the future of canadian oil and gas exports - art berman€¦ · labyrinthconsulngservices,inc....

Labyrinth Consul4ng Services, Inc.

The Future of Canadian Oil and Gas Exports

Arthur E. Berman Labyrinth Consulting Services, Inc.

Middlefield Group Limited Calgary, Alberta July 10, 2014


The Future of Canadian Oil and Gas Exports •  A global context is essen4al to understand the export future of both heavy oil

and natural gas. •  LNG exports to Asia will be limited and will face increasing compe44on on price

and market-‐share. •  NEB: Considerable natural gas produc4on growth (32% by 2035) if LNG exports

materialize (3 Bcf/day by 2023 & 4.5 Bcf/day by 2035). More limited growth without exports.

•  Russia’s natural gas deal with China fundamentally alters the Asian LNG market. •  Keystone XL Pipeline reality changes every day but oil export to the U.S. will be

mostly by rail. •  Heavy oil development will proceed but short-‐ and medium-‐term capex will be a

challenge because of oil price, labor & service costs, and geographic constraints. •  Canadian energy companies paid a premium to enter the oil-‐prone core of the

Eagle Ford Shale play in south Texas.


A Global View of Natural Gas Proved Reserves

1,680&

1,168&

890&

305& 284& 265&215& 195& 180& 159& 147& 141& 112& 107& 85& 83& 77& 71& 65& 64& 61&

0&

200&

400&

600&

800&

1000&

1200&

1400&

1600&

1800&

Russia&

Iran&

Qatar&

United&States&

Saudi&Arabia&

Turkm

enistan&

UAE&

Venezuela&

Nigeria&

Algeria&

Europe&

Indonesia&

Iraq&

China&

Kazakhstan&

Malaysia&

Egypt&

Norway&

Uzbekistan&

Kuwait&

Canada&

Trillions(of(C

ubic(Feet(o

f(Gas(

Natural(Gas(Proved(Reserves(

Canada is 21st in the world for proven natural gas reserves: 3% of Russia, 20% of U.S.

Source: EIA


A Global View of Natural Gas Proved Reserves

Canada’s 61 Tcf of proven reserves make it a small player in the global market.


Canadian Gas Produc4on & Exports Declining

•  Gas produc4on is decreasing and consump4on is increasing. •  Surplus supply—produc4on minus consump4on—is down from 9.5 Bcf/day

in 2001 to 5 Bcf/day in 2013. •  Exports to the U.S. are down 3 Bcf/day since February 2008. •  Clearly, Canada must find other markets for its gas but what is the right

amount to export? How much commercial spare capacity is in Alberta and B.C.?

Source: BP

0"

2"

4"

6"

8"

10"

12"

Jan+1990"

Aug+1990"

Mar+1991"

Oct+1991"

May+1992"

Dec+19

92"

Jul+1

993"

Feb+1994"

Sep+1994"

Apr+1995"

Nov+1995"

Jun+1996"

Jan+1997"

Aug+1997"

Mar+1998"

Oct+1998"

May+1999"

Dec+19

99"

Jul+2

000"

Feb+2001"

Sep+2001"

Apr+2002"

Nov+2002"

Jun+2003"

Jan+2004"

Aug+2004"

Mar+2005"

Oct+2005"

May+2006"

Dec+20

06"

Jul+2

007"

Feb+2008"

Sep+2008"

Apr+2009"

Nov+2009"

Jun+2010"

Jan+2011"

Aug+2011"

Mar+2012"

Oct+2012"

May+2013"

Dec+20

13"

Billion

s'of'C

ubic'Feet'o

f'Gas'Per'Day'(1

29Mon

th'M

A)'

U.S.'Gas'Imports'From'Canada'

Gas$Imports$Down$3$Bcf/day$since$Feb$2008$

Source: BP

0"

2"

4"

6"

8"

10"

12"

14"

16"

18"

20"

1970"

1971"

1972"

1973"

1974"

1975"

1976"

1977"

1978"

1979"

1980"

1981"

1982"

1983"

1984"

1985"

1986"

1987"

1988"

1989"

1990"

1991"

1992"

1993"

1994"

1995"

1996"

1997"

1998"

1999"

2000"

2001"

2002"

2003"

2004"

2005"

2006"

2007"

2008"

2009"

2010"

2011"

2012"

2013"

Billion

s'of'C

ubic'Feet'o

f'Gas'Per'Day'

Canada"Natural"Gas"Produc:on"&"Consump:on"Produc:on" Consump:on" Surplus"

Surplus'Down''From'9.5'to'5'Bcf/d'


How Much Gas is Enough and What is the Fiscal Framework?

Plant Partners)(Interest) Location Status NEB)Application Mtpa Capacity)bcf/d Target Start?UpDouglas(Channel(LNG LNG(Partners((47.5%),(Haisla((27.5%),

Golar(LNG((25%)Kitimat,(BC Proposed Approved 0.7?1.8 0.1?0.2 2016

Kitimat(LNG Chevron((50%),(Apache((50%) Kitimat,(BC Proposed Approved 10 1.4 TBDPacific(NorthWest(LNG PETRONAS((77%),(JAPEX((10%),(Indian

Oil((10%),(PetroleumBRUNEI((3%)Prince(Rupert,(BC Proposed Approved 12?18 1.6?2.4 2019?20

LNG(Canada Shell((40%),(KOGAS((20%),Mitsubishi((20%),(PetroChina((20%)

Kitimat,(BC Proposed Approved 12?24 1.6?3.2 2020

Prince(Rupert(LNG BG(Group((100%) Prince(Rupert,(BC Proposed Approved 14?22 1.9?2.9 2020?21WCC(LNG ExxonMobil((50%),(Imperial(Oil((50%) TBD,(BC Proposed Approved 10?30 1.3?4.0 2021?23Woodfibre(LNG Pacific(Oil(&(Gas((100%) Squamish,(BC Proposed Approved 2.1 0.3 2017Triton(LNG AltaGas((50%),(Idemitsu((50%) TBD,(BC Proposed Pending 2.3 0.3 TBDKitsault(FLNG Kitsault(Energy((100%) Kitsault,(BC Proposed Pending 20 2.6 2018Goldboro(LNG Pieridae(Energy((100%) Goldboro,(NS Proposed Pending 10 1.3 2019?20Aurora(LNG CNOOC((60%),(INPEX((20%),(JGC((20%) Grassy(Point,(BC Proposed Pending 24 3.2 2021?23H\Energy H\Energy((100%) Melford,(NS Proposed \\ 4.5 0.6 2020Stewart(Energy(LNG Canada(Stewart(Energy(Group((100%) Stewart,(BC Proposed Pending 5?30 0.7?4.0 2017+Woodside Woodside(Petroleum Grassy(Point,(BC Proposed \\ ?? ?? ??

Approved 11.35Pending 10.40Total 21.75

•  Apparently the people gran4ng export approvals are not reading the NEB Energy Forecast 2013 for 3 Bcf/day of exports by 2023!

•  There is a lack of clarity about fiscal terms, safety & environmental standards, First Na4ons deals & conflict with oil pipeline plans.

•  Poten4al customers are not sympathe4c to arguments over B.C. export taxes.

Source: RBC Capital Markets


The Power Of Siberia Pipeline Changes Everything

•  Russia’s gas deal with China is largest in history: 1.4 Tcf over 30 years for $400 billion.

•  Sets a $10/MMBtu benchmark price for Asia without oil linkage. •  Gas agreement has far-‐reaching implica4ons for global LNG markets. •  Russia plans to be the leading supplier to Asian gas markets. •  Russia’s East Siberia proven reserves: 196 Tcf & 7 billion barrels of oil , 3-‐4mes

Canadian reserves and more than U.S. shale gas resources. •  This is only the beginning: pipelines to Korea & Japan are planned.

Source: Gazprom


Horn River Gas Supply Cost is a Barrier to Development & Export Economics

•  Well costs are $16-‐22 million depending on lateral length.

•  The gas is sour and has no liquids. •  Deep, over-‐pressured reservoirs: risk of

reservoir compac4on like Haynesville Shale—much reduced EURs from higher-‐than-‐modeled decline rates.

•  EURs are adver4sed at 15-‐35 Bcf/well depending on lateral length.

•  There are few conven4onal wells this good and never the average well. Ø  Average Haynesville Shale well is 4-‐5

Bcf. Ø  Best Marcellus wells in core are 8-‐10

Bcf. •  Based on $15 mm well cost, 15 mmcf/d

ini4al produc4on rate & 8% discount rate, break-‐even gas price is $7.25.

•  This includes $0.40 AECO discount to HH and $0.40/mcf sour gas processing charge.

Source: RBC Capital Markets


Montney Shale: Lower Supply Cost Because of Liquids But Export Economics are Marginal

Mix of Cretaceous and Montney Wells Example Montney Wells Only Example

Price200 MMcf/d x 15% Shrinkage=170 MMcf/d (28,333 Boe/d) Sales Gas100 Bbl/MMcf: 20,000 Bbl/d NGLs

200 MMcf/d x 23% Shrinkage=154 MMcf/d (25,667 Boe/d) Sales Gas150 Bbl/MMcf: ~30,000 Bbl/d NGLs

Deep-Cut Rich Gas $3.00/Mcf 170 MMcf/d $510,000 154 MMcf/d $462,000

Condensate $100.00/Bbl 8,000 Bbl/d $800,000 12,400 Bbl/d $1,240,000

Butane $65.00/Bbl 2,000 Bbl/d $130,000 2,500 Bbl/d $162,500

Propane $35.00/Bbl 4,000 Bbl/d $140,000 5,000 Bbl/d $175,000

Ethane $12.00/Bbl 6,000 Bbl/d $72,000 10,480 Bbl/d $125,760

Total: 48,333 Boe/d $1,652,000/day 56,047 Boe/d $2,165,260/day

Royalty 5% ($82,600/day) 5% ($108,260/day)

Operating Cost ($0.50/mcf) ($85,000/day) ($0.50/mcf) ($77,000/day)

Total: 17.6 MMBoe/year

$1,484,400/day$542 MM/year

$30.78/Boe

20.5 MMBoe/year

$1,980,000/day$723 MM/year

$35.25/Boe

22

Illustrative Deep-Cut

•  Considerable condensate yield pushes supply cost lower: 80 BPM (12,500 GOR). •  NGL uplim adds to lower supply cost.

Source: Paramount Resources Source: RBC Capital Markets


The Economics of North American LNG Export

•  Model uses RBC Capital Market data with updated gas price ($4.30 HH and $0.40 AECO discount) and modified Horn River supply cost.

•  Horn River not feasible because of high supply cost. •  Montney has lower supply cost but greenfield construc4on pushes break-‐even above $10

benchmark set by Russia-‐China pipeline deal. •  Haynesville brownfield project not feasible because of supply: Haynesville produc4on is 4.2

Bcf/day below its peak because of economics (high drilling cost). •  U.S. Gulf Coast brownfield projects slightly more aorac4ve than Montney because of

disintegrated nature of components. •  Both Montney and U.S. Gulf Coast will struggle to compete with $10 gas in Asia. •  Liquefac4on projects are notorious for delays, cost over-‐runs and lower-‐than-‐planned capacity.

Source: RBC Capital Markets & NGI Shale Daily

$7.00%

$4.70% $4.80% $4.30%

$2.50%

$2.31%$3.26%

$2.33%

$5.00%

$4.82% $2.88%

$3.50%

$0%

$2%

$4%

$6%

$8%

$10%

$12%

$14%

$16%

Horn%River%Ki6mat%(Greenfield)%

Montney%(Greenfield)% Haynesville%(Brownfield)% U.S.%Gulf%Coast%(Brownfield)%

Land

ed&Costs&in&Ja

pan&

Break1Even&North&American&LNG&Project&Costs&

Liquefac6on%

Processing%&%Transporta6on%

Upstream%Cost%


•  The Na4onal Energy Board predicts that conven4onal gas will account for only 6% of produc4on by 2035, with 4ght gas making up 62% and shale gas 28%.

•  Total gas produc4on will increase 32% from 13.2 to 17.4 Bcf/day by 2035 amer falling to 12.2 Bcf/day in 2016.

•  Biggest increase will be 5.8 Bcf/day in the Montney with most of increase in B.C. •  Horn River will increase 3.3 Bdf/day although supply cost is a big issue. •  Consump4on will rise from 10 Bcf/day in 2013 to 12.9 Bcf/day in 2035, leaving 4.5 Bcf/day for

export. NEB high case for export is 10.7 Bcf/day. •  Ziff predicts 19 Bcf/day by 2022 assuming 5.7 Bcf/day of LNG exports beginning in 2019, but

no growth without exports. •  Ziff also sees more gas from Montney (7-‐8 Bdf/d) and Duvernay (2-‐3 Bcf/d) but less from Horn

River (2 Bcf/d) at least by 2022.

NEB Natural Gas Produc4on Forecast

Source: NEB Source: NEB

Bcf/Day 2013 2013 Growth2%B.C.$Montney 1.60 6.10 281%AB$Montney 0.30 1.60 433%Total2Montney 1.90 7.70 305%AB$Deep$Basin 2.50 2.60 4%Horn$River 0.30 3.60 1100%Duvernay ? 0.61Cordova ? 0.24Liard ? 0.23CBM 0.70 0.20 ?71%WCSB 6.17 1.62 ?74%Associated$Gas 1.60 0.60 ?63%Other 0.03 0.00 ?99%TOTAL 13.20 17.40 32%


Alberta Heavy Oil and Keystone XL Pipeline

•  Spending delays and job cuts as costs rise and companies seek ways to make projects more profitable.

•  Keystone XL Pipeline reality changes daily because approval is a poli4cal issue in the U.S. At this moment, it appears unlikely that the project will be approved under Obama.

•  Other op4ons include rail and Mainline Pipeline to eastern Canada refineries.


"EssenBally, for a company like mine and many others, $100 a barrel is becoming the new $20 in our business." -‐-‐John Watson, Chevron CEO

3/7/14 Oil companies feel a pinch as their expenses swell - Houston Chronicle

www.houstonchronicle.com/business/energy/article/Oil-companies-feel-a-pinch-as-their-expenses-swell-5289696.php#/0 1/2

ENERGY

By Zain Shauk

Oil companies feel a pinch as their expenses swell

Chevron chief says labor and capital costs have doubled in last decade

Mayra Beltran, Staff

Chevron CEO John Watson is a keynote speaker during CERA Week at the Hilton Americas on March4, 2014, in Houston. ( Mayra Beltran / Houston Chronicle )

March 4, 2014 | Updated: March 4, 2014 11:12pm

Rising labor and capital costs are challenging oil companies, even as oil prices hover at $100 abarrel or more, executives said Tuesday on the first full day of the IHS Energy CERAWeeksummit in Houston.

To continue reading this story, you will need to be a digital subscriber toHoustonChronicle.com.

Capex Compression: Some Companies Are Postponing Heavy Oil Investment

•  E&P costs rising faster than revenues: capex consumed 2/3 of revenue in Q1 2014 (Bernstein). •  Companies struggling to replace reserves—re-‐focus on ROCE leads to investment in shorter-‐

term projects. •  $10/boe downward price would move the industry into nega4ve margins. •  Margins are flat at best despite the “good news” about shale plays.

50

Listing Oil Majors: Capex and Crude Oil Production

• Capex flattening this year

• Cash flow growth over production growth

• Implies unraveling

Historical and Forecast Crude Oil Production and Capex (Provisional, subject to Revision) Combined data for BG, BP, COP, CVX, ENI, OXY, PBR, RDS, STO, TOT, XOM

Source: Bloomberg via Phibro Trading LLC

8

9

10

11

12

13

14

15

16

17

$0

$50

$100

$150

$200

$250

$300

mbp

d cr

ude

oil p

rodu

ctio

n

US

$ bi

llion

s

Capex (l)

Forecast Capex

Oil Production (r)

Forecast Production

41

• The vast majority of public oil & gas companies require oil prices of over $100/bbl to achieve positive free cash flow under current capex and dividend programs

• Nearly half of the industry needs more than $120/bb. The 4th quartile, where most US E&Ps cluster, needs $130/bbl or more.

Source: Goldman Sachs Oil Price Required by Oil Companies to be Free Cash Flow Neutral After Capex and Dividends

The Industry Needs $100+ Oil Prices

Source: Douglas-‐Westwood Source: Douglas-‐Westwood


The Global Context For Oil Sand Investment

Source: Hyperdynamics

0%#

5%#

10%#

15%#

20%#

25%#

30%#

35%#

40%#

45%#

50%#

0#

20000#

40000#

60000#

80000#

100000#

120000#

2000# 2005# 2010# 2015# 2020# 2025# 2030#

Conven0onal#

Unconven0onal#and#deepwater#

Total#

Percent#Unconven0onal#and#deepwater#

•  Deep water (and 4ght oil) produc4on will sustain global oil supply through the mid-‐2020s as conven4onal oil produc4on declines.

•  Then, heavy oil will be essen4al as deep-‐water produc4on declines.


0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2000 2005 2010 2015 2020 2025 2030

GOM Deepwater Brazil Deepwater

OPEC Deepwater Other Non OPEC DW

Total Deepwater


0

1

2

3

4

5

6

7

2000 2005 2010 2015 2020 2025 2030

Venezuela Canada ROW Total

The Global Context For Oil Sand Investment


Heavy Oil and Bitumen in Place (BBO) World Energy Council 2007

Venezuela 2250

Canada 1600

Rest of World 800


•  Produc4on reaches 7 MMbo/day in 2030. •  85% of resources in two provinces: Canada and Venezuela. •  High oil prices needed for profitability. •  Limits on produc4on not resources, but commercial environment is nega4ve in

Venezuela, and there are significant infrastructure, geographic, environmental and labor constraints in Canada.

•  Heaviest environmental footprint (surface imprint, CO2 emission, water use) of all unconven4onal produc4on.

•  Beoer commercial environment in Canada vs. Venezuela gives Canada advantage despite beoer reservoir and oil quality in Venezuela.


Economic Commentary

Vol 8 No 11, November 2013

�

©�Arab�Petroleum�Investments�Corporation��Page�3/3��Comments�or�feedback�to:�aaissaoui@apicorpͲarabia.com�

Figure�7:�5Ͳyear�MENA�Energy�Investment,�2014Ͳ2018��

0 30 60 90 120 150 180

MauritaniaYemenSyria

JordanSudan�*Tunisia

LebanonMoroccoBahrainOmanEgyptLibya

KuwaitQatarIranIraq

AlgeriaUAE

Saudi�Arabia

US$�billion

2013Ͳ17�Review

2014Ͳ18�Review

APICORP�Research�using�internal�database*�Sudan:�North�&�South

�9.�Despite�greater�uncertainty�in�the�outlook�of�production�from�new� regions,� MENA� is� expected� to� keep� its� pivotal� role� in�supplying�global�markets�with�oil�and�to�a� lesser�extent�natural�gas.� When� factoring� in� growth� of� domestic� renewables� and�nuclear,�the�region’s�total�energy� investment�could�build�up�to�$3.9� trillion� (in� dollars� of� the� year� 2012),� representing� a� little�more� than�10%�of� global�energy� investment� through� to�2035.�However,� in� the� context� of� lingering� political� turmoil,� the�region’s� medium� term� investment� (Figure� 7)� faces� many�challenges,�including:��x A�poor�and�deteriorating�investment�climate�as�is�the�case�

of�the�soͲcalled�‘Arab�Spring’�countries�and�Iraq;��x Conservative� depletion� policies� as� is� the� case� of� Qatar’s�

moratorium�on�further�development�of�the�North�Field;�x Tougher�economic�sanctions�on�the�region’s�biggest�holder�

of�combined�oil�and�gas�reserves,�ie�Iran;�x Durable� loss� of� production� due� to� armed� conflict� and�

resulting�damage�to�infrastructure,�as�is�the�case�of�Syria;�x Last�but�far�from� least,� is�a�serious�constraint�on�financing�

across�countries.��

Figure�8:�MENA�Energy�Capital�Structure�and�Financing��

UpstreamC�=�$222bnL�=�0:100 Aggregate�

capital�required�and�

capital�structure�C�=�765bnL�=�43:57

Retained�earnings

APICORP�Research

Medium�and�long�term�loans

Bonds�or�sukuks

Common�stocks

State�budget

allocationDownstreamC�=�$227bnL�=�60:40

MidstreamC�=�$38bnL�=�0:100

Power��GenerationC�=�$278bnL�=�70:30

F I N A N C I N G(Conceptual)

Intern

al�sour

ces

Capit

al�req

uired

Extern

al�sour

ces�

Resu l t i ng � cap i ta l �requ i rement s � (C )

and � l e ve rage �( L =D : E )

I N V E S T I N G(Empirical)

�

10.� I� wish� I� could� have�more� time� to� delve� deeper� into� the�financing� constraint.� Let�me� just� say� that� financing� is� at� the�heart� of� corporate� strategies� and� investment� decisions.� It� is�basically� determined� by� the� structure� of� capital� requirement,�which�we�have�established�to�be�43%�debt�and�57%�equity� for�MENA�energy�investment�as�a�whole�(Figure�8).�Debt,�which�is�a�dominant� feature� of� the� downstream� industry,� is� sourced�externally.�With�still�limited�opportunities�for�raising�funds�from�the� capital� markets� debt� is� typically� provided� through� the�region’s�bank�loan�market.�As�most�European�banks�have�pulled�out�in�the�wake�of�the�Eurozone�debt�crisis,�this�market�has�yet�to� recover.� Surely,� export� credit� agencies� (ECAs)� and� local�commercial�banks�have�stepped�in;�but�they�could�hardly�fill�the�gap.� In� contrast,� internal� financing� is� a� dominant� part� of� the�upstream� and� midstream� sectors.� It� has� been� more� easily�provided� through� retained� earnings� and� state� budget�allocations,�thanks�to�sustained�high�oil�prices.��

Figure�9:�Fiscal�BreakͲeven�Oil�Prices�and�Fiscal�Cost�Curve��

0

25

50

75

100

125

150

175

200

0 5 10 15 20 25 30 35

Fiscal�breakͲeven�price

�(S/bbl)

Cumulative�petroleum�production�(mbd)

QAT KUW

ANG UAE

SAU VE

N

LIB

IRQ

ALG

NIG

ECU

IRN

Upward�fiscal�cost�curve

Down�pressure�on�oil�prices

��

11.�We�have� established� that� internal� financing� can�hardly�be�secured�for�key�MENA�countries�if�the�value�of�the�OPEC�basket�of�crudes�falls�durably�below�$105/bbl.�This�level�corresponds�to�APICORP’s� estimated� OPEC� outputͲweighted� average� fiscal�breakͲeven�price�for�2013.1�Let�me�take�a�few�more�moments�to�explain� Figure� 9.� Since� a� fiscal� breakͲeven� oil� price� can� be�interpreted� as� a� cost,� a� fiscal� cost� curve� can� be� drawn.� A�reasonable� approximation� to� such� a� curve� is� obtained� by�ranking�each�country’s�petroleum�output,�from�lowest�to�higher�costs.�Because� it� is�a�fixed�cost,�a�fiscal�breakeven�price�cannot�be� interpreted�as�a� reservation�price:�no�OPEC� country�would�likely�withhold�production�until� its� ‘preferred�price’� is�met.�The�likelihood� is� that�market�prices�risk�receding�on� lower�demand�for�OPEC�oil�and�resulting�higher�spare�capacity.�In�this�respect,�three�OPECͲrelated� factors�are� likely� to�dominate� the�outlook:�Iran's�ability�to�solve� its�nuclear� impasse,�Iraq’s�push�for�higher�production� and� OPEC’s� capacity� to� close� ranks� in� time� of�predicament.� Beyond� OPEC,� as� unconventional� technologies�mature�and�their�costs�decline,�oil�prices�will�likely�come�under�greater�pressure.�The�risks�facing�OPEC�and�MENA�oilͲproducing�countries�now�and� then�will�differ�depending�on� their�position�on� the� fiscal� cost� curve.� The� higher� their� fiscal� cost� the� less�money�will�be�left�to�invest�in�the�energy�sector.��

12.�With�this�challenging�concern� in�mind,� it� is�time�to�sum�up�and� conclude� our� assessment� of� the� changing� global� energy�landscape� and� its� implications� for� MENA� investment.� Amid�major� shifts� in� the�patterns�of�global�demand�and� supply,� the�region� is�expected� to�compete�with�emerging�production� from�other�sources�and�areas�to�provide�the�bulk�of� increment� in�oil�supply� and� still� a� large� amount� of� natural� gas.� This� involves�investment� of� some� $160bn� per� year� (in� dollars� of� the� year�2012).�It�is�far�from�certain�that�such�levels�of�investment�will�be�forthcoming� in� the�medium� term.� The� causes� for� delay� have�become�more�serious�as�a�result�of�a� longͲlasting�deterioration�of� the� investment� climate� in�most� parts� of� the� region.�At� the�same� time,� and� as� far� as� funding� is� concerned,� two� opposing�forces�in�tension�with�one�another�will�drive�the�availability�and�cost�of�internal�financing.�On�the�one�hand,�a�relentless�upward�fiscal� cost� curve,�on� the�other�hand�an�anticipated�downward�pressure�on�oil�prices.�

1�Ali�Aissaoui,�“Modeling�OPEC�Fiscal�BreakͲeven�Oil�Prices:�New�Findings�and�Policy�Insights’,�APICORP’s�Economic�Commentary,�SeptemberͲOctober�2013.�

•  Conven4onal producers need $100/bbl. oil to balance budgets. •  Unconven4onal producers need $100/bbl. oil to make a profit. •  Delays in heavy oil development will increase prices in the longer

term.

Source: APICORP Research

Oil Prices Will Probably Remain High Enough To Fund Heavy Oil Projects


0"

20"

40"

60"

80"

100"

120"

8.7" 12.8"4.1"3.5"Deepwater"

Shale""Oil"

Heavy""Oil" NGL"

MMBopd


Two Contras+ng Decades

•  Produc4on increase 8 MMBOD. •  Conven4onal produc4on decline. •  Major produc4on increase in

deep-‐water and unconven4onal plays.

•  Stable oil price at $100/bbl. (2012 dollars).

•  Produc4on increase only 3 MMBOD. •  Conven4onal produc4on decline except

certain areas. •  Deep-‐water and US shale oil produc4on

plateau and decline. •  USA produc4on in decline.

2010-‐2020 2020-‐2030

Choices to be Faced Around 2020

Accelerated heavy oil and fracking

Return to Arabian Basin Emphasis on natural gas and

renewables

Higher oil prices

A View of the Future For Oil Supply


NEB Heavy Oil Produc4on Forecast

•  The Na4onal Energy Board forecasts 5 MMbopd produc4on of heavy oil by 2035.

•  This represents a 2.6-‐fold increase compared to 2012 produc4on. •  2025-‐2015 annual growth rate will be 3% for in-‐situ and 1% for mining projects. •  3.4 Bcf/day of natural gas used for extrac4on, upgrading and co-‐genera4on by

2035.

Source: NEB


Encana and Baytex Enter the Eagle Ford Play

From EOG Investor PresentaBon, 2010

Source: HPDI

•  Produc4on began in 2008 by Petrohawk (BHP). •  Reservoir is Cretaceous oil source rock that charged

overlying Aus4n Chalk and underlying Woodbine Sandstone in East Texas. It is a mixed carbonate-‐clas4c reservoir.

•  Core areas related to fracturing on structural highs. •  Oil produc4on may be flaoening. Gas produc4on is flat. •  Rig count is 195 dominated by EOG, Marathon,

Chesapeake and BHP.


Shale Oil Plays – Calcula4on of Breakeven EUR/well at $95/bbl WTI

Oil Play Breakeven EUR ValuesEagle Ford Bakken

Royalty 25.0% 20.0%Drilling and Completion Well Cost, $MM/well $8.50 $9.00Tie In Cost, $MM/well $0.25 $0.50Expense, LOE+Gath.+Tax+G&A, $/BOE $16.00 $20.00Price Differential to WTI -‐$5.00 -‐$10.00

Breakeven EUR/well for 8% Return @ $95/BOE WTI, MBOE 217 353

EUR/12-‐Month Cumulative Production Ratio

3.0 for western counties, 2.2 for eastern counties 4.74

12-‐Month Cutoff, MBOE @ $95/bbl WTI72 MBOE West, 99 MBOE East 74

For Eagle Ford, Western Counties = Webb, Dimmit and LaSalle Eastern Counties = Karnes, Dewitt, McMullen, Gonzales, Live Oak and AtascosaBOE converted on economic value basis of each product and typical condensate and NGL yields

Land Costs Not Included All Opera+ng Costs Included

(Drilling These Wells IS the Operator’s Main Business They Are Not an Incremental Add On)


Impact of NGL Assump4ons on BOE Values

85 BCPD2,143 Mscfd gross gasVery Gassy = 25,000 scf/bbl Gas Oil Ratio (GOR)

Full Ethane Reovery BOE 6:1 BOE on Economic Basis

Assuming NGL Processing Yielding 100 BPM, 22% Shrinkage

Assuming No NGL Processing

Assumes NGL Processing at 40 BPM Yield, 12% shrinkage

85 BCPD 85 BCPD 85 BCPD214 BPD NGL (Roughly Half Ethane) 2,143 Mscfd gross gas 2,143 Mscfd gross gas

1,672 Mscfd incl shrinkage

578 BOEPD at 6:1 442 BOEPD at 6:1 200 BOEPD at 18.7:1Assumes $4/MMBtu

Very Gassy, Yet Operators Express Test Rates in BOE (6:1)

And Assume Full Ethane Recovery (despite very depressed ethane prices) 65% Lower

Mean Utica Well Rate 3Q 2013

Than Full Ethane Recovery


High Decline Rates in Oil-‐Prone Eagle Ford: 220,000 BOE Break-‐even Threshold

Source: HPDI


Eagle Ford Decline Curve Analysis Results By County and Year of Comple4on

GOR EUR 12-Mo Cum EUR/12 Mo. Cum Peak Rate WellCounty/Year Completion Cumulative Remaining EUR Cumulative Remaining EUR scf/bbl MBOE Econ MBOE Econ Ratio BOE/day Count

Karnes 2010 124.5 38.6 163.1 690.7 283.8 974.5 5,975 224 117 1.9 532 50Karnes 2011 142.4 70.3 212.7 501.9 260.4 762.3 3,584 260 131 2.0 562 130Karnes 2012 109.7 88.9 198.6 343.4 341.1 684.5 3,447 241 125 1.9 604 243Avg all yrs 137 61 199 554 267 821 4,248 250 127 2.0 553.5Dewitt 2010 221.3 126.5 347.8 1,191.4 748.7 1,940.1 5,578 469 184 2.6 822 31Dewitt 2011 178.7 118.5 297.2 994.5 827.7 1,822.2 6,131 411 170 2.4 729 131Dewitt 2012 141.0 211.2 352.2 621.6 1,085.8 1,707.4 4,848 459 645 203Avg all yrs 187 120 307 1,032 813 1,845 6,025 422 173 2.4 746.9

Dimmit 2010 123.0 100.2 223.2 803.5 685.0 1,488.5 6,669 316 90 3.5 335 39Dimmit 2011 69.5 85.4 154.9 419.2 533.0 952.2 6,147 214 59 3.6 220 181Dimmit 2012 54.1 93.1 147.2 273.5 612.6 886.1 6,020 203 71 2.8 275 346Avg all yrs 79 88 167 487 560 1,047 6,240 232 65 3.6 240.4

LaSalle 2010 35.5 10.0 45.5 1,143.8 1,496.9 2,640.7 58,037 211 63 3.4 333 45LaSalle 2011 39.8 23.6 63.4 965.6 1,224.1 2,189.7 34,538 200 70 2.9 300 80LaSalle 2012 56.3 68.1 124.4 319.6 840.4 1,160.0 9,325 197 76 2.6 348 221Avg all yrs 38 19 57 1,030 1,322 2,352 42,998 204 67 3.0 311.8Webb 2010 54.7 28.8 83.5 1,598.6 1,887.6 3,486.2 41,751 301 82 3.7 357 101Webb 2011 45.2 38.8 84.0 1,108.2 1,524.4 2,632.6 31,340 249 77 3.2 349 234Webb 2012 28.6 32.2 60.8 788.7 1,672.9 2,461.6 40,487 215 74 2.9 366 272Avg all yrs 48 36 84 1,256 1,634 2,890 34,479 264 79 3.4 351.6

McMullen 2010 67.9 22.6 90.5 835.3 370.1 1,205.4 13,319 166 75 2.2 445 22McMullen 2011 61.8 31.8 93.6 717.4 505.6 1,223.0 13,066 170 82 2.1 417 52McMullen 2012 56.7 59.1 115.8 384.6 402.6 787.2 6,798 165 430 137

Avg all yrs 64 29 93 752 465 1,218 13,141 169 80 2.1 425.2Gonzales 2010 90.6 18.0 108.6 65.9 2.0 67.9 625 113 76 1.5 556 13Gonzales 2011 67.5 29.4 96.9 45.8 2.0 47.8 493 100 53 1.9 279 21Gonzales 2012 71.7 50.8 122.5 54.1 13.1 67.2 549 127 72 1.8 399 55

Avg all yrs 76 25 101 53 2 55 544 105 62 1.7 385.2Live Oak 2010 119.0 72.5 191.5 1,230.0 668.4 1,898.4 9,913.3 310 124 2.5 717 14Live Oak 2011 127.2 97.4 224.6 528.7 305.0 833.7 3,711.9 277 122 2.3 602 84Live Oak 2012 64.9 158.3 223.2 489.4 698.8 1,188.2 5,323.5 297 424 90

Avg all yrs 126 94 220 629 357 986 4,598 281 122 2.3 618.1Atascosa 2010 78.8 43.1 121.9 55.6 0.0 55.6 456.1 125 56 2.2 301 7Atascosa 2011 73.0 59.8 132.8 72.4 9.4 81.8 616.0 138 61 2.2 311 37Atascosa 2012 64.8 80.9 145.7 48.3 20.0 68.3 468.8 150 62 2.4 304 54

Avg all yrs 74 57 131 70 8 78 591 136 61 2.2 309.2

Weighted Average = 248 77 2.3 427

Oil, Mbbls Gas, MMscf

Source: HPDI

•  Dewio and Karnes coun4es have best well economics and well performance.

•  This is where Encana and Baytex entered the play.


Encana-‐Baytex Eagle Ford Acreage

Baytex

Encana

•  Encana paid $68,000 per acre: $3.5 billion for 45,500 acres.

•  Baytex paid $115,000 per acre: $2.6 billion for 22,200 acres.

Eagle Ford Shale 6-‐Month Oil CumulaBve ProducBon. Source: HPDI

Eagle&Ford&$95&Case Area&(acres) WellsMain&&Core 1,282,713 3,846Drilled&Play&Area 6,872,695 7,991Percent&Commercial 19% 48%


Eagle Ford Performance By Operator

Source: HPDI

EAGLE%FORD%PERFORMANCE%BY%OPERATOROperator Average%EUR%(BOE) Number%of%Wells EUR/Cutoff%@%$95Geosouthern%(DVN) 417,767 143 193%Marathon 186,870 177 186%EOG 400,000 373 184%Rosetta 348,325 105 161%Pioneer 285,130 177 131%Burlington%(COP) 266,833 292 123%SM 232,832 136 107%Petrohawk%(BHP) 228,125 124 105%Chesapeake 220,069 323 101%Anadarko 197,176 414 91%FMM%(Encana) 190,790 56 88%Talisman 182,700 90 84%Lewis 174,719 82 81%Shell 157,710 53 73%

•  Encana’s acquisi4on not currently commercial. •  Baytex’s posi4on looks worse. •  Why the disconnect? overly-‐op4mis4c EURs based on flaoer decline rates, boe

conversion based on energy content vs. economic value of gas, NGL uplim too op4mis4c because of full-‐ethane recovery?

•  Economics that do not fully account for opera4ng costs and realized price differen4als.


Dimmit County Example of Poor Well Performance: Well Spacing Too Tight?

Source: HPDI

•  Well performance indicates that closely spaced laterals are not commercial while more widely spaced laterals by the same operator are.

•  Shale producers announce reduced spacing as a celebra4on. •  When did more capex become beoer than less capex for the same reserves? •  The same investor exuberance that values huge acreage posi4ons that are mostly

not commercial cannot be drilled during the lease term.


Eagle Ford Well-‐Spacing

•  Assump4ons are difficult to assess, most cri4cal data is

proprietary. •  Industry discusses spacing as 4ght as 40 ac/well (~330 m

between laterals, 16 wells per square mile): Ø  Most likely too much interference between wells.

•  From our experience, we es4mate final op4mum well spacing to be in range of 80-‐120 ac/well (~660 – 990 m between laterals, 6-‐8 wells per square mile).

•  Industry is likely to be aggressive, so our two scenarios assume 60 & 90 ac/well.

•  Depic+on of how monitoring micro-‐seismic events are used to determine op+mum well spacing.

•  More overlap of fracture ac+vity likely to cause too much interference between wells.

•  Fracture events in this well show significant overlap at 750 T. spacing (~90 ac/well)

From Inamdar, A. et al, EvaluaBon of SBmulaBon Techniques Using Microseismic Mapping in the Eagle Ford Shale, SPE 136873


Eagle Ford Development Scenarios

Scenario 1: Current Rig Count •  180 rig count. •  Final well spacing = 90 acre/

well. •  10,700 wells remain to be

drilled. •  4.5 years of steady ac4vity

before ramp down.

Scenario 2: Slow Decline in Rig Count •  Rig count declines from 180

to 150 over four years, steady thereamer.

•  Final well spacing = 60 acre/well.

•  15,100 wells remain to be drilled.

•  7.3 years of slowly declining ac4vity before ramp down.

Both scenarios assume addiBonal wells beyond full development calculaBon drilled in ramp down phase

(over-‐development or poor investments)


Conclusions •  LNG exports to Asia will be limited and will face increasing compe44on on price and

market-‐share. Montney more aorac4ve than Horn River for export but projects will not be profitable based on current cost & price assump4ons.

•  Limited exports will limit natural gas produc4on growth—less Montney growth without significant export volumes and possibly no Horn River growth without meaningful price increase or cost reduc4on.

•  Keystone XL Pipeline approval not likely under Obama (or Clinton). •  Heavy oil growth and development will proceed because of global supply and price

factors. •  Canadian energy companies paid a premium to enter currently under-‐performing areas

of the Eagle Ford Shale play in south Texas. •  It’s hard to make money on fundamentals in the oil patch: how can everyone win when

they are all doing the same thing?

the future of canadian oil and gas exports - art berman€¦ · labyrinthconsulngservices,inc....

Documents