Crescent Point Energy Corporate Presentation March 2016

Crescent Point Energy
Corporate Presentation
March 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; expected impact of dividend reduction on long-term growth; living within cash flow; plans for the use of excess cash flow; payout ratios; impact of price danger on funds flow; waterflood
plans; step-out drilling plans; half-cycle capital efficiencies; corporate decline rate reductions; F&D costs; using internal funding to complete future acquisitions; potential additional cost savings in 2016;
expected ongoing cost improvements in 2016; planned reduction or elimination of fresh water usage during completions in Viewfield Bakken; improving differentials in Uinta; the ability of the Company to
maintain its balance sheet strength; type well economics and performance; drilling inventory and reserve life index expectations; the anticipated impact of technical advancements and waterflood activities
on productivity and decline rates; the Company’s strategy to increase recovery factors and maintain high netbacks with low costs; the Company's waterflood goals and injection well plans; the ability of the
Company to manage the current low oil price environment; the Company’s hedging program; the Company’s business strategy (including development, enhancement, acquisition and risk management);
capital allocation; 2016 capital expenditure scenarios; CAGR predictions; free cash flow; future commodity prices and production; capital cost and type well scenarios, cost per well, NPV, rate of return and
payout; increased recovery given mobility levels; plans for injection wells; production and reserve growth; outperformance of large oil in place pools; and the Company’s expected ongoing emphasis on
prudent cost and risk management.
Statements relating to "reserves" are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the
quantities predicted or estimated and that the reserves can be profitably produced in the future. There are numerous uncertainties inherent in estimating crude oil, natural gas and NGL reserves and the
future cash flow attributed to such reserves. The reserve and associated cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties,
production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and
future operating costs, all of which may vary materially. Actual reserve values may be greater than or less than the estimates provided herein. All 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
$9.2 billion (508.9 million shares fully diluted)(1)
Net Debt*
$4.3 billion (incl. hedged US$ denominated debt)
Enterprise Value
$13.5 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 December 31, 2015.
Maximize shareholder return with long-term growth and dividend income
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
3
Q4 2015 AND 2015 YEAR-END HIGHLIGHTS
•
Record Q4 production greater than 176,000 boe/d; up 14% year-over-year
• Well positioned in 2016 with current Q1 2015 production greater than 177,000 boe/d
•
Q4 2015 funds flow per share of $0.98;
• 2% per share growth versus Q3 2015 with operating costs and royalties down from Q3 2015
• Q4 average netback of $34.17/boe including hedging gains, or $22.48/boe excluding hedging gains
•
Reduced overall capital cost structure by ~30% relative to 2014 costs
• Targeting 10% further cost improvements in 2016
•
Advancing resource plays
• Uinta: Continue to evaluate and test horizontal drilling potential across several zones
• Flat Lake Torquay: Step-out drilling success, further expanding economic boundaries
• Midale: Step-out drilling continues to add new economic locations
• Viewfield: Completions technologies increasing productivity and expanded waterflood initiatives
reducing decline rates
•
Subsequent to quarter, reduced monthly dividend to $0.03/share to protect the balance sheet, increase
financial flexibility and enhance long-term growth profile
•
Significant financial liquidity with unutilized credit capacity of more than $1.4 billion on covenant-based,
unsecured credit facility (June 2018 renewal)
4
2015 RESERVES HIGHLIGHTS
• Replaced 315% of 2015 production and increased Proved plus Probable (“2P”) Reserves by
16% to 935.7 mmboe
• 14th consecutive year of strong organic reserve additions
• Added more than 65 mmboe of 2P reserves (replaced 109% of 2015 production)
• 2P F&D of $9.83/boe (incl. changes in FDC)
• 2.6x recycle ratio
• Organically added ~4.5 mmboe of 2P Viewfield and Shaunavon waterflood reserve additions
• 3rd consecutive year of waterflood reserve additions in Viewfield Bakken
Continuing to generate strong reserves growth across asset base
5
ORGANIC RESERVES GROWTH
Cumulative Technical and Development
2P Reserve Additions (mmboe)(5)
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 $20.39/boe with a recycle ratio of 2.2 times(6)
Long-term strategy of step-out and infill drilling, waterflood optimization and improved technology
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
6
BUSINESS STRATEGY
Develop and Enhance Assets
• Increase recovery factors through step-out and infill drilling, waterflood
optimization and improved technology
• Maintain high netbacks with low operating, royalty and transportation costs
Acquire
• Focus on high-quality, large resource-in-place pools with the potential for
upside in production, reserves, technology and value
• Utilize internal funding to complete future acquisitions
Manage Risk
• Maintain strong balance sheet, with significant liquidity and no material
debt maturities and a 3½-year hedging program
7
BALANCE SHEET STRENGTH
Debt Composition ($CAD) as of Dec 31, 2015
4.0x
$1.8B
Senior
Guaranteed
Notes*
3.0x
$1.4B
Unutilized
Credit
Capacity
2.0x
1.0x
$2.2B
Drawn on Bank
Credit Facilities
(~60% utilized)
0.0x
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Million $ CAD
Senior Guaranteed Notes Maturity Schedule*
•
Living within cash flow in 2016 and 2017
•
No material near-term debt maturities
•
Significant unutilized credit capacity of more than $1.4 billion
on syndicated credit facility with June 2018 renewal date
•
Bank credit facilities and senior guaranteed notes rank equal
and are unsecured and covenant-based.
•
US$ denominated senior guaranteed notes fully hedged with
cross currency swaps
$232
250
200
150
100
Net Debt to Funds Flow from Operations
$119
$50
50
0
Less than 1 year
1 - 3 Years
3 - 5 Years
Significant amount of liquidity and financial flexibility
*Includes underlying currency swaps
8
COMMODITY HEDGING STRATEGY
Current Oil Hedges
50%
2016 average floor price ~ CAD $80.00/bbl
2017 average floor price ~ CAD $76.00/bbl
2018 average floor price ~ CAD $80.00/bbl
50,000
40%
bbl/d
40,000
30%
2017 Average:
9%
30,000
20%
20,000
2018 Average:
3%
10,000
% hedged
2016 Average:
39%
60,000
10%
0
0%
Q1 16
Q2 16
Q3 16
Q4 16
Swaps
Q1 17
Collars
Q2 17
Q3 17
Q4 17
Q1 18
Q2 18
Q3 18
Percent Hedged w/o Extendables
• Mark-to-market value of hedge book is ~$500 million, including oil and gas hedges in place through 2018
Disciplined hedging strategy reduces volatility
As of March 4, 2016. Percentages based on 2016 guidance.
9
FULLY-FUNDED MODEL
2016 @ US $35 WTI
2017 @ US $45 WTI
Total Payout Ratio: 97%
Total Payout Ratio: 96%
21%
of FFO
Cash
Dividends
16%
of FFO
Cash
Dividends
80%
of FFO
Capital
Expenditures
Funds Flow
Funds Flow
76%
of FFO
Capital
Expenditures
Production: 165,000 boe/d
Production: 165,000 boe/d
• Forecast 97% total payout ratio protects balance sheet strength
• Funds flow increases by ~$400 million in 2016 and ~$600 million in 2017 for every US$10/bbl increase in WTI
Sustainable business model positioned for upside in oil price recovery
FFO = Funds Flow from Operations.
10
FOCUSED GROWTH
Large Oil in Place with significant running room
• Only 3.0% recovered to date with
significant growth potential
• ~14 years of drilling inventory
Viewfield Bakken
Shaunavon
Flat Lake / Midale
Viking
Conventional
OOIP
>7.8
billion
barrels
OOIP
>5.2
billion
barrels
Uinta Basin
OOIP
>7.4
billion
barrels
High-return asset base
• Top-quartile netbacks supported by low
operating costs
• Shallow plays with low capital costs
Focused on long-term value creation
• Waterflood development increases net
asset value and lowers decline rates
• Advancing core plays through step-out
drilling and new technology
11
SIGNIFICANT ECONOMIC INVENTORY
Total Net locations(4)
2016 Net Drills
Years of Inventory
Recovery to Date
Shaunavon
~1,850
~102
~18
1.2%
Conventional
~1,225
~80
~15
8.3%
Viewfield Bakken
~1,200
~124
~10
3.4%
Uinta
~1,150
~7
>50
0.6%
Viking
~1,000
~148
~7
1.3%
Flat Lake / Midale Unconventional
~825
~60
~14
0.9%
Other
~450
~29
~16
14.2%
TOTAL
~7,700
~550
~14
3.0%
Key Focus Areas
Proved and probable locations evaluated by GLJ Petroleum Consultants Ltd. and Sproule Associates Limited.
Recovery to date as of December 31, 2015.
•
Increasing recovery factors through step-out drilling, new technology and waterflood
Early-stage resource plays with significant growth potential
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
12
2016 GUIDANCE
2016 Capital Budget Break-Down
2016 Guidance
Production (boe/d)
US$35/bbl WTI
Long-Term Capital
165,000
~$75 million
Waterflood Injection Well Conversions
Step-Out Drilling
Capital Expenditures
Total Payout Ratio
$950 million
New Completions Technology
Drilling Capital Efficiencies
~$21,000 / boe
Drilling Capital Efficiencies (ex. Long-Term Capital)
~$19,500 / boe
97%
•
Living within cash flow: protecting balance sheet and production levels
•
39% capital expenditures reduction from 2015: ($950 million in 2016 from $1.56 billion in 2015)
•

~55% of capital allocated to H2/16 to benefit from ongoing cost reductions and to increase 2017 flexibility

Reiterated production guidance of 165,000 boe/d
Focused on long-term sustainability:

Accelerating waterflood development; 120 water injection conversion wells planned for 2016, up 70% from 2015

Advancing technology across asset base to improve recoveries and per-well economics

Drilling step-out wells to expand the economic boundaries of core resource plays
13
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
•
Targeting further capital cost reductions of 10% on average during 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%.
14
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.
15
2016 CAPITAL PROGRAM SUPPORTED
BY QUICK PAYOUTS
Type Well Payouts by Play
(Excluding Upside from Waterflood and New Technology)
60
Months
48
36
24
12
US $35 WTI
US $45 WTI
0
Viewfield Bakken
75 - 125
Type Well
Flat Lake
Torquay
SE SK
Conventional
Midale
Unconventional
SK Viking
150 - 225
Type Well
65 - 75
Type Well
103 - 175
Type Well
41 - 51
Type Well
Swan Hills
180 - 250
Type Well
Shaunavon
(Upper & Lower)
84 - 150
Type Well
Uinta
(Vertical)
125 - 175
Type Well
High-return asset base provides capital flexibility during current environment
US $35 WTI = $35WTI/bbl in 2016, $45WTI/bbl in 2017 and Sproule Dec. 31, 2015 pricing assumptions thereafter.
US $45 WTI = Sproule Dec. 31, 2015 pricing assumptions.
16
VIEWFIELD BAKKEN WATERFLOOD:
TRIPLES VALUE OF BAKKEN INFILL WELLS
Viewfield Waterflood Offset Well
EURs ~3x greater versus Primary(7)(8)
160
Example of Per Section
Bakken Recoveries and Economics
140
120
Oil Rate (bbl/d)
100
Development
80
Primary Infill
Waterflood – Indirect offset
Waterflood – Direct Offset
60
Estimated
Recovery
Factor(9)
Incremental
EURs (mbbls)
Cumulative
F&D costs
(per bbl)
EUR
(mbbls)
NPV
@10%*
4-well Spacing
6.1
~10%
615
~$13
100
125
350
$2.1 M
$2.8 M
$5.9 M
8-well Spacing
6.1
~19%
553
~$13
Waterflood
6.1
~30%
676
~$9
Waterflood
6.1
~40%
615
~$7
EUR: 350 mbbls
40
OOIP
(MMbbls)
EUR: 125 mbbls
20
EUR: 100 mbbls
0
0
1
2
3
4
5
Years
100mbbl Infill
Direct Offsets
Indirect = 125mbbl
DO = 350mbbl
Indirectly Affected
Includes historical land acquisition costs of $1M per section, primary well costs of
$1.8M and waterflood injector conversions of $0.4M per well. Current primary well
costs are ~$1.4M.
• Incremental F&D of waterflood reserve additions <$3/bbl
• Currently producing from ~150 direct offset wells in
the Viewfield Bakken
*December 31, 2015 Sproule pricing
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
17
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
18
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)(6)
Cost-focused producer with strong netbacks and capital efficiencies
Excellent Balance Sheet
•
Conservative and flexible capital budget to live within cash flow and maintain balance
sheet strength
•
Utilize internal funding to complete future acquisitions
•
3½-year hedging program provides cash flow stability and balance sheet protection
•
Significant unutilized credit capacity of more than $1.4 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
19
APPENDIX
20
ORIGINAL OIL IN PLACE ~23 BILLION BARRELS
OOIP (mmbbls)*
Recovery to Date**
Independent Recovery Factor
(P+P)***
Shaunavon
5,500
1.2%
3.6%
Uinta Basin
5,200
0.6%
3.4%
Viewfield Bakken
4,600
3.4%
8.5%
Flat Lake
1,800
0.9%
3.8%
Viking
1,400
1.3%
5.0%
Midale Unconventional
1,000
0.9%
3.7%
Turner Valley
1,000
19.8%
23.9%
Swan Hills
600
2.4%
9.2%
Cantuar
500
15.7%
21.1%
Battrum
400
26.9%
36.0%
Other
1,000
8.3%
10.6%
TOTAL
23,000
3.0%
6.5%
Key Focus Areas
All figures are rounded to approximate values
*Gross OOIP estimates
**As of December 31, 2015
*** Calculated by dividing net OOIP by reserves assigned by independent engineering evaluators
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 $1.86 and heavy oil differential of 25%.
Based on 43 light and medium oil plays (excluding condensate). Payouts based on average of total play results.
22
VIEWFIELD BAKKEN
Crescent Point Energy lands
Waterflood Unit outline
(Four Units in total)
Viewfield Bakken edge
Waterflood affected area
•
Q4/15 production: ~64,000 boe/d
•
~1,200 net drilling locations
•
~4.6 billion barrels of Original Oil in Place with recovery to
date of 3.4%
•
Continue to implement new completions technology
resulting in improved overall returns and recovery factors
and less water consumption
•
Producing oil wells directly offsetting injection wells
demonstrating significant improvements in decline rates and
approximately three times the estimated ultimate recovery
•
Unitizing remaining three waterflood units; budgeted
injection conversions of ~50 wells in 2016 up from ~30 in
2015
•
Working towards eliminating the use of fresh water during
the completions process
Type Well
(mbbls)
Cost per
well ($M)
NPV @
10% ($M)
Rate of Return
(%)
Payout
(months)
2016 US$35/bbl WTI*
75-125
$1.3
$0.9 to $2.5
41 to 120
13 to 27
December 31, 2015 Sproule pricing
75-125
$1.3
$1.3 to $3.1
65 to 200
9 to 18
Pricing Scenario
*Cdn$0.71 exchange.
~1,200 net drilling locations, of which 536 net are proved and 157 net are probable reserve locations as independently evaluated by GLJ
Petroleum Consultants Ltd. and Sproule Associates Limited. Remaining locations are internally identified unbooked locations.
23
STRATEGIC ASSET BASE WITH STRONG ECONOMICS
Viewfield Bakken Infill Type Well
(75 mbbls)
Comparison
Viewfield
North Dakota
160
Land
Majority crown
Majority freehold
Royalties
Crown holiday,
~10% royalty
No holiday,
~30% royalty
Efficiencies
Multi-well batteries,
no day camps
Single-well batteries,
camps for workers
Capital
Shallower wells,
lower cost wells
Deeper wells,
higher cost wells
Average Netback
($/boe)
Cumulative
Cash Flow (M$)
(excl. initial capital)
Production (boe/d)
140
120
100
80
60
40
20
0
0
1
2
3
4
5
Year
75 mbbls infill type well 60/40 Crown/Freehold; 0% GOR, Type Well Economics @ December 31, 2015 Sproule pricing
Average
Average
Average
Average
Production
Oil Production
Average
Royalty
Op Cost
(boe/d)
(bbl/d)
Oil Price (C$/bbl)
(%)
($/boe)
Year 1
72
62
$53.70
10
$6.53
$38.05
$975
Year 2
29
25
$68.00
10
$9.47
$47.10
$1,787
Drilling and completion capital costs of $1.3 million
24
SHAUNAVON
•
Q4/15 production: ~25,000 boe/d
•
~1,850 net drilling locations
•
~5.5 billion barrels of Original Oil in Place with recovery to date of 1.2%
•
Upper Shaunavon wells exceeding expectations
•
Producing oil wells directly offsetting injection wells demonstrating significant
improvements in decline rates and approximately two times the estimated ultimate
recovery
•
Continue to advance waterflood with ~30 injection well conversions planned for 2016
•
Eliminated the use of fresh potable water during completions in Q4 2015
Crescent Point Energy lands
Lower Shaunavon edge
Upper Shaunavon edge
Waterflood affected areas
Type Well
(mbbls)
Cost per
well ($M)
NPV @
10% ($M)
Rate of Return
(%)
Payout
(months)
2016 US$35/bbl WTI*
84-150
$1.4 - $1.5
$0.6 to $1.5
22 to 38
34 to 48
December 31, 2015 Sproule pricing
84-150
$1.4 - $1.5
$1.0 to $2.2
37 to 78
17 to 30
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.
25
SHAUNAVON WATERFLOOD ECONOMICS
Example of Per Section Shaunavon Recoveries and Economics
OOIP (MMbbls)
Estimated Recovery
Factor(9)
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 ~$1.6M. OOIP per section based on lower Shaunavon OOIP estimates only.
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
26
FLAT LAKE UNCONVENTIONAL
•
Q4/15 area production: ~17,000 boe/d
•
~825 net drilling locations
Viewfield Bakken
Flat Lake Torquay: (Torquay/Three Forks, Bakken and Ratcliffe)
Torquay
•
~1.8 billion barrels of Original Oil in Place with recovery to date of ~0.9%
•
~300 net sections in the core boundary; continues to expand
•
New Ratcliffe zone (low capital costs / un-fracked wells)
•
First waterflood pilot to be initiated during 2016
Midale
Flat Lake Midale: (Midale, Torquay/Three Forks and Bakken)
Flat Lake lands
Flat Lake edge
Crescent Point Energy lands
USA border
Torquay (Three Forks) Economics
•
>1 billion barrels of Original Oil in Place with recovery to date of ~0.9%
•
Increasing water injection wells in 2016, building on success of initial pilots
Midale Unconventional Economics
Type Well
(mbbls)
Cost per
well
($M)
NPV @
10% ($M)
Rate of
Return
(%)
Payout
(months)
Pricing Scenario
2016 US$35/bbl WTI*
150-225
$2.4
$2.1 to $4.0
43 to 90
16 to 28
December 31, 2015
Sproule pricing
150-225
$2.4
$2.8 to $4.9 74 to 177
10 to 17
Pricing Scenario
*Cdn$0.71 exchange. Based on 1-mile horizontal well economics.
Type Well
(mboe)
Cost per
well
($M)
NPV @
10% ($M)
Rate of
Return
(%)
Payout
(months)
2016 US$35/bbl WTI*
103-145
$1.6
$0.2 to $1.5
16 to 46
28 to 51
December 31, 2015
Sproule pricing
103-145
$1.6
$0.7 to $2.4 36 to 104
13 to 27
*Cdn$0.71 exchange. Based on an expected type well for the Steelman / Pinto Midale area.
~825 net drilling locations, of which 115 net are proved and 146 net are probable reserve locations as independently evaluated by GLJ
Petroleum Consultants Ltd. and Sproule Associates Limited. Remaining locations are internally identified unbooked locations.
27
UINTA BASIN
Multi-Zone Basin
Ouray
Valley
Gusher
Blacktail Ridge
Rocky Point
Randlett
Aurora
Horseshoe
Bend
North Monument
Butte
Lake Canyon
Crescent Point Energy lands
Zones tested horizontally since late 2014
•
Q4/15 production: ~14,000 boe/d
•
~1,150 net low-risk vertical drilling locations plus
horizontal drilling opportunities
•
•
~5.2 billion barrels of Original Oil in Place with
recovery to date of ~0.6%
Oil price differentials continue to improve
Vertical Drilling Economics
Type Well
(mbbls)
Cost per
well
(US$M)
NPV @
10% (US$M)
Rate of Return
(%)
Payout
(months)
2016 US$35/bbl WTI*
125-175
$1.3 to $1.4
$0.7 to $1.7
22 to 44
31 to 50
December 31, 2015
Sproule pricing
125-175
$1.3 to $1.4
$1.0 to $2.0
32 to 67
21 to 36
Pricing Scenario
*Cdn$0.71 exchange. 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.
28
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
29
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
30
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
•
Integrated strategy of organic development and acquisitions has consistently generated growth on a per share basis
•
Declared $30.94 of dividends per share to shareholders from inception to December 31, 2015
•
Suspended the dividend reinvestment plans (DRIP and SDP) effective August, 2015, further enhancing long-term per share growth
(2)
Continue growing on a per share basis
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
31
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 to ~30,000 bbl/d
(Wood Mackenzie Canada Ltd.)
*Mobility ratio is defined as the oil’s ability to move within the rock; determined by permeability and viscosity
32
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
33
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
34
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
evolutions (December 31, 2015 Sproule pricing - WTI US$45 and
300
250
US/Cdn exchange $0.75)
200
Mbbl
• New closeable sliding sleeve technology allows for:
150
 Lower costs by minimizing sand flow-back
(primary recovery)
100
50
0
Surgi Frac
16 stage packer
16 stage
Frac
cemented liner
25 stage
cemented liner
 Greater efficiency and productivity of
waterflood programs through increased
control of water placement, potentially
leading to enhanced recovery factors
(secondary recovery)
Technology advancements continue to be transferred to our emerging plays
FOOTNOTES INCLUDED IN THE BACK AS ENDNOTES
35
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
200
4.00
Targeting to eliminate fresh
water usage during completions
100
0
0.00
2009
2010
2011
2012
2013
2014
2015
2007 2008 2009 2010 2011 2012 2013 2014 2015
Viewfield Bakken well ROR (3 twp core)
14
25
12
10
20
8
15
6
10
4
700
>500% increase in rate of return
600
500
400
300
200
5
2
100
0
0
0
2007 2008 2009 2010 2011 2012 2013 2014 2015
Dec. 31, 2015 Sproule pricing– 2016 WTI US$45 US/CDN $0.75 exchange
800
Rate of Return %
30
900
Tonnage per stage
Stages per well
Viewfield Bakken Stage and Tonnage Evolution
Surgifrac
16 Stage
Packers Plus
16 Stage
Cemented
Liner
25 Stage
Cemented
Liner
36
ENDNOTES
1. Fully diluted shares outstanding as of December 31, 2015. Based on March 4, 2016 market closing price of $18.04. Directors and officers ownership
represents 0.6% of issued and outstanding shares as of March 6, 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. Positive reserve revisions include reserves obtained from “Discoveries”, “Extensions”, “Infill Drilling”, “Improved Recovery”, “Technical Revisions” and
“Economic Factors” as defined in COGEH.
6. 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.
7. 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.
8. Waterflood reserve additions represent internally evaluated incremental reserves over the average primary type curve described above.
9. Estimated recovery factors are based on independent (P+P) reserves, comparable analog pools, independent studies commissioned by Crescent Point Energy
and company targets.
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.
37
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.
Cash flow equates to funds flow from operations. Cash flow from operations equals funds flow from operations per share.
4.
Net present values disclosed in this presentation are calculated before tax.
5.
Enhanced Ultimate Recovery relates to the extraction of additional crude oil, natural gas, and related substances from reservoirs through a production process other than natural depletion, which
includes both secondary and tertiary recovery processes such as pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible
displacement fluids.
6.
Dividend reinvestment plans include the Dividend Reinvestment Plan (DRIP) and Share Dividend Plan (SDP).
7.
Type wells are internally generated based on actual well results and data that is interpreted by internal qualified reserves evaluators.
8.
December 31, 2015 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.
38
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.
Management believes the presentation of the Non-GAAP measures above provide useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze
performance against prior periods on a comparable basis. This information should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. For definitions of the non-GAAP
measures listed above refer to the Company’s most recent annual Management’s Discussion & Analysis (“MD&A”) available on SEDAR as sedar.com, or EDGAR as 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.
39
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
40