Will We Have the Right Stuff? files 2009/Flint Forward... · 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990 Solution Gas 1 year 3.2 3.4 Bcfd Bcfd 1 year 60 °N 70 60 80 90

Current and Future Natural Gas Supply as Feedstock

CERI Petrochemicals ConferenceJune 2007

1

Will We Have the Right Stuff?Will We Have the Right Stuff?

Current and Future Natural Gas SupplyCurrent and Future Natural Gas Supply as Feedstock

Dave Flint and Bob Dixon

CERI Petrochemical ConferenceCERI Petrochemical ConferenceJune 4, 2007

• Western Canada supply– Current trends

Current and Future Gas Supply Trends

– Fundamentals of short term supply

– Is unconventional gas the right stuff?

• Canadian supply in longer term

• US supply projections

2

• LNG – the genie in the bottle



2

Forward Energy Group IncGas Production by Year Onstream

6,000

8,000

10,000

12,000

14,000

dar D

aily

Sal

es G

as, M

Mcf

d

2005200420032002200120001999199819971996199519941993199219911990Solution Gas

1 year

3.2Bcfd3.4

Bcfd

1 year

60°N

70

60

80

90

100

110

120

6M 5M

120

60

70

80

90

100

110

4M3M

Lloydminster

Edmonton

Grande Prairie

Fort McMurray

Fort Nelson

Fort St. John

50

60

70

90

80

100

110

120

126

Rate Added per TownshipMMcfd

32 to 60 (8)16 to 32 (31)

8 to 16 (90)4 to 8 (196)2 to 4 (319)1 to 2 (464)0.5 to 1 (512)0 to 0.5 (1251)

Brazion, PermianBashaw & Nevis, CBM

Sundown, Cadotte

Drake, Notikewin

Elleh, Jean Marie

0

2,000

4,000

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006Year Onstream

Cal

end

Supply Trends49°N

10

1

20

30

40

50

Swift Current

Saskatoon

Lloydminster

Calgary

Hinton

Medicine HatLethbridge

10

20

30

40

1

Events Onstream 2003 - 2005, MMcfd

Natural Gas Supply Trends

2000 - 2004 Pool Discovery PeriodRate Added per Township

Abbey and Lacadena

Tay River, D3-B

Plays and Sources60°N

80

90

100

6M

110

120

80

120

90

5M

100

110

3M4M

90

80

100

110

120

126

Fort Nelson

Fort Saint John

Fort McMurray

Drilled and PredecessorWells Retained

32 to 42 (2)16 to 32 (3)8 to 16 (16)4 to 8 (20)2 to 4 (35)1 to 2 (45)0.5 to 1 (64)0.25 to 0.5 (44)0 to 0.25 (93)

DevonRate Added per Township, MMcfd

Events Onstream 2003 - 2005

Rate Additions by Deep Basin Play

700

800

900

1,000

MM

cfd

CardiumDunveganCadotte VikingViking OilBow IslandSpirit RiverU. Mannville S.BlueskyGethingEllerslieL. Mannville S.Cadomin

3Better information for E&P strategies

0

60

70

49°N

20

1

10

30

70

60

40

50

40

10

20

30

50

60

70

1

Hinton

Calgary

Saskatoon

Grande Prairie

Swift Current

Lloydminster

Edmonton

Medicine Hat

Lethbridge

Operator Benchmarking0

100

200

300

400

500

600

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005Year Onstream

Rat

e A

dditi

ons

Sale

s G

as, M

CadominNikanassinMultiplay

High Impact Areas

Gas Supply Regions in North AmericaWCSBWCSB

• Largest natural gas supply region in North America

• Produces 6 Tcf per year

Regional Gas Supply

Produces 6 Tcf per year• Supplies over 23% of North

American consumption

LOWER 48LOWER 48• Supplies over 72% of North

America’s demand

4

• Produces 19 Tcf per year

LNGLNG• Future swing supply source

Balancing Natural Gas Policy, NPC (2003)

Continental market



3

• Total production grew by over 70% from 1990 to 2001

Supply by Period Onstream

WCSB Gas Production by Period Onstream

14,000

16,000

18,000

Mcf

d

Wells Onstream 1990 to 2005

Wells Onstream Pre-1990

• Total gas production recovering slowly since 2001

• Wells onstream since 1989 produce 85% of gas2,000

4,000

6,000

8,000

10,000

12,000

Cal

enda

r Dai

ly M

arke

tabl

e G

as R

ate,

MM

5

• Decrease of 300 MMcfd in 2007 due to reduced gas drilling

2006 production estimated at 16.9 Bcfd

01990

19911992

19931994

19951996

19971998

19992000

20012002

20032004

20052006E

2007Fsource: Forward Energy, CAPP

Competing Forces on Gas Supply

Production Lost

Rate Additions

Investment Environment

Profitability

Production Rate

XComposite

Decline Rate

WellsX

Rate Addedper Well

Gas prices

F&D costs

Capital efficiency

Cash flow

Alternative investments

6

•Changing slowly•Low control

•Changing rapidly•High operator control

Portfolio

New opportunities

Technology



4

• Rate loss from decline increased from 2.5 Bcfd to 3.9 Bcfd in 2004

WCSB Rate Losses and Rate Additions

Rate Losses and Rate Additions

3,500

4,000

4,500Rate Lost from DeclineRate Added from New WellsNet Rate Added

• Annual rate loss has averaged 3.7 Bcfd since 2001

• Net rate added has been decreasing

500

1,000

1,500

2,000

2,500

3,000

Rat

e A

dds/

Loss

es, M

Mcf

d

7Rate losses and rate additions close to balance

• 2002 correction may be a useful model for 2007

-500

0

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

• Supply additions were 1.7 Bcfd in 1990, rising to 3.9 Bcfd in 2001, R t dditi

Rate Additions by Year Onstream

Rate Added and Event Count

3,500

4,000

4,500

14,000

16,000

18,000First Year Rate AddedEvent Count

• Rate additions averaged 3.6 Bcfd from 2001 to 2005

• Events are the new connections that provided the new rate additions

• Connections lag500

1,000

1,500

2,000

2,500

3,000

Rat

e A

dded

, MM

cfd

2,000

4,000

6,000

8,000

10,000

12,000

Even

t Cou

nt

8Connections increasing more rapidly than rate additions

• Connections lag drilling0

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005Year Onstream

0

• Since 2000, rate additions static but the number of connections has increased 69%– this is the treadmill!



5

Rate Added per Foot Drilled296

243 241

201190

285

220

241

273

200

250

300

ousa

nd F

eet D

rille

d

Rate Added per Event

814 800

705681

609

539594620

721

500

600

700

800

900Ev

ent,

Mcf

d

Rate Added per Connection

-12%146

121114 109

91

7468

0

50

100

150

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005Year Onstream

Rat

e A

dded

, Mcf

d pe

r Tho

Source: Forward Energy Group

344319 303

265

216 212

402

0

100

200

300

400

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005Year Onstream

Rat

e A

dded

per

E

Source: Forward Energy Group

• Production replacement per foot drilled has decreased by 12% per year

-10%

9

• In 2005, the same event connected and foot drilled resulted in only 30% of the 1995 rate additions per unit

• Supply from previously-unprofitable, lower deliverability opportunities increased in response to higher prices and improved technology

Decreasing results for same activity is the consistent driver of F&D cost increase

WCSB Drilling Cost per Foot Drilled by YearTotal Drilling Capital / Total Feet Drilled

200

250

oot

• Total drilling capital / Total feet drilled

• Cost per unit has been increasing at

Drilling Cost per Foot

9%

50

100

150

Dril

ling

Cap

ital p

er F

oot D

rille

d, $

/ fo been increasing at

9% per year since 1999

• Rapid cost increases in 2005 (14%) and continuing at least 15% into 2006

10

01990

19911992

19931994

19951996

19971998

19992000

20012002

20032004

20052006E

2007FSource: Forward Energy, CAPP

Cost inflation is accelerating, driving F&D costs



6

WCSB Gas F&D Cost by YearGas-directed Capital / EUR Connected

3 38

4.40

4.00

4.50

5.00

• Gas-directed capital / extrapolated recovery in newly-connected zones

Gas F&D cost

2005 gas at $4.40 per Mcf F&D requires a $6.16 cash netback from the 2005 sales price of $8.41

M f t id 10% t

21%

0.790.67

0.77 0.71

1.02 0.98 0.95

1.261.47 1.40

1.88

2.30 2.24

3.38

2.87

0.50

1.00

1.50

2.00

2.50

3.00

3.50

$ C

dn /

Mcf

• Increasing at 21% per year since 1999

• Most of F&D cost increase is in lower EUR per well

per Mcf to provide a 10% return

11

0.001990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Source: Forward Energy, CAPP

Increasing costs threaten profitability and investment

• To sustain investment return, increasing F&D cost must be matched by increasing netback and therefore, increasing price

Natural Gas Price by Year, Canada

6.25 6.38

8.41

6.737.08

7.00

8.00

9.00

• Increased at > 22% per year between 1999 and 2005

• Commodity price

Gas Price

>22%

1.571.35 1.36

1.71 1.86

1.391.68

1.94 1.92

2.48

4.66

5.57

3.93

0 00

1.00

2.00

3.00

4.00

5.00

6.00

$ C

dn /

Mcf

Commodity price increases supported projects despite increased F&D cost

• Estimated 20% decrease in price in 2006

12

0.001990

19911992

19931994

19951996

19971998

19992000

20012002

20032004

20052006E

2007FSource: Forward Energy, CAPP, ARC Financial

What happens when gas prices decrease?

• Rate additions at increasing F&D costs sustained by increasing prices• Activity and rate adds will decrease when price decreases



7

• Active gas rigs dropped below 2005 levels in August 2006

• Dropped below 2004

Drilling Response

Canada Active Gas Rigs

500

600

700

Dropped below 2004 levels in October

• Year to date 2007 active gas rigs are 56% of the comparable 2006 period 100

200

300

400

500

Act

ive

gas

rigs

200420052006

13Rapid response after a record first half of 2006

• Operators have announced reduced shallow gas and CBM programs• Lower utilization rate of shallow rigs

0Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

2007

Source: Baker Hughes Rig Count

• Connections and completions flat 2004 to 2006

• CAODC and PSAC

Drilling Response

Completions, Connections and Gas Price

14 000

16,000

18,000

20,000

ectio

ns

$7 00

$8.00

$9.00

$10.00

Gas Connections

Natural Gas Well Completions

Price $Cdn / Mcf

CAODC and PSAC forecasts 2007 gas completions down 20% to 30%

• We assume a 10% decrease in activity

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Gas

wel

l com

plet

ions

and

zon

e co

nn

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$ C

dn /

Mcf

?

14Lower drilling = lower production

• Decrease in rate added depends on rate added per new event

01995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006E 2007F

$0.00

Source: Forward Energy, CAPP, CAODC, PSAC



8

• F&D costs have been increasing rapidly

• Decreasing rate additions and reserves per well has been the major driver of increased F&D costs

Profitable Production Replacement

• Cost inflation has been a recent contributor

• Increased gas commodity prices supported investment at the increased F&D costs until 2006

• Current slowdown in drilling will result in lower supply, higher gas prices and, in time, lower input

15

pp y g g p pcosts

• WCSB gas F&D costs are less competitive with US basins due to stronger Canadian dollar

Gas Accumulation Types

16Will unconventional gas rescue WCSB supply?



9

What’s in a name?

CONVENTIONAL1. Discrete gas pools in pervasively

water saturated rock - aquifer2. Only high quality reservoir

accumulates gas in place

UNCONVENTIONAL1. Pervasive gas saturated

accumulations - gasifer2. Very large gas in place in

reservoir of all qualitiesaccumulates gas in place3. Discovery is uncertain, recovery

is certain4. Discovery process is efficient

.5. R&D to increase success

6. Remaining resource, in small undiscovered pools, is small

reservoir of all qualities3. Discovery is certain, recovery is

uncertain4. Recovery is inefficient but

improves with technology5. R&D to improve recovery and

characterization6. Remaining resource in lower

quality reservoirs is large7 I d t i f WCSB

17

7. “Official” view of WCSB remaining resources

“Glass is mostly empty”

7. Industry view of WCSB remaining resources – believed in US

“Glass is mostly full”

Models define how we evaluate potential

WCSB Gas Production, by Resource Type

10

12

14

16

18ShaleCoalbed MethaneTight (3 plays)Conventional

US Lower 48 Gas Production, by Resource Type

40

50

60

Gas Production Profiles

WCSB Gas Production, by Resource Type

10

12

14

16

18ShaleCoalbed MethaneTight (3 plays)Conventional

CBM: 240 MMcfd in ’05Shale: none

0

2

4

6

8

10

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Bcf

d

0

10

20

30

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Bcf

d

ShaleCoalbed MethaneTight Conventional

US Lower 48

0

2

4

6

8

10

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Bcf

d

Western Canada

18Better understanding of unconventional gas required

• Conventional gas in decline• Tight gas in lower 48 over

30% of 2005 total • CBM and shale gas significant

• CBM growing rapidly• Tight gas not reported

– estimate over 30% of 2005 total

• Conventional gas in decline



10

Plays and Characterization

3.0

Production by Tight Gas RegionWCSB Gas Production, by Resource Type

4

6

8

10

12

14

16

18B

cfd

ShaleCoalbed MethaneTight (3 plays)Conventional

0 5

1.0

1.5

2.0

2.5B

cfd

Jean MarieShallow biogenicDeep Basin trap

0

2

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

19

19901991

19921993

19941995

19961997

19981999

20002001

20022003

20042005

0.0

0.5

Three major tight gas regions – recent growth trends

60°N

100

6M

110

120 120

5M

100

110

3M4M

Fort Nelson

90

100

110

120

12660°N

100

6M

110

120 120

5M

100

110

3M4M

Fort Nelson

90

100

110

120

12660°N

100

6M

110

120 120

5M

100

110

3M4M

Fort Nelson

90

100

110

120

126

Cumulative Gas per TownshipBCF

>12864 to 12832 to 6416 to 328 to 164 to 82 to 40 to 2

Jean Marie

Cum production: 1.3 tcf (raw)

4.5% of rate additions 03-05

2.5% of production 03-05

Marginal economics?Reduced drilling activity in

80

60

70

90

70

80

60

50

90

Lloydminster

Edmonton

Hinton

Grande Prairie

Fort McMurray

Fort St. John

50

40

60

70

80

80

60

70

90

70

80

60

50

90

Lloydminster

Edmonton

Hinton

Grande Prairie

Fort McMurray

Fort St. John

50

40

60

70

80

80

60

70

90

70

80

60

50

90

Lloydminster

Edmonton

Hinton

Grande Prairie

Fort McMurray

Fort St. John

50

40

60

70

80

Milk River – Med Hat – 2WS

Cum production: 14 tcf (raw)

11% of rate additions 03-05

10% of production 03-05

Deep Basin tight gas

Cum production: 17 tcf (raw)

21.5% of rate additions 03-05

Reduced drilling activity in CBM, shallow gas and the

Jean Marie plays in 2006-07

2049°N

20

1

10

30

40

Swift Current

Saskatoon

Calgary


20

30

10

1

49°N

20

1

10

30

40

Swift Current

Saskatoon

Calgary


20

30

10

1

49°N

20

1

10

30

40

Swift Current

Saskatoon

Calgary


20

30

10

1

Wells Onstream to 2005, Production to Feb 2007

Western Canada Tight Gas

Tight Gas RegionsCumulative Raw Gas per Township, Bcf

0 100 200 km

0 50 100 miles

% p15% of production 03-05



11

Illustrative long term supply outlook for Canada

16

18

20

22 LNG Imports BC

LNG Imports Que

LNG Import EastCoastNewfoundland

Natural Gas Production Outlook – Continuing Trends Scenario • Continuing Trends preliminary scenario

• Decline of WCSB ti l &

2

4

6

8

10

12

14

16

Bcf

/d

Nova Scotia Deep

Panuke

Sable &SurroundingsMackenzie

WCSB Shale

WCSB Tight

WCSB MV CBM

WCSB HC CBM

WCSB Additions

WCSB Non Assoc

conventional & limited replacement

• Unconventional from WCSB grows

• Mackenzie onstream i 2012 E t C t

21Unconventional, Mackenzie and LNG required

02004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

WCSB Solution

Source: National Energy Board, Consultations on Preliminary Results February 2007

in 2012, East Coast LNG earlier

Base case assumes business as usual, 2.8% economic growthAssumes gas price of $7/mcf US Henry Hub

• Gas consumption increases in medium term until electrical switches to coal

Long term supply/demand outlook for United States

US Natural Gas Production, Consumption and Imports

24

26

28

Consumption

LNG Imports

Projections

• US gas production grows despite recent declines in Gulf

• Pipeline imports from Canada decrease

12

14

16

18

20

22

Tcf

Pipeline Imports (Canada)

Dry Gas Production

22Greenhouse gas policies would limit new coal generation

• LNG is plug number to meet consumption

Base case assumes policy neutral: no carbon taxes affecting coalForecasts prices of $5-$6/mcf Henry Hub ($US 2005) over period

102005 2010 2015 2020 2025 2030

Source: EIA



12

8

10

Lower 48 Non-Associated Unconventional

ProjectionsHistory

Natural Gas Production by Source, 1990-2030trillion cubic feet

US Dry Gas Production base case• Unconventional

growth is slower, gas shales growing

Sh t t

0

2

4

6

Alaska

Lower 48 Non-Associated Offshore

Lower 48Associated-Dissolved

Lower 48 Non-Associated Conventional Onshore

• Short-term production hiccup

• Reverse declines in Gulf of Mexico by tying in Deepwater oil and gas fields

23

01990 1995 2000 2005 2010 2015 2020 2025 2030

EIA AEO 2007

A generous production forecast

• Assumes Alaska pipeline in 2018

Actual US production flat despite record onshore drillingGulf of Mexico offshore production declining – not just hurricanes!

LNG Supply

24Unconventional largest single source of supply



13

Will We Have the Right Stuff?

• Challenge to sustain production profitably in WCSB– More feet drilled for less gas production and reserves– Supply costs and F&D costs are increasing– Uncompetitive costs and economics for WCSB gas projects will

reduce reinvestment

• Unconventional gas, Mackenzie and LNG – Will be required to replace declining WCSB output– Project economics are challenging, supply timing uncertain

25

• US production is forecast not to meet consumption

• LNG will be the swing source for North America

Yes . . . but volatile supply won’t be cheap!

Will We Have the Right Stuff?Will We Have the Right Stuff?

Current and Future Natural Gas SupplyCurrent and Future Natural Gas Supply as Feedstock

[email protected]

CERI Petrochemical ConferenceCERI Petrochemical ConferenceJune 4, 2007

Documents

Will We Have the Right Stuff? files 2009/Flint Forward... · 2000 1999 1998 1997 1996 1995 1994 1993 1992 1991 1990 Solution Gas 1 year 3.2 3.4 Bcfd Bcfd 1 year 60 °N 70 60 80 90