Overview of the Drivers of Current
Instability  Innovation
Bruce Peachey, FEIC, FCIC, P.Eng.
PTAC Technical Advisor
May 12th, 2015
Issues to Cover
z Natural Gas Sector
z Current gas prices vs. future prices (Canada vs. the World)
z What will drive future prices and opportunities?
z Natural Gas recognizing resource vs. reserves
z Oil Sector
█
█
Current oil prices vs. future
What gives with Shale and Tight Oil?
z Oil Sands Sector
█
█
Markets, Prices and Differentials
Rapid Growth vs. Maintain Production
Natural Gas Supply Paradigm has
Radically Changed in 7 Years!!!
zNatural gas depleted
█
High gas prices $8/GJ
█ Alternate fuel sources needed
 clean coal/nuclear
zDiluent shortage looming 
rich gas deposits depleted
2008 Paradigm
zNatural gas surplus
█
Low gas prices <$2-4/GJ
█ Other sources can’t compete
with “clean American” gas
zDeep shale gas  Rich in
Natural Gas Liquids & CO2
2015 Paradigm
• Governments, regulators, developers, suppliers
and the public are having a hard time adjusting to
the change  Creates Opportunities for SMEs
Global Gas Supply & Demand Trends
3250 BCM/yr
Rest of World
Asia Pacific
1700 BCM/yr
Europe & Eurasia
North America
85% Increase over 25 years!
BP 2012 Statistical Review – 1986-2011
Global Natural Gas Price Chaos
Russian base
gas price
Future
Convergence??
??
As differential drops so does
incentive for new LNG!!!
Source - BP
What Drives Canadian Gas Demand/Price?
z U.S. Demand Dropping  No need to buy
Canadian Gas
█
Even with conversion to natural gas power
█ Projections are that U.S. could be re-exporting Cdn gas
z Alberta Oil Sands Gas Demand Growing
█
Soon could be 50% or more of Alberta’s produced gas
█ Oil Sands Producers Prefer Alberta Gas  No Royalty
z LNG Markets?????
Doesn’t Look Good Right Now  Will mainly be B.C. Gas
█ Time is running out  Others (Australia, U.S. may be there 1st
█
z Long-term  Huge New “Resources”
█
Will they become “reserves”?
EIA U.S. Gas Supply History &
Forecast
Demand Increase +25% Mainly for
Gas Power Generation
Imports from Canada!!
Y2K 20% to 1% in Y2K +35
Source – www.powermag.com “Global Gas Glut”
Natural Gas Power Generation in the
U.S. & Canada???
Easy option for “greener” power
• Increased energy efficiency
• Decreased GHG emissions
• Decreased water use
• Lower capital costs
• Faster construction
• Shale gas close to demand
• Balancing of “renewables”
Source “Power” magazine
 Recently added to my reading list!
CSP = Concentrated Solar Power  6xNG
PV = Photovoltaic Power (Centralized)  8XNG
Source www.claverton-energy.com
Shale Gas Resources in the U.S.
Source US DOE – NB a lot of deposits don’t even have estimates of potential gas in place
Alberta gas production vs. demand
Source AER ST98-2014
Gas Pipelines to LNG Markets
Battle for Kitimat:
• Alberta’s Bitumen
• B.C.’s LNG
• Small population
• Impacts on Native Bands
• Few sites for facilities
• Narrow shipping channel
• Oil vs. LNG tankers
• Oil vs. gas pipelines
• Overlapping construction
Potential LNG Outlets
to the Pacific Markets
• Prince Rupert
• Kitimat
• Multiple projects
proposed to get to the
same market
“The Big Picture”
A Global Shale Gas Revolution
Total Canadian Production
Todate (2011) = 224 tcf
Remaining Conventional
Reserves = 69 tcf
The Resource Triangle
Improving
Technologies*
Increasing Costs
Decreasing
Recovery
Source: NPC Global Oil and Gas Study
*Masters and Grey
Gas “Triangle”  Volumes-in-Place
Conventional Gas
Fixed Volumes
Tight Gas Sands
Onshore or Near Shore Basins
Coalbed Methane
Gas Shales
Deep Subsea & Subarctic
Gas Hydrates
Additional Volumes
Of Gas Forming
• Biogenic
• Thermogenic
Natural Gas Innovation Needs?
z Optimize production of gas resources for our
own use for Oil Sands and Power Generation
█
Avoid embarrassment of importing fuel gas
█ NDP commitment to eliminate coal power through more
cogeneration and natural gas generation
z Boost Alberta Competitiveness vs. U.S.
Work toward year-round drilling to lower costs  steady vs.
seasonal
█ Focus on increase gas recovery and capture vs. just drilling
more wells  Dewatering; Lower processing costs; Increase
capture of NGLs at low cost  Keep existing gas plants going
█
z Provide Innovation for International Producers
█
Make Alberta a preferred supplier of oil and gas technology
Oil Price Reality Check…(a few years old)
For those who think of the oil industry as greedy and making huge profits,
here is a different perspective for the consumer…
Costs below are (42 gallons)
for a barrel
Costs below are
for a barrel
(42 gallons)
Coca Cola
$78.73
Crisco Oil
$435.12
Milk
$126.00
$826.65
Evian Water
$189.90
Scope
Mouthwash
Orange Juice
$251.16
Sunflower Oil
$971.04
Snapple
$267.12
Olive Oil
$1,324.38
Perrier Water
$328.67
Lemon Oil
$390.88
West Texas
Intermediate Crude
Real Maple Syrup $1,787.52
Sesame Oil
$2,535.61
Visine Eye Drops
$32,202.24
$40.00 - $100.00
Ever wonder if we’re in the wrong business?
Which of these products does society need the most?
Global Oil Prices 1861-2013
1800’s – Whale Oil to
Kerosene
1970s – IOCs
 NOCs
2000s – Light 
Heavy  Shale
Trend?
$100
2013 US Dollars
$80
New
Range?
1900 – Horses
 Oil
1920s Coal 
Oil
$40
$0
Money of the Day
BP Statistics 2014
What Drives Alberta Light Oil Price?
z Undiscounted  higher quality
Light oil without sulphur is worth more to refineries  lower
cost to turn into gasoline; easier to pipeline
█ Tight Oil  same as conventional
█ Shale Oil Only the lightest stuff economic
█
z Alberta Land-locked
█
Isolated from the main consumer markets
█ Pipeline limits  Impact volumes and ability to ship products
z Internal Competition with Oil Sands
Royalty Incentives for Oil Sands  Disincentive for Light Oil
█ Gradually being Adjusted  New EOR Royalty in 2013
█
z Long-term  Quality of New Shale Oil Resources
Variation Between Crudes
z Conventional Oil
• Density = 38 API; Viscosity (@110oF) = 10 cP; Sulphur
(wt%) = 0.4%; Acid No. (mgKOH/g) = 0.4; Gasoline = 31%
z Medium Oil
• Density = 22.4 API; Viscosity (@110oF) = 64 cP; Sulphur
(wt%) = 1.6%; Acid No. (mgKOH/g) = 1.2; Gasoline = 11%
z Heavy Oil
• Density = 16.3 API; Viscosity (@110oF) = 642 cP; Sulphur
(wt%) = 2.9%; Acid No. (mgKOH/g) = 2; Gasoline = 7%
z Natural Bitumen
• Density = 5.4 API; Viscosity (@110oF) = 198,000 cP;
Sulphur (wt%) = 4.4%; Acid No. (mgKOH/g) = 3; Gasoline
= 4%
USGS World Wide Bitumen & Heavy Oil 2007
Gasoline vs. Oil Benchmarks
•Most refineries and gasoline
consumers are not in regions
where oil is produced, so
gasoline tends to follow
international light oil prices.
• 2012 data shown here
shows impact of the oil glut
in Central North America
•Gasoline prices can also be
impacted by lower refining
capacity during refinery
shutdowns for accidents or
maintenance usually high
gasoline demand (summer)
“The Wall” North American Oil Glut
US production 13 yr can grow faster than oil sands @ $100/bbl
• Tight oil can grow much faster than oil sands and fill pipelines 
don’t know the limits or ultimate reserves or recoveries yet
•
U.S. Shale Oil
Up +0.7 Mbopd since 2008!
Canadian Oil Production
Up +0.8 Mbopd since 2000
0.2 Mbopd from tight oil
Focus on Oil Sands Delays Light Oil
z Eg. Cardium – Largest Light Oil Pool  Needs
more investment  hz wells; CO2 or Gas EOR
Historic Cardium Oil Well Development - Annual Completions by Well Type
800
Horizontal
600
Primary &
Waterflood
500
Horizontal
Directional
Vertical
Infills
Infills
400
300
200
100
0
1953
1955
1957
1959
1961
1963
1965
1967
1969
1971
1973
1975
1977
1979
1981
1983
1985
1987
1989
1991
1993
1995
1997
1999
2001
2003
2005
2007
2009
2011
2013
Cardium Oil Completions Per Year
700
Shoul d have b een l i k e Weyb ur n
• Second largest pool in Canada, not as “tight”
• Sask. provided incentives to encourage more production
Weyburn CO2 Flood - Source Cenovus
Type Curves by Season
z Rapid decline then levels out
z Learning curve getting higher initial rates, but maybe not
more oil recovery. Time will tell
█
Higher cost wells to get oil quicker, but by how much?
Cardium Oil Well Average Type Curves by Drilling Season
July 2009 to June 2013
25
Average Well - Cumulative Production by Drilling Season
July 2009 to February 2014
7,000
6,000
125 bopd/well
20
2009/10
2012/13
15
5,000
2010/11
2009/10
2011/12
4,000
2012/13
2010/11
2011/12
2012/13
3,000
10
Avg Daily Rates
2009/10
2,000
Cum Production
1,000
5
0
0
0
0
2
4
6
8
10
12
14
16
18
20
22
24
26
28
30
32
34
36
38
40
42
44
2
4
6
8
10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44
Economics
z Examples from Producer Websites
█
Large range of values depending on formation depth, location, GOR, pad
vs. single wells, other variables
Producer and Area
Capital Cost
($MM/well)
Initial Year
Production Rate
(boe/d)
NPV@10%
(MM$)
Rate of Return
(%)
Payout (years)
ARC Pembina
2.6
104
Bellatrix Cardium
3.6
~275
Bonavista Lochend Cardium
3.4
194
Bonterra Cardium
2.5
100
Lightstream West Pembina Cardium
4.1
~151
Pengrowth Garrington Cardium
3.5
77
2.1
35
2.3
Pengrowth Lochend Cardium
3.9
132
3.2
46
1.9
Penn West Cardium Crimson Lake
3.0
Penn West Cardium Lodgepole
2.5
Vermillion West Pembina Cardium
3.0
~165
85
2.0
Whitecap East Pembina Cardium
2.5
98
3.11
94
1.12
Whitecap Garrington Cardium (ERH)
3.6
169
5.5
164
.78
Whitecap Garrington Cardium (std)
3.0
114
3.46
79
1.28
66
6.1
159
.8
.6
88
1.2
1.6
Shale Oil – What gives?
z Extremely Cash Flow (Oil Price) Sensitivity
At $100/bbl: 1 well  3 new wells = rapid growth
█ At $60-$80/bbl: 1 well  1 new well = no growth
█ At $40-$50/bbl: 2 to 3 wells  1 new well = decline
█
z Capital Costs  Wide Variation
$500k (Viking Oil)  $25M+ (Duvernay)
█ ~50-50 cost split drilling vs. completion (multistage fracturing)
█
z Still Drilling but not Completing Shale Oil Wells?
█
Prove production “capability” to high grade/retain leases
█ Rigs were hard to come by so many under long term contracts
█ Drilling takes months – completions only take days
█ Belief that oil price slump is temporary
Light Oil Innovation Needs?
z Increase liquids production and recovery per well
█
Offset high tight and shale well costs with more production
█ Refracturing?  or Pressure maintenance?
█ EOR – Waterfloods, gas floods  Already starting in Bakken
z Boost Conventional with more EOR
█
New EOR Royalty regime should help encourage
█ Lower cost natural gas  should support EOR
█ Have many pools which have had NO EOR applied
█ Portable EOR methods preferred
z Provide Innovation for International Producers
█
“Alberta Advantage” is a public database to learn from!!!!!!
Heavy Oil is a Different Market!!!
•U.S. heavy oil imports feed
into refineries with upgraders
on the east coast , the Gulf of
Mexico or even California
•Many east coast and Gulf
Coast refineries are designed
to take Venezuelan or Mexican
heavy oil  partially owned by
PDVSA (Venezuela) which are
declining due to lack of
investment
•California domestic heavy oil
production also declining 
Need heavy from Gateway
Can’t Produce
Losing to Shale
Losing to Shale
Can’t Produce
http://endofcrudeoil.blogspot.ca/2012/06/canada-energy-report.html
Canada filling a gap in U.S. heavy oil
supply vs. replacing light oil
Canada also imports Venezuelan Heavy
Oil into East Coast Refineries
• Opportunity to supply from Western
Canada but need pipelines
• Oil pipelines to Eastern Canada go
through the U.S. so major upgrades
need U.S. State Dept & Presidential
Approval
****U.S. is already “re-exporting”
Canadian Heavy Oil from Gulf of Mexico
ports (because we can’t get export
markets directly  loss of revenues to
Canada!!!!)
Pipeline Limits to Oil Price
•Most oil pipelines go to
the U.S. through states
now producing large
volumes of tight oil
•Only one pipeline to the
west coast. Mainly to
meet B.C.’s needs
•Limited capacity to
Eastern Canada through
the U.S.
•East coast mainly
imports crude from
other countries. Line
has often been reversed.
http://endofcrudeoil.blogspot.ca/2012/06/canada-energy-report.html
Price Disadvantage of Bitumen
Source: CAPP to March 2015
Heavy Oil and Oil Sands
z Lower Prices Reduce Cash Flow  New Builds
█
Industry basically reinvests to grow at maximum rate while
avoiding higher royalties after payout
█ Phased developments are relatively easy to slow down or
speed up
█ Plants under construction will finish  Best ones go first
z Oil Sands better than Shale at low Oil Price
█
Trade off of high present value and stability vs. short-term
payout investments that need high prices
z Still potential to export to other heavy markets
█
But would be better to go an “All Canada” route
Heavy Oil / Oil Sands Innovation Needs?
z Reduce capital and operating costs
█
Especially if Alta starts to talk about changing oil sands
royalty formula which protected producers from capital risk
█ Operations with operating costs below $40/bbl of raw bitumen
should be safe  Low gas prices help this
z Continue Increasing Recovery
█
Producers continuing to increase recovery in thermal
operations and converting non-thermal to thermal as they run
out of primary production drilling locations
z Time to Address Environmental Issues
During high growth  low resources available for this
█ NDP government likely to increase motivation to implement
changes
█
Overall Summary of Industry Drivers
z Focus will be on Efficient use of Capital, People
and Recovery of Resources vs. rate of growth
█
Natural Gas, Light Oil and Heavy Oil / Oil Sands will not
dissappear
z Generally should be a better time for innovation
█
At $100/bbl no one had the time or motivation to be efficient
█ Higher price forces companies to operate “smarter”
█ New government  likely change some priorities
z Main Challenge  Getting over the shock!!!!
█
Rapid changes first in technology, now in price, result in a lot
of uncertainty and it will take time for producers and
government to adjust
Questions & Discussion???