,000 40,000 60,000 80,000 30 60 90 Days on Production
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Depth (ft) 6,000 to 9,000 Lateral Length Currently one-mile Down-hole pressure (psi per foot) 0.5 to 0.7 Max flowing pressure (psi) >1,600 Peak flowing rate (boe/d)* >1,300 Proppant loading (lbs/foot) Currently ~1,750 Realized oil price as a % of US WTI ~90% Liquids Percentage ~80% Type Well (mboe) IP 30 Rate* (boe/d) IP 90 Rate (boe/d) Well Cost ($M) NPV @ 10% ($M) IRR (%) Payout (months) Castle Peak 380 620 650 $5.0 $3.1 83 11
Choke managed IP rates*
*Choke managed to optimize current infrastructure ** Includes two wells currently on confidential status. Less than 90 days on production.
2017 budget risk factor: 80%
Flat Pricing assumption: US $55.00 WTI Well cost and NPV are in USD.
Castle Peak HZ drills to date in Randlett (Includes drilled locations that have not yet been completed)
(~120 locations based on a conservative 4 wells/section7) ~15 miles Expected Type Well Risked Type Well Assumed in 2017 Budget Average of 4 Wells** Most Recent Public Well
bbl
40 80 120 6 12 18 24 30 36 42 48 54 60 Months
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
technology (comparable to moving from surgifrac to multi-stage fracture stimulation technology)
reservoir pressure and may further reduce decline rates and increase estimated ultimate recoveries
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40 80 120
6 12 18 24 30 36 42 48 54 60 Months
Response in 12-18 months
(Normalized to start of injection)
Actual Oil Rate with Waterflood (bbl/d) Oil Rate without Waterflood (bbl/d) Actual Oil Rate with Waterflood (bbl/d) Oil Rate without Waterflood (bbl/d)
bbl/d bbl/d Response in 6 months
(Normalized to start of injection)
17 Based on Scotiabank Global Banking and Markets research as of February 22, 2017. Pricing assumptions: US WTI $60.00 / 0.76 CAD/USD fx
Free cash flow yield is defined as estimated free cash flow divided by enterprise value. Free cash flow as per Scotiabank’s analysis is calculated as cash flow from operations, excluding hedges, plus interest expense less capital expenditures required to sustain 2017 annual average production.
10% 0.0% 4.0% 8.0% 12.0% CPG VET SU CNQ IMO HSE CVE ARX PEY VII TOU ECA
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FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
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$0 $2 $4 $6 $8 $10 Surgifrac 16 Stage Packers Plus 16 Stage Cemented Liner 25 Stage Cemented Liner
Initial Spacing Viewfield Bakken well NPV @10%13 Net Present Value @10% ($M) $ Millions Viewfield Bakken Capital Expenditures vs Funds Flow from Operations
$ US WTI Viewfield Bakken Land Position
Crescent Point Energy lands Pool boundary
20 $0 $30 $60 $90 $120 $0 $400 $800 $1,200 $1,600 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017E Development Capex Funds Flow from Operations AVG US WTI Oil Price
20 40 60 80 100 120 140 160 1 2 3 4 5 6 7 8 9 10 Oil Rate (bbl/d) Years
21 Infill Well Direct Offset Well
EUR 350mbbl EUR 100mbbl
*Includes underlying currency swaps.
Debt Composition ($CAD) as of December 31, 2016
$1.9B Unutilized Credit Capacity $1.7B Senior Guaranteed Notes* $1.7B Drawn on Bank Credit Facilities (~47% utilized)
22 $69 $ 50 $74 $158 $185
100 150 200 2017 2018 2019 2020 2021 Million $ CAD
Senior Guaranteed Notes Maturity Schedule*
0.0x 1.0x 2.0x 3.0x 4.0x 2010 2011 2012 2013 2014 2015 2016
Net Debt to Funds Flow from Operations
23 Drilling Days Drilling Days Capital cost per Metre Capital cost per Metre 2016 days to drill based on Q4 2016 results. Capital cost per Metre Drilling Days
~30% reduction in capital cost per metre ~50% reduction in capital cost per metre ~60% reduction in capital cost per metre
4 6 8 10 $150 $230 $310 $390 $470 2011 2012 2013 2014 2015 Q4 2016
Cost per metre Days to drill 6 10 14 18 $200 $280 $360 $440 2013 2014 2015 Q4 2016
Cost per metre Days to Drill 3 6 9 12 $100 $200 $300 $400 $500 2011 2012 2013 2014 2015 Q4 2016
Cost per metre Days to Drill
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FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
200 300 400 2010 2011 2012 2013 2014 2015 2016 2017 Exit Guidance
1 1.25 1.5 1.75 2 2010 2011 2012 2013 2014 2015 2016
CAGR plus dividend yield calculations based on 2010-2016 figures.
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Area Type Well (EUR) Cost per well ($M) NPV @ 10% ($M) IRR (%) Payout (months) Williston Basin (Viewfield) 75 – 125 (mbbl) $1.3 $1.4 to $3.4 86 to 268 8 to 14 Williston Basin (Flat Lake – Torquay) 150 – 225 (mbbl) $2.3 $2.6 to $5.1 83 to 193 10 to 15 Williston Basin (Flat Lake – Midale) 100 – 150 (mboe) $1.7 $0.8 to $1.3 53 to 89 12 to 17 Williston Basin (Flat Lake – Conventional Ratcliffe) 75 – 100 (mbbl) $1.1 $1.3 to $2.0 108 to 187 9 to 12 Williston Basin (North Dakota) 430 – 500 (mbbl) $4.2 to $4.7 $1.0 to $1.3 16 to 20 44 to 59 Williston Basin (SE Saskatchewan Conventional) 60 (mbbl) $1.0 $0.9 60 19 SW Saskatchewan Resource Play (Shaunavon) 84 – 150 (mbbl) $1.4 $0.6 to $1.7 29 to 92 13 to 32 SW Saskatchewan Resource Play (Viking) 41 – 51 (mbbl) $0.6 $0.8 to $1.0 88 to 121 12 to 14 Uinta (Castle Peak Horizontals) 380 (mboe) $5.0 $3.1 83 11
All figures are approximate. Uinta and North Dakota figures are in USD. Shaunavon economics based on upper and lower Shaunavon type wells. Capital costs per well include drilling, completion, equipment and tie-in expenditures. Economics by play represent type wells expected to be drilled in 2017 program.
Flat Pricing assumption: US $55.00 WTI / 0.75 CAD/USD fx
As of December 31, 2016 as evaluated by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. Total 2P reserves = estimated production plus current 2P reserves.
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Williston Basin acquisition history includes: Viewfield Bakken, Flat Lake Resource, North Dakota, Manor, Tatagwa Unit SW Saskatchewan acquisition history includes: Shaunavon, Battrum/Cantuar, Saskatchewan Viking, Sounding Lake Other acquisitions includes: Alberta
184,154 177,754 429,594 607,348 423,194 230%
63,322 19,301 95,616 114,917 51,595 82%
25,071 10,474 39,534 50,007 24,936 99%
423,319 283,606 780,861 1,064,466 641,147 152%
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perception of management integrity, ethics and values; trends are consistently high
Continuous Improvement in Globe and Mail’s Report on Business Annual “Board Games” Score
Crescent Point Percentile Rank 61% 64% 73% 73% 83% 2012 2013 2014 2015 2016
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30 30 Director / Nominee Skills / Background 2017 Re-election Joined Board Peter Bannister, Chair Oil & Gas Executive
2003 Rene Amirault President and CEO, Secure Energy Services, Inc.
2014 Laura A. Cillis Oilfield Services Executive
2014
Oil & Gas Executive Retiring 2018 2003 Ted Goldthorpe Managing Partner, Global Credit Business for BC Partners – U.S. First election in 2017 2017 Nominee Robert F. Heinemann Oil & Gas Executive – U.S.
2014 Michael Jackson Investment Industry Executive First election in 2017 2016 Barbara Munroe Executive Vice President, General Counsel and Corporate Secretary, WestJet Airlines
2016 Gerald A. Romanzin Investment Industry Executive Retiring 2019 2004 Scott Saxberg(1) President & CEO, Crescent Point Energy Corp.
2003 Greg Turnbull Partner, McCarthy Tétrault LLP Retiring 2017 2001
capital markets)
(1) Only non-independent member
Impact of Board Renewal Process on Tenure
Under 7 Years Over 7 Years
3 new independent members 2 new independent members
$1.00 $1.50 $2.00 $2.50 $3.00 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
$ per boe
2015 peer average G&A = $2.75/boe
Source: Peters & Co. based on 2016 estimates as of February 2017
Peer average figures are from publically disclosed financial results and include: ARX, BTE, BNP, CNQ, ECA, ERF, MEG, POU, PGF, PWT, PEY, TOU, TET, VET
G&A as a percentage of netback
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CPG 10 year average G&A = $1.49 / boe
8% 15% 0% 3% 6% 9% 12% 15% 18% CPG Peer Average
Netback is prior to hedging
32 1. Largest Canadian operator and among top 5 in Williston Basin based on publically available production data as of December 2016. #1 driller in Canada based on metre’s drilled sourced from a boereport.com article dated Jan 31, 2017. Top-quartile netbacks based on peer comparison work done by Macquarie Capital Markets Canada in
2. Based on a share price of $16.24 as of market close on February 17, 2017 and 546.9 million fully diluted shares outstanding as of December 31, 2016. Directors and
3. As of December 31, 2016 as independently evaluated by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. 4. Calculated using 2017 guidance production of 172,000 boe/d and the drilling of approximately 670 net wells. 5. Approximately 8,085 identified net drilling locations of which 2,308 net are proved and 1,371 net are probable reserve locations as independently evaluated by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited as of December 31, 2016. The remaining net locations are internally identified locations that are unbooked. 6. Approximately 1,000 identified net drilling locations of which 103 net are proved and 31 net are probable reserve locations as independently evaluated by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited as of December 31, 2016. The remaining net locations are internally identified locations that are unbooked. 7. Approximately 120 horizontal drilling locations in the Uinta Basin of which 13 net are proved and 10 net are probable as independently evaluated by Sproule Associates Limited as of December 31, 2016. The remaining net locations are internally identified locations that are unbooked. 8. Greater than 500 identified net drilling locations of which 16 net are proved and 14 net are probable reserve locations as independently evaluated by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited as of December 31, 2016. The remaining net locations are internally identified locations that are unbooked. 9. Approximately 3,470 identified net drilling locations of which 1,022 net are proved and 779 net are probable reserve locations as independently evaluated by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited as of December 31, 2016. The remaining net locations are internally identified locations that are unbooked.
Consultants Ltd. and Sproule Associates Limited as of December 31, 2016. The remaining net locations are internally identified locations that are unbooked.
Consultants Ltd. and Sproule Associates Limited as of December 31, 2016. The remaining net locations are internally identified locations that are unbooked.
normalized to start of production. NPVs are before-tax and are based on a flat US $55 WTI price deck from 2017 onwards.
land acquisition costs of $1M per section, primary well costs of $1.8M and waterflood injector conversions of $0.4M per well. Recovery factors and F&D are approximate
independent studies commissioned by Crescent Point Energy and company targets.
DEFINITIONS: 1. Original Oil-In-Place (OOIP) means Discovered Petroleum Initially-In-Place (DPIIP) as at December 31, 2016. 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, 2016, and are based on current accepted technology and have been prepared by Crescent Point’s qualified reservoir engineers. 3. 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, 2016. 4. Cash flow equates to funds flow from operations. Cash flow from operations equals funds flow from operations per share. 5. Net present values disclosed in this presentation are calculated before tax. 6. Enhanced Ultimate Recovery (or EUR) relates to the extraction of additional crude oil, natural gas, and related substances from reservoirs through a production process
chemical flooding, and the use of miscible and immiscible displacement fluids. 7. Dividend reinvestment plans include the Dividend Reinvestment Plan (DRIP) and Share Dividend Plan (SDP). 8. 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 “total payout ratio”, “funds flow from operations”, “funds flow from operations per share”, “netback”, “net debt”, “market capitalization”, “enterprise value”, “net debt to funds flow from operations”. 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. Total payout ratio is calculated on a percentage basis as capital expenditures and dividends paid or declared divided by funds flow from operations. Total payout ratio is used by management to monitor the Company’s capital reinvestment and dividend policy, as a percentage of the amount of funds flow from operations. Funds flow from operations is calculated based on cash flow from operating activities before changes in non-cash working capital, transaction costs and decommissioning
from operations as a key measure to assess the ability of the Company to finance dividends, operating activities, capital expenditures and debt repayments. Funds flow from
with IFRS.
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Netback is calculated on a per boe basis as oil and gas sales, less royalties, operating and transportation expenses. Netback is a common metric used 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. 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. Enterprise value is calculated as market capitalization plus net debt. Management uses enterprise value to assess the valuation of the Company. 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 hedged US dollar long-term debt. 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 for the trailing four quarters. Q4 annualized net debt to funds flow from operations is calculated as the net debt divided by the annualized funds flow from operations for the fourth quarter. 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. 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 www.sec.gov and on our website as www.crescentpointenergy.com. 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. 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. 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. 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.
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www.crescentpointenergy.com
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