FLAT LAKE - Crescent Point

Crescent Point Energy
Corporate Presentation
July 2016
1
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; impact of production outperformance on flexibility to manage low oil prices and impact on positioning for 2017; horizontal well plans for Uinta; targeting continued cost reductions; ways to
improve recovery factors; how to company plans to create value in its emerging-growth plays; living within cash flow; continued focus on long-term strategic projects; expected driver of long-term growth
plans; implementation of new completions technology and anticipated impact on overall returns, recovery factors and water consumption; payout ratios; future waterflood plans; step-out drilling plans;
unitization plans; corporate decline rate reductions; F&D costs; using internal funding to complete future acquisitions; 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 on productivity and decline rates and ultimate recoveries;
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 cost and type well scenarios, cost per well, NPV, rate of return and
payout; increased recovery given mobility levels; plans for injection wells; 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. Unless otherwise noted, reserves referenced herein are given as
at December 31, 2015. 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, 2015, 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, 2015 under the headings “Marketing and Prices”, “Dividends”, “Capital Expenditures”, “Decommissioning
Liability”, “Liquidity and Capital Resources”, “Critical Accounting Estimates”, “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, 2015, 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; 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
HIGH-QUALITY, LOW-COST PRODUCER:
CPG (TSX AND NYSE)
Market Capitalization
$10.2 billion (511.2 million shares fully diluted)(1)
Net Debt*
$4.3 billion (incl. hedged US$ denominated debt)
Enterprise Value
$14.5 billion
2016 Average Production
165,000 boe/d (~90% oil weighted)
Monthly Dividend
$0.03/share
Proved + Probable Reserves
935.7 million boe (RLI:15.5 years)(2)(3)
Proved Reserves
592.1 million boe (RLI: 9.8 years)(2)(3)
Drilling Inventory
~7,700 locations (~14 years of inventory)(3)(4)
* As of March 31, 2016.
Maximize shareholder return with long-term growth and dividend income
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
3
BUSINESS STRATEGY
Develop and Enhance Assets
• Increase recovery factors through step-out and infill drilling, waterflood
optimization and improved technology
• Maintain high netbacks with low operating, royalty and transportation costs
Acquire
• Focus on high-quality, large resource-in-place pools with the potential for
upside in production, reserves, technology and value
• Primarily utilize internal funding to complete future acquisitions
Manage Risk
• Maintain strong balance sheet, with significant liquidity and no material
debt maturities and a 3½-year hedging program
4
2016 PRIORITIES
Protecting against volatile short-term oil prices while positioning for long-term growth
•
Maintain production levels at 165,000 boe/d for 2016 and 2017
•
Protect and further strengthen balance sheet
•
Realize additional cost reductions and capital efficiency improvements (targeting 10% reduction versus Q4 2015)
•
Continue to advance core resource plays for long-term growth; budgeting ~$75 million on long-term value creation projects
• Step-out drilling
• Waterflood advancement
• New technology
•
Opportunistic acquisitions within core areas
Capital Budget Allocation
Balanced Capital Expenditures Budget – Developing for Long-Term Value
Viewfield Bakken
Other
15%
26%
Shaunavon
19%
Flat Lake
17%
Viking
Drilling & Completions
85%
12%
Conventional
Uinta
Other
11%
4%
11%
*Other includes facilities, land and seismic
5
COMMODITY HEDGING STRATEGY
Current Oil Hedges
2016 H2 Average:
43%
2017 H1 Average:
28%
2017 H2 Average:
9%
60,000
$110.00
50,000
$90.00
$70.00
$ CAD
bbl/d
40,000
30,000
$50.00
20,000
$30.00
10,000
-
$10.00
Q3 16
Q4 16
Swaps
Collars
Q1 17
3-Way Collars
As of June 27, 2016. Market hedge price is calculated using the forward strip as of June 27, 2016.
Percentages based on 2016 guidance.
Q2 17
Floor Hedge Price
Q3 17
Q4 17
Market Hedge Price
6
FOCUSED GROWTH
Viewfield Bakken
Shaunavon
Flat Lake / Midale
Viking
Conventional
OOIP
>7.8
billion
barrels
OOIP
>7.4
billion
barrels
OOIP
>5.2
billion
barrels
Uinta Basin
Large Original Oil in Place with significant running room
• Only 3.0% recovered to date with significant growth
potential
• ~14 years of drilling inventory
High-return asset base
• Top-quartile netbacks supported by low operating
costs
• Shallow plays with low capital costs
2016 budget continues to focus on long-term value creation
• Waterflood development increases net asset value
and lowers decline rates
• Expanding core plays through step-out drilling
• Advancing new technology
Positioned in four of the seven largest light and medium oil pools in Canada
Oil pool rankings based on resource in place comparison by CIBC World Markets.
Recovery to date as of December 31, 2015
7
SIGNIFICANT GROWTH POTENTIAL
Total Net
locations(4)
Years of
Inventory
OOIP
(mmbbls)
Recovery to
Date
Shaunavon
1,850
18
5,500
1.2%
Conventional
1,225
15
2,900
14.4%
Viewfield Bakken
1,200
10
4,600
3.4%
Uinta
1,150
>50
5,200
0.6%
Viking
1,000
7
1,400
1.3%
Flat Lake (excluding Ratcliffe)
825
14
2,800
0.9%
Other
450
16
600
2.4%
TOTAL
7,700
14
23,000
3.0%
Key Focus Areas
•
Improving recovery factors through step-out and infill drilling, new technology and waterflood development
•
A 5% increase in the corporate recovery factor would add ~1 billon barrels of reserves
Approximately 50% of risked drilling locations are unbooked allowing for future reserves upside
OOIP are estimates of gross OOIP. Recovery to date as of December 31, 2015.
All figures are rounded to approximate values.
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
8
VIEWFIELD BAKKEN AND SHAUNAVON RESOURCE PLAYS –
VALUE DRIVERS
Waterflood
Closable Sliding Sleeve Technology
Source: NCS Multistage
•
Infill drilling and optimized well density patterns allow for greater recovery rates and optimal waterflood development
•
Waterflood is reducing decline rates and increasing estimated ultimate recoveries (~3x in the Viewfield Bakken play and ~2x in
the earlier-stage Shaunavon play)
•
Improvements in completions fluids in certain areas of the Viewfield Bakken play have increased production by >40% in
comparison to average offset wells: Testing similar completions fluids in the Shaunavon play
•
Closable sliding sleeve technology reduces costs by minimizing sand flow-back (primary recovery) and increases efficiency and
productivity of waterflood (secondary recovery)
•
Transferring knowledge and learnings from technology and waterflood initiatives to emerging-growth resource plays
9
VIEWFIELD BAKKEN WATERFLOOD:
SIGNIFICANTLY INCREASING VALUE
160
Example of Per Section
Bakken Recoveries and Economics
Viewfield Waterflood Offset Well
EURs ~3x greater versus Primary(5)(6)
140
OOIP
(MMbbls)
Estimated
Recovery
Factor(7)
Incremental
EURs (mbbls)
Cumulative
F&D costs
(per bbl)
4-well
Spacing
6.1
10%
615
$13
8-well
Spacing
6.1
19%
553
$13
Waterflood
6.1
>30-40%
>615 - 1,291
<$7 - $9
120
Oil Rate (bbl/d)
100
80
EUR 100mbbl
EUR 125mbbl
EUR 350mbbl
NPV@10%: $2.3M NPV@10%: $3.0M NPV@10%: $6.1M
60
40
20
0
0
1
2
3
4
5
6
7
8
9
10
Includes historical 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 costs are approximate values. Current primary well costs are ~$1.3M.
Years
Infill
Indirectly Affected
Direct Offsets
• ~145 net water injection wells currently converted in the Viewfield Bakken play;
• >600 remain in the four waterflood units after 2016 (assuming a 1:1 ratio between producing wells and injection wells)
• Initial plans to potentially double injection well conversions in 2017 and evaluating additional lands for potential waterflood
unitization (~60% increase)
• Third consecutive year of reserves growth due to waterflood in Viewfield Bakken (~8 mmbbls of reserve adds over the past 3 years)
*March 31, 2016 Sproule pricing
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
10
EMERGING-GROWTH RESOURCE PLAYS –
VALUE DRIVERS
Mahogany
Garden Gulch
Douglas Creek
Marly Midale
Black Shale
Ratcliffe Conventional
Vuggy Midale
Castle Peak
Bakken
Bakken
Uteland Butte
Torquay/Three Forks
Torquay/Three Forks
Wasatch
Flat Lake
Torquay Area
Flat Lake
Midale Unconventional Area
Uinta Basin
~5 MMbbls
OOIP per section
~5 MMbbls
OOIP per section
~24 MMbbls
OOIP per section
Creating value in our emerging-growth plays through:
•
Step-out drilling
•
Implementation of new technology
•
3-D seismic work
•
Transferring knowledge from Viewfield
•
Waterflood development
Bakken and Shaunavon plays
11
FLAT LAKE
Viewfield Bakken
•
Q1/16 area production: ~17,500 boe/d
•
~1,000 net drilling locations (154% growth since 2012)
• ~825 unconventional and ~160 conventional
•
~2.8 billion barrels of unconventional Original Oil-In-Place
(recovery to date ~0.9%)
• Recently identified new ~100 million barrel conventional oil pool in
the Ratcliffe zone (shallow depth)
• Un-fracked wells, low capital costs, attractive royalty rates
Torquay
Midale
• Successful step-out program continues to expand economic boundaries
USA border
Flat Lake edge
Flat Lake lands
Crescent Point Energy lands
Flat Lake Production
20,000
Flat Lake Capital Cost Reductions
$3.5
15,000
$ million per well
Net Production Rate (boe/d)
• Successful future waterflood pilot would create potential for secondary
recovery opportunities in the Three Forks zone in North Dakota
10,000
5,000
$2.5
$1.5
0
2012
2013
2014
2015
Q1 2016
2012
~825 net drilling locations, of which 115 net are proved and 146 net are probable reserve locations as independently evaluated by GLJ
Petroleum Consultants Ltd. and Sproule Associates Limited. Remaining locations are internally identified unbooked locations. ~160
Ratcliffe locations are recently discovered and all internally identified.
2013
2014
Q4 2015
2016E
12
UINTA BASIN
•
Q1/16 production: ~14,000 boe/d
•
~1,150 net low-risk vertical drilling locations
plus horizontal drilling opportunities
•
~5.2 billion barrels of Original Oil-In-Place
(recovery to date ~0.6%)
•
Recent horizontal well results outperforming
expectations; returns similar to Viewfield Bakken
Ouray
Valley
Gusher
Rocky Point
Blacktail Ridge
Randlett
Horseshoe
Bend
Aurora
North Monument
Butte
Lake Canyon
Crescent Point Energy lands
16,000
80
14,000
12,000
60
10,000
40
8,000
6,000
Uinta Basin Capital Cost Reductions
$2.2
100
$ million per well
18,000
2P Reserves (mmboe)
Net production Rate (boe/d)
Uinta Basin Production and 2P Reserves Growth
$1.8
$1.4
20
2012
2013
2014
2015
$1.0
Production
2P Reserves
2012
~1,150 net drilling locations, of which 274 net are proved and 130 net are probable reserve locations as independently evaluated by GLJ
Petroleum Consultants Ltd. and Sproule Associates Limited. Remaining locations are internally identified unbooked locations.
2013
2014
Q4 2015
2016E
13
2016 CAPITAL PROGRAM SUPPORTED
BY QUICK PAYOUTS
Type Well Payouts by Play
(Excluding Upside from Waterflood and New Technology)
36
Months
24
Payouts of
2 years or
less
12
0
Viewfield Bakken
Flat Lake
Torquay
Midale
Unconventional
SE SK
Conventional
Shaunavon
(Upper & Lower)
Swan Hills
SK Viking
Uinta
(Vertical)
75 - 125
Type Well
150 - 225
Type Well
103 - 175
Type Well
65 - 75
Type Well
84 - 150
Type Well
180 - 250
Type Well
41 - 51
Type Well
125 - 175
Type Well
High-return asset base provides capital flexibility during current environment
14
Based on March 31, 2016 Sproule pricing: 2016 US $45 WTI and US/CAD $0.75 exchange, 2017 US $60WTI and US/CAD $0.80 exchange.
GENERATING EXCESS FUNDS FLOW
2016 @ US $45 WTI
2017 @ US $50 WTI
Total Payout Ratio: 78%
Total Payout Ratio: 83%
Excess Funds
Flow
Excess Funds
Flow
>$300MM
>$200MM
Cash
Dividends
Cash
Dividends
Capital
Expenditures
Funds Flow
~$950MM
Funds Flow
Capital
Expenditures
~$950MM
Production: 165,000 boe/d
Production: 165,000 boe/d
Expected decline rate: 28%
Expected decline rate: 26%
• Generating excess funds flow: forecast ~$500 million of excess funds flow in 2016 and 2017*
• Flexibility to redeploy excess funds flow to:
• Additional organic production growth
• Debt reduction
• Accretive acquisitions
• Dividend increases
FFO = Funds Flow from Operations.
* Based on US $45 WTI in 2016 and US $50 WTI in 2017
15
CONTINUING HISTORY OF PER SHARE GROWTH
5-Year Production Per Share Growth to 2015
Canadian Senior E&Ps >100,000 boe/d
8%
5%
CPG
PEER AVG
Debt and Dividend Adjusted. Peer group includes: CNQ,CVE,HSE,IMO,SU
Source: CIBC World Markets Inc.
•
Integrated strategy of organic development and acquisitions has generated growth on a per share basis
•
Grew oil-in-place, drilling inventory, and established new core resource plays during the same period
•
Large oil-in-place resource base expected to continue driving long-term per share growth plus a dividend
16
SUMMARY
Proven Management Team
•
Proven track record of per share reserves, production and cash flow growth
•
•
5-year weighted average F&D of $20.39 per 2P boe of reserves (2.2 times recycle ratio)(8)
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
•
Primarily utilize internal funding to complete future acquisitions
•
3½-year hedging program provides cash flow stability and balance sheet protection
•
Significant unutilized credit capacity of ~$1.3 billion
High-Quality Reserve Base
•
Efficiently allocating capital across high-quality asset base
•
~7,700 net locations in drilling inventory primarily within low cost, high-return basins(4)
•
~14 years of low-risk drilling inventory with a large inventory of potential unbooked upside(3)
•
Large OOIP of ~23 billion barrels with only ~3.0% recovered to date
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
17
APPENDIX
18
BALANCE SHEET STRENGTH
Debt Composition ($CAD) as of Mar 31, 2016
4.0x
$1.8B
Senior
Guaranteed
Notes*
3.0x
$1.3B
Unutilized
Credit
Capacity
2.0x
1.0x
$2.3B
Drawn on Bank
Credit Facilities
(~60% utilized)
0.0x
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Senior Guaranteed Notes Maturity Schedule
Million $ CAD
400
$361
300
200
$119
100
$50
0
Less than 1 year
Net Debt to Funds Flow from Operations
1 - 3 Years
•
Living within cash flow in 2016 and 2017
•
No material near-term debt maturities
•
Significant unutilized credit capacity of ~$1.3 billion on
syndicated credit facility with June 2018 renewal date
•
Bank credit facilities and senior guaranteed notes rank equal
and are unsecured and covenant-based.
•
US$ denominated senior guaranteed notes fully hedged with
cross currency swaps
3 - 5 Years
Significant amount of liquidity and financial flexibility
*Includes underlying currency swaps
19
ORGANIC RESERVES GROWTH
Cumulative Technical and Development
2P Reserve Additions (mmboe)(9)
700
578 mmboe
600
500
400
300
200
100
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
2004
0
•
Organic growth of 578 mmboe since inception = ~50% of current 2P Reserves (935.7 mmboe) plus cumulative
production (~299 mmboe)
•
Historical five-year 2P F&D of $20.39/boe with a recycle ratio of 2.2 times(9)
Long-term strategy of step-out and infill drilling, waterflood optimization and improved technology
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
20
INDUSTRY-LEADING CASH NETBACKS
Cash Netbacks @ US$30 WTI
(Excluding Hedging Gains)
$15.00
Cash Netbacks $/boe
CPG
Canadian Peers
$10.00
USA Peers
Saskatchewan Focused
$5.00
$Source: Macquarie Capital Markets Canada Ltd.
Based on 2016 WTI US$30, US/Cdn$0.72, and NYMEX $2.50/mcf
$(5.00)
CPG
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
$(10.00)
Strong Netbacks:
• Support corporate cash flow generation to protect balance sheet strength at low oil prices
• Contribute to strong economics and quick project payouts
Peer group includes: AAV, APA, APC, AREX, ARX, BBG, BCEI, BIR, BNP, BTE, BXE, BXO, CHK, CLR, CNQ, COG, COS, CPG,
CR, CVE, CXO, DVN, ECA, EGN, EOG, EOX, ERF, GXO, HSE, IMO, KEL, MEG, NBL, NFX, OAS, PDCE, PE, PEY, POU, PXD,
REXX, RMP, RRC, SGY, SM, SN, SPE, SU, SWN, TOG, TPLM, TVE, VET, VII, WCP, WLL, XEC.
21
HIGH-RETURN, QUICK-PAYOUT ASSET BASE
Top Light and Medium Oil Resource Plays in North America
(ranked by half-cycle payout)
25
20
19th
Eight of Crescent Point’s nine core resource
plays ranked in the top 20 across North America
CPG
Canadian Peers
18th
17th
USA Peers
15
10th
10
9th
7th
5
3rd
2nd
1st
Tuscaloosa Shale
US Bakken
Uinta Basin (Vt.)
Upper Shaunavon
Tower Montney
Permian Delaware Basin
Lochend Cardium
Kaybob Duvernay
Permian Midland Basin
West Pembina Cardium
Flat Lake Torquay
Lower Shaunavon
East Pembina Cardium
Midale Unconventional
Spirit River Charlie Lake
Brazeau Belly River
Karr Dunvegan
Viewfield Bakken
SE SK Conventional
SK Viking
0
Source: Scotiabank GBM. Based on 2016 WTI US$30, US/Cdn$0.70, AECO C$/mcf $1.86 and heavy oil differential of 25%.
Based on 43 light and medium oil plays (excluding condensate). Payouts based on average of total play results.
22
ADVANCING WATERFLOODS
~285
35%
200
35%
28%
100
25%
30
0
2011A20112011B
2016A2016E
2016B
Cumulative Water Injection Well Count
12
45%
15%
Reserves (mmboe)
300
Viewfield Bakken Cumulative Oil Reserves
due to Waterflood(10)
Corporate Decline Rate (%)
Cumulative Injection well count*
Water Injection Well Conversions and
Corporate Decline Rate
9
6
3
0
2013
2014
2015
Corporate Decline Rate
Over the last 5 years:
• Increased water injection well count from 30 wells to
~285 wells
• Reduced decline rate by ~20% (from 35% to 28%) due to
waterflood and disciplined capital activity
• Waterflood reserves recognized in both Viewfield Bakken
and Shaunavon resource plays
• Third consecutive year of reserves growth due to waterflood
in Viewfield Bakken
• Shallow nature of reservoirs creates waterflood advantage
Waterfloods reduce decline rates, increase recovery factors and generate significant free cash flow
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
*Water injection well conversions for Viewfield Bakken and Shaunavon
23
VIEWFIELD BAKKEN
Crescent Point Energy lands
Waterflood Unit outline
(Four Units in total)
Viewfield Bakken edge
Waterflood affected area
•
Q1/16 production: ~65,000 boe/d
•
~1,200 net drilling locations
•
~4.6 billion barrels of Original Oil-In-Place with recovery to date
of 3.4%
•
Continue to implement new completions technology resulting in
improved overall returns and recovery factors and less water
consumption
•
Producing oil wells directly offsetting injection wells
demonstrating significant improvements in decline rates and
approximately three times the estimated ultimate recovery
•
Unitizing remaining three waterflood units; budgeted injection
conversions of ~50 wells in 2016 up from ~30 in 2015; initial
plans to potentially double injection well conversions in 2017 and
evaluating several additional waterflood units
Type Well
(mbbls)
Cost per
well ($M)
NPV @
10% ($M)
Rate of Return
(%)
Payout
(months)
2016 US$35/bbl WTI*
75-125
$1.3
$1.2 to $3.0
60 to 181
10 to 20
March 31, 2016 Sproule pricing
75-125
$1.3
$1.4 to $3.2
72 to 227
9 to 17
Pricing Scenario
*Cdn$0.71 exchange.
~1,200 net drilling locations, of which 536 net are proved and 157 net are probable reserve locations as independently evaluated by GLJ
Petroleum Consultants Ltd. and Sproule Associates Limited. Remaining locations are internally identified unbooked locations.
24
STRATEGIC ASSET BASE WITH STRONG ECONOMICS
Viewfield Bakken Infill Type Well
(75 mbbls)
Comparison
Viewfield
North Dakota
160
Land
Majority crown
Majority freehold
Royalties
Crown holiday,
~10% royalty
No holiday,
~30% royalty
Efficiencies
Multi-well batteries,
no day camps
Single-well batteries,
camps for workers
Capital
Shallower wells,
lower cost wells
Deeper wells,
higher cost wells
Average Netback
($/boe)
Cumulative
Cash Flow (M$)
(excl. initial capital)
Production (boe/d)
140
120
100
80
60
40
20
0
0
1
2
3
4
5
Year
75 mbbls infill type well 60/40 Crown/Freehold; 0% GOR, Type Well Economics @ March 31, 2016 Sproule pricing
Average
Average
Average
Average
Production
Oil Production
Average
Royalty
Op Cost
(boe/d)
(bbl/d)
Oil Price (C$/bbl)
(%)
($/boe)
Year 1
81
70
$53.70
10
$6.17
$38.51
$845
Year 2
34
30
$68.00
10
$8.76
$47.87
$1,444
Drilling and completion capital costs of $1.3 million
25
SHAUNAVON
•
Q1/16 production: ~26,000 boe/d
•
~1,850 net drilling locations
•
~5.5 billion barrels of Original Oil-In-Place with recovery to date of 1.2%
•
Optimized tonnage and stages during completions process resulting in increased productivity
•
Producing oil wells directly offsetting injection wells demonstrating significant improvements
in decline rates and approximately two times the estimated ultimate recovery
•
Continue to advance waterflood with ~30 injection well conversions planned for 2016
•
Eliminated the use of fresh potable water during completions
Crescent Point Energy lands
Lower Shaunavon edge
Upper Shaunavon edge
Waterflood affected areas
Type Well
(mbbls)
Cost per
well ($M)
NPV @
10% ($M)
Rate of Return
(%)
Payout
(months)
2016 US$35/bbl WTI*
84-150
$1.4
$0.9 to $2.0
29 to 60
23 to 37
March 31, 2016 Sproule pricing
84-150
$1.4
$1.1 to $2.3
39 to 92
15 to 29
Pricing Scenario
Waterflood Voluntary Unit
*Cdn$0.71 exchange. Based on Upper and Lower Shaunavon type well economics.
~1,850 net drilling locations, of which 491 net are proved and 221 net are probable reserve locations as independently evaluated by GLJ
Petroleum Consultants Ltd. and Sproule Associates Limited. Remaining locations are internally identified unbooked locations.
26
WATERFLOOD ECONOMICS
Example of Per Section
Bakken Recoveries and Economics
Example of Per Section
Shaunavon Recoveries and Economics
OOIP
(MMbbls)
Estimated
Recovery
Factor(7)
Incremental
EURs (mbbls)
Cumulative
F&D costs
(per bbl)
4-well
Spacing
6.1
10%
615
$13
8-well
Spacing
6.1
19%
553
$13
Waterflood
6.1
>30-40%
>615 - 1,291
<$7 - $9
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 ~$1.3M.
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
OOIP
(MMbbls)
Estimated
Recovery
Factor(7)
Incremental
EURs (mbbls)
Cumulative
F&D costs
(per bbl)
4-well Spacing
13.5
~6%
810
~$14
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
~$1.6M. OOIP per section based on lower Shaunavon OOIP estimates only.
27
FLAT LAKE
Viewfield Bakken
•
Q1/16 area production: ~17,500 boe/d
•
~1,000 net drilling locations (~825 unconventional, ~160 conventional)
•
>2.8 billion barrels unconventional Original Oil-In-Place (recovery to date ~0.9%)
Flat Lake Torquay: (Torquay/Three Forks, Bakken and Ratcliffe)
Torquay
•
~300 net sections in the core boundary; continues to expand
•
New Ratcliffe conventional zone (low capital costs / un-fracked wells)
•
First waterflood pilot to be initiated during 2016
Midale
Flat Lake Midale: (Midale, Torquay/Three Forks and Bakken)
Flat Lake lands
Flat Lake edge
Crescent Point Energy lands
USA border
Torquay (Three Forks) Economics
Step-out program extending economic boundaries
•
Increasing water injection wells in 2016, building on success of initial pilots
Midale Unconventional Economics
Type Well
(mbbls)
Cost per
well
($M)
2016 US$35/bbl WTI*
150-225
$2.4
March 31, 2016
Sproule pricing
150-225
$2.4
Pricing Scenario
•
NPV @
10% ($M)
Rate of
Return
(%)
Type Well
(mboe)
Cost per
well
($M)
NPV @
10% ($M)
Rate of
Return
(%)
Payout
(months)
2016 US$35/bbl WTI*
103-145
$1.6
$1.0 to $1.8
40 to 60
23 to 28
March 31, 2016
Sproule pricing
103-145
$1.6
$1.5 to $2.4 79 to 117
12 to 15
Payout
(months)
Pricing Scenario
$2.5 to $4.5 56 to 121
13 to 22
$2.9 to $5.1 81 to 193
10 to 16
*Cdn$0.71 exchange. Based on 1-mile horizontal well economics.
*Cdn$0.71 exchange. Based on an expected type well for the Steelman / Pinto Midale area.
~825 net drilling locations, of which 115 net are proved and 146 net are probable reserve locations as independently evaluated by GLJ
Petroleum Consultants Ltd. and Sproule Associates Limited. Remaining locations are internally identified unbooked locations. ~160
Ratcliffe locations are recently discovered and all internally identified.
28
UINTA BASIN
Multi-Zone Basin
Ouray
Valley
Gusher
Blacktail Ridge
Rocky Point
Randlett
Aurora
Horseshoe
Bend
North Monument
Butte
Lake Canyon
Crescent Point Energy lands
Zones tested horizontally since late 2014
•
Q1/16 production: ~14,000 boe/d
•
~1,150 net low-risk vertical drilling locations
plus horizontal drilling opportunities
•
•
~5.2 billion barrels of Original Oil-In-Place
with recovery to date of ~0.6%
Recent horizontal well results exceeding
expectations; three horizontal wells
planned during 2016
Vertical Drilling Economics
Type Well
(mbbls)
Cost per
well
(US$M)
NPV @
10% (US$M)
Rate of
Return
(%)
Payout
(months)
2016 US$35/bbl WTI
125-175
$1.3 - $1.5
$0.8 to $1.9
25 to 51
27 to 43
March 31, 2016
Sproule pricing
125-175
$1.3 - $1.5
$1.1 to $2.3
37 to 77
18 to 31
Pricing Scenario
Based on Randlett North and South (tribal and non-tribal) vertical economics
~1,150 net drilling locations, of which 274 net are proved and 130 net are probable reserve locations as independently evaluated by
GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. Remaining locations are internally identified unbooked locations.
29
CREATING LONG-TERM VALUE FOR SHAREHOLDERS
Growth + Dividend Strategy
CPG
Base Business
Waterflood
Expansion
Technology
Initiatives
• Large OOIP resources with low
recovery to date
• Lower decline rates and
future capital requirements
• Increase recoveries and capital
efficiencies
• High-return asset base
• Increase ultimate recoveries
over primary development
• Expand programs from vertical into
larger horizontal opportunities
• Control of infrastructure
• Manage risk (i.e. hedging and strong
balance sheet)
• Allows for discovery of new plays
M&A
• 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
30
PROVEN TRACK RECORD
200,000
Production Growth (boe/d)
Funds Flow (millions)
$3,000
160,000
$2,500
120,000
$2,000
$1,500
80,000
$1,000
40,000
$500
2015
2014
2013
2012
2011
2010
2009
2008
2007
2005
P+P Reserves (MMboe)
2006
$0
2016E
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
0
Net Debt to Funds Flow from Operations
4.0x
1,000
3.0x
800
600
2.0x
400
1.0x
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
0.0x
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
0
(2)
200
Proven track record of delivering growth and income
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
31
PER SHARE FOCUS
Production per Share
Reserves per Share
CAGR: ~6%
+ Dividend Yield
400
2
300
1.75
200
1.5
100
1.25
0
CAGR: ~6%
+ Dividend Yield
1
2010
2011
2012
2013
2014
2015
2010
2011
2012
2013
2014
2015
(2)
•
Integrated strategy of organic development and acquisitions has consistently generated growth on a per share basis
•
Declared $31.17 of dividends per share to shareholders from inception to March 31, 2016
•
Suspended the dividend reinvestment plans (DRIP and SDP) effective August, 2015, further enhancing long-term per
share growth
Continue growing on a per share basis
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
32
FAVOURABLE WATERFLOOD RESERVOIRS
Low Mobility Ratios* Enhance Waterflood Oil Recovery
Horizontal Waterflood Comparison
Tight Oil
Unconventional
Resource Plays
Mobility Ratio
Recovery to Date
Viewfield
Bakken
0.4
3.4%
Shaunavon
Battrum
2.5
20
1.2%
26.9%
New resource plays with attractive mobility provide
opportunity for increased 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
Province
E&P Companies
Total Affected
Waterflood
Production (bbl/d)
Viewfield Bakken
SK
CPG
~22,000
2006
Shaunavon
SK
CPG
~11,000
2008
Shaunavon
SK
1 E&P
~300
2012
Cardium
AB
4 E&Ps
~6,000
2008
Slave Point
AB
4 E&Ps
~5,000
2012
Viking
SK
3 E&Ps
~4,000
2009
Montney
AB
5 E&Ps
~4,000
2009
Swan Hills
AB
2 E&Ps
~2,000
2012
Swan Hills
AB
CPG
~1,000
2013
Viking
AB
2 E&Ps
~700
2013
Viking
AB
CPG
~300
2014
TOTAL
Pilot
Initiated
~56,300
Source: Accumap Canada. Waterflood production based on horizontal injection wells.
Based on 2015 production data.
• Viewfield Bakken is the largest unconventional oil pool
in North America currently under commercial
waterflood, with plans for expansion
(Wood Mackenzie Canada Ltd.)
*Mobility ratio is defined as the oil’s ability to move within the rock; determined by permeability and viscosity
33
ACQUISITION HISTORY:
RESERVES MORE THAN DOUBLED
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
4,402
3,383
7,785
5,348
219%
Manor/Tatagwa Unit
13,641
17,072
25,571
42,643
29,002
213%
Little Bow
2,872
2,992
1,683
4,675
1,803
63%
18,950
24,466
30,637
55,103
36,153
191%
SW Sask
132,285
55,740
193,655
249,395
117,110
89%
Viewfield Resource
106,630
116,393
231,121
347,514
240,884
226%
Flat Lake Resource
3,178
7,767
69,796
77,563
74,385
2,341%
261,043
204,366
525,209
729,575
468,532
179%
Utah
61,858
14,747
89,358
104,105
42,247
68%
North Dakota
13,511
6,909
64,352
71,261
57,750
427%
336,412
226,022
678,919
904,941
568,529
169%
Property
Subtotal
Canada Subtotal
CPG TOTAL
As of December 31, 2015 as evaluated by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited.
Total 2P reserves = estimated production plus current 2P reserves.
• Increased 2P reserves by >568 million boe (169%)
• Large oil in place pools have outperformed initially estimated recoveries over time
34
REDUCING DRILLING & DEVELOPMENT COSTS
Viewfield Bakken
Drilling and Development Cost
Shaunavon
Drilling and Development Cost
$3.0
Cost per well ($Millions)
Cost per well ($Millions)
$2.5
$2.0
$1.5
$1.0
$2.0
$1.0
2008
•
2009
2010
2011
2012
2013
2014
2015 2016E
2008
2009
2010
2011
2012
2013
2014
2015 2016E
30% reduction in drilling and development capital costs in 2015 due to operational efficiencies and cost savings
 Operational efficiencies include new technology, reduced drilling days and other optimizations
 Per well productivity has also increased over this period, enhancing overall economics
•
Reduced capital costs by an additional 4% during Q1 2016
Efficiencies are expected to be retained as commodity prices increase
Shaunavon well costs are based on an average of Lower and Upper Shaunavon zones.
Well costs for 2015 are based on Q4 actual results. 2016 estimated costs based on Q4 2015 actuals less 10%.
35
PIONEER IN ADVANCING NEW TECHNOLOGY
2008 - 2009
2010 - 2012
2013 - 2015
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 in the Viewfield Bakken,
Shaunavon, Flat Lake, Midale and Viking resource plays
372 Gross
Wells Drilled
1,484 Gross Wells
Drilled
2,453 Gross Wells
Drilled
36
VIEWFIELD BAKKEN TECHNOLOGY ADVANCEMENTS
Viewfield Bakken Independent type well changes(11)
(Primary recovery – 3 twp core)
• Technology has shown to be a significant value
creator over time; net present value (@ 10%) perwell has more than tripled with technology
300
250
• New closeable sliding sleeve technology allows for:
Mbbl
200
 Lower costs by minimizing sand flow-back
(primary recovery)
150
 Greater efficiency and productivity of
waterflood programs through increased
control of water placement, potentially
leading to enhanced recovery factors
(secondary recovery)
100
50
0
Surgi Frac
16 stage packer
16 stage
Frac
cemented liner
25 stage
cemented liner
Technology advancements continue to be transferred to our emerging plays
(March 31, 2016 Sproule pricing - WTI US$45 and US/Cdn exchange $0.75)
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
37
IMPACT OF TECHNOLOGY IMPROVEMENTS
Viewfield Bakken
Drilling Progression Spud to Rig Release
Viewfield Bakken Fresh Water Usage
900
16.00
800
700
12.00
500
Days
Water (m3)
600
400
8.00
300
4.00
200
100
0
0.00
2009
2010
2011
2012
2013
2014
2015
2007 2008 2009 2010 2011 2012 2013 2014 2015
Viewfield Bakken Stage and Tonnage Evolution
1000
Viewfield Bakken well ROR (3 twp core)
14
25
12
10
20
8
15
6
10
4
5
800
Rate of Return %
30
Tonnage per stage
Stages per well
Mar. 31, 2016 Sproule pricing– 2016 WTI US$45 US/CDN $0.75 exchange
>500% increase in rate of return
600
400
200
2
0
0
2007 2008 2009 2010 2011 2012 2013 2014 2015
0
Surgifrac
16 Stage Packers
16 Stage
25 Stage
Plus
Cemented Liner Cemented Liner
38
INDUSTRY-LOW G&A
G&A as a % of Netback
G&A as a percentage of netback
20%
44% lower G&A
(as a percentage of netback)
in comparison to peers
15%
10%
5%
0%
2015 CPG
2015 PEER AVG
•
Crescent Point Energy G&A/boe includes capitalized expenses for comparison purposes
•
Crescent Point Energy’s reported G&A is lower than the numbers shown above
Peers include: ARX,BTE, BNP, CVE, CNQ, ECA, ERF, HSE, LTS, MEG, POU, PGF, PWT, PEY, TOU, TET, VET
39
ENDNOTES
1. Fully diluted shares outstanding as of March 31, 2016. Based on June 24, 2016 market closing price of $19.87. Directors and officers ownership represents
0.6% of issued and outstanding shares as of May 9, 2016.
2. As of December 31, 2015 as independently evaluated by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited.
3. Calculated using 2016 guidance production of 165,000 boe/d and the drilling of approximately 550 net wells.
4. Approximately 7,700 net drilling locations, of which 2,378 net are proved and 1,305 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. 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.
6. Waterflood reserve additions represent internally evaluated incremental reserves over the average primary type curve described above.
7. Estimated recovery factors are based on independent (P+P) reserves, comparable analog pools, independent studies commissioned by Crescent Point Energy
and company targets.
8. As of December 31, 2015, excluding the change in future development capital and based on the five year average netback (prior to realized derivatives) of
$44.47 per boe.
9. Positive reserve revisions include reserves obtained from “Discoveries”, “Extensions”, “Infill Drilling”, “Improved Recovery”, “Technical Revisions” and
“Economic Factors” as defined in COGEH.
10. Waterflood reserve additions represent reserves over primary, as evaluated by independent reserve evaluators, for areas that are directly under
waterflood.
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.
40
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, 2015. 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, 2015 and are based on current accepted technology and 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, 2015.
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 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.
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.
9.
March 31, 2016 Sproule pricing : 2016 US $45 WTI and US/CAD $0.75 exchange, 2017 US $60WTI and US/CAD $0.80 exchange. Hybrid Sproule price deck in 2016; US $35 WTI and US/CAD $0.71 exchange, 2017
US $45WTI and US/CAD $0.73 exchange
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.
41
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 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. 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. 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 as 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.
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.
42
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
403.767.6930
1.855.767.6923 (Toll Free)
investor@crescentpointenergy.com
www.crescentpointenergy.com
Suite 2000, 585 – 8th Ave SW, Calgary, AB T2P 1G1
T: 403.693.0020 | F: 403.693.0070 | TF: (Canada & USA) 1.888.693.0020
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