Developing Emerging International Shale Plays

Developing Emerging International Shale Plays

Supply Chain Challenges & Constraints

IAPG Congreso Latinamericano y del Caribe

Buenos Aires, Argentina

9 August 2012

Alexander Robart arobart@pacwestcp.com

+1 434 294 1396

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PacWest Consulting Partners

920 Memorial City Way, Suite 160

Houston, TX 77024

IAPG CONGRESO PRESENTATION

Agenda

1) Introduction

2) North American Market Update

3) Supply Chain & Infrastructure Constraints

4) International Unconventional Development

5) US Analogue: Bakken

6) Questions

© PacWest 2011 | All rights reserved | 2


PacWest is a boutique strategy consultancy and market intel firm specializing in energy, industrial, resources; strength in the oilfield

PacWest Overview & Capabilities

Consulting & Advisory

 Provide strategy consulting and

advisory services to energy, industrial, and resources clients

Market Intelligence Products

 Offer industry-leading, granular analysis of the oilfield

 Deep knowledge and strength in the pressure pumping / frac market  Strength in the oilfield supply market

Often work with E&Ps or suppliers across range of industries that supply products/services to it

 Employ combination of primary intelligence + secondary research

 Generally work at C-Level or business lead level

 Unique in market: apply strategy consulting capabilities to turn research into actionable intelligence

All key staff come from top-tier strategy firms; consulting and market intelligence capabilities reinforce/inform each other



PacWest currently offers multiple oilfield market intelligence product offerings to support subscriber decision-making

PacWest Market Intelligence Product Offerings

Product Description

Breakdown of pressure pumping fleets/capacity by basin and supplier with strategic analysis of latest regional supply market trends

Interactive database of 100+ critical unconventional suppliers

Cost escalation forecast for major D&C categories

Stripped-down version of PumpingIQ: regional frac fleet/capacity counts, by pumper, and other key data points from PumpingIQ

Database of fracs including basin, operator, pumper, chemicals, chemical suppliers

Adding international coverage to PumpingIQ in upcoming quarterly release



Agenda

1) Introduction





6) Questions



There are dozens of active plays in the US, but majority of activity has shifted to a handful of key oil/liquids-rich plays

Today’s US Hot Spots: Oil/Liquids-rich

Bakken

DJ Basin/Niobrara

Granite Wash

Permian Basin

Source: PacWest

Eagle Ford



The dramatic shift to oil/liquids plays over the last three years is highly visible in the US Land rig count

US Rig Count, Oil/Gas Split

100,0%

% Gas

% Oil

90,0%

80,0%

70,0%

60,0%

50,0%

Gas rigs down

40,0%

30,0%

Oil rigs up!!

20,0%

10,0%

0,0%

Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12

Source: Baker Hughes Rig Counts, PacWest Analysis



16

14

12

10

8

Frac supply has lagged behind demand, but we expect capacity to increase by 16.5% over 2012 to 15.5MM HHP at year-end

US Frac Supply

Frac Capacity (11Q3-12Q4)

Analysis Dated May 2012

Comments

■ Frac capacity additions have lagged pressure pumping demand increases until recently, but supply in 2012 has expanded much more quickly than demand

■ We expect frac capacity to increase by 2.2 million HHP over the course of 2012, for a total EOY frac capacity of 15.5 million HHP, an 16.5% increase on EOY2011

6

4

2

0

11Q3 11Q4 12Q1 12Q2 12Q3 12Q4



There has been a massive redeployment of capacity from key gas plays

(-1.1MM HHP) to liquids plays (+3.3MM HHP)

US Frac Capacity Outlook Analysis Dated May 2012

Frac Capacity in Key Gas Plays (11Q3-12Q4) Comments

6

5

4

3

2

1

0

11Q3

10

8

6

4

Eagle Ford

Permian

Bakken

Anadarko

DJ Basin

11Q4 12Q1 12Q2

Marcellus/Utica

Haynesville

Barnett

Fayetteville

12Q3

Frac Capacity in Key Liquids Plays (11Q3-12Q4)

12Q4

■ We expect more than 1.1 MM HHP of frac capacity to be redeployed from key gas plays during 2012, driven primarily by deployments out of the Haynesville and

Fayetteville,

■ We expect aggregate capacity in these 4 key gas plays to total 4MM HHP EOY

■ We expect more modest declines in frac capacity in the Marcellus/Utica and Barnett, as activity in the liquids-rich portions of these plays is creating a softer landing for suppliers

■ We expect a 52% increase in frac capacity in

2012 across the Eagle Ford, Permian,

Bakken, Anadarko, and DJ Basin, for an EOY capacity of 9.7MM HHP

2

0

11Q3 11Q4 12Q1 12Q2 12Q3 12Q4



Due to the recent shift to an oversupplied market, quarterly additions of new frac capacity are expected to slow dramatically

1 200

1 000

800

600

400

Frac Capacity Additions, by Quarter

Frac Capacity Additions (11Q4-12Q4)

798

12H1 capacity additions:

1,748,300 HHP

1 029

720

386

Forecast

12H2 capacity additions:

607,500 HHP

222


Comments

■ We expect 12H1 additions to comprise nearly 75% of total 2012 frac capacity additions, 1.75MM HHP

■ Pressure pumpers have canceled or pushed back deliveries of new frac capacity because of expected oversupply issues in many US plays

■ We expect total 12H2 deliveries to total only

~600,000 HHP, or 25% of 2012 capacity additions

■ 12Q4 capacity additions are expected to amount to 72% less than capacity additions in 11Q4

200

0

11Q4 12Q1 12Q2 12Q3 12Q4

Dramatic slowdown in fleet/capacity additions!!



Over the last six months, US frac capacity utilization has fallen below

100% for the first time in more than two years

US Aggregate Frac Capacity Utilization

US Aggregate Capacity Utilization (11Q4-12Q4)

105%

100%

95%

90%

85%

100%

93%

87%

88%

89%


Comments

■ Pressure pumping demand has outpaced supply for the last two years, resulting in an aggregate utilization above 100%

■ Available pressure pumping supply surpassed demand in 12Q1, resulting in capacity utilization of 93%

■ We forecast capacity utilization to bottom out at 87% in 12Q2 and increase as pressure pumping demand increases in 12Q3 and

12Q4

■ We expect the year to close out with capacity utilization of 89% in 12Q4

80%

11Q4 12Q1 12Q2 12Q3

Forecast

12Q4

Good news: low NAM utilization makes business case for redeploying fleets internationally much more compelling



Agenda

1) About PacWest





6) Questions



Unconventional O/G carries with it significant supply chain and infrastructure implications

Unconventional Supply Chain & Infrastructure Implications

Competition & Innovation Key

■ Technology and innovation made shale a reality; requires entrepreneurial supply chain to optimize for each unique unconventional formation

■ US has deepest and most entrepreneurial O/G supply chain, competitive environment

Higher Service Intensity

■ Shale demands increased products/services, requiring more people, more equipment, more consumables (water, proppant, chemicals), more transportation infrastructure

Advanced Equipment and Experience Required

■ Most equipment and people will be imported initially; how friendly is import regime?

Infrastructure Availability Key

■ Production profile of shale gas wells is shorter and steeper than for conventional, so drilling campaigns have to be closely coordinated with take-away projects

Delay in infrastructure can significantly impact economics



Pressure pumping (frac), drilling rigs, and water will drive nearly 60% of

3 rd party costs in many plays

Operator 3 rd Party Spend by Category (3-year)

Stimulation/Completion = 39%

45%

40%

35%

30%

25%

20%

15%

10%

5%

0%

39%

Σ = 59%

Drilling Rigs = 11%

Water Treatment/Disposal = 9%

11%

9% 8%

4% 4% 4% 3% 3% 3%

2% 2% 1% 1% 1% 1% 1% 1% 1% 1% 1% 0% 0% 0%

Source: PacWest Analysis; Macquarie



As North American unconventional activity has increased, the supply chain has been forced to respond to a series of constraints

Recent Areas Experiencing Supply Chain Constraints

Hydraulic Fracturing Services

Frac Equipment

Frac Units

Frac Pumps

Frac Consumables

Frac Sand

Water

Chemicals (guar)

Labor Infrastructure

Rail Capacity

Storage

Takeaway Capacity

Source: PacWest Analysis

We will briefly talk through each of these



Global pressure pumping capacity is the single largest supply limitation to a rapid ramp up of global shale development

Global Reserves vs. Frac / Pumping Capacity

Source: Halliburton Analysis;, Barclay’s CEO Energy-Power Conference, Sep 2011



Annual frac capacity growth is expected to slow from its recent 33% annualized growth to 10% over the 2012 to 2016 timeframe

Global Frac Capacity Forecast

2012-2016 Frac Capacity Forecast Discussion

30

25

20

2011 growth peak

CAGR

33%

73%

17,1

19,8

20,7

Forecast

CAGR

10%

22,1

24,3

27,6

80%

■ Total frac capacity growth is expected to slow through 2016 from 33% to 10% CAGR

60%

High 2008-2011 growth rate was led by unprecedented 62% YoY growth over 2011 in

North America

■ Global frac capacity growth is forecast to reset to a more restrained pace through

2014 and then begin to pick up again in

2015-2016

15

10

5

0

7,3

8,2

12%

9,9

21%

16%

13%

40%

Increasing growth rates in 2015-2016 led by

NAM natural gas price increases and additions in emerging international shale

■ YoY 2012 capacity growth is forecast to slow from record 2011 high to 16%

20%

Followed by just 4% growth in 2013, which is expected to see the lowest growth rate over the forecast timeframe

10%

4%

7%

0%

2008 2009 2010 2011 2012 2013 2014 2015 2016

2013 growth trough

Source: PacWest Analysis; company documents; field staff interviews; PacWest FracDB / FracFocus.org



Starting in 2014, frac capacity additions are forecast to begin a shift from North America to international markets

Global Frac Capacity Forecast, by Region

8

7

6

5

4

3

2

1

0

2012-2016 Forecast Frac Capacity Additions

7,2

22%

78%

2011


Discussion

Good news: frac equipment manufacturing capacity is in place to support international frac demand

■ Forecast frac capacity additions of just 0.6 and 0.8 million HHP in 2012 and 2013 reflect a dropoff in demand for new equipment in North America

NAM continues to be the market driver, but at significantly lower level than recent years

2,7

7% 2,2

3,3

57%

■ In 2014, international capacity additions are expected to increase significantly, while

NAM additions remain flat

0,8

12%

1,4

42%

40%

■ In 2015 and 2016, international additions are expected to continue to grow

93% 88% 58% 60% 43%

2012 2013 2014 2015 2016

NAM demand is also expected to return with 7% and 9% growth, respectively



Unconventional wells require significant amounts of high-quality frac sand, as well as resin-coated and ceramic proppant

US Aggregate: Frequency of Proppant Usage

Frequency of Proppant Usage (% of wells)

100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

Sand is proppant of choice, used in 97% of wells

Wells Sand Resin-coated Sand

Source: PacWest analysis; PacWest FracDB / FracFocus.org

1 400

1 200

1 000

800

600

400

200

-

Ceramic

Comments

■ Frac sand is the most common proppant type, used in 96.8% of wells

■ Resin-coated sand is the second-most common proppant type, used in 13.5% of wells

■ Ceramic proppant is the least common proppant type, used in 2.9% of wells

■ N.B. percentages do not add to

100% because more than one type of proppant is typically used in a single well

■ N.B. sample size is small in

April 2012 and May 2012 due to reporting lag, so conclusions are uncertain for these time periods



Frac sand demand is expected to grow steadily in North America; does not even consider emerging international demand

Frac Sand Demand Forecast

Frac Sand Demand Outlook

Million Tons

140

120

100

80

60

40

20

0

52

2012

60

2013

CAGR (2012-2018) = 16.0%

69

2014

80

2015

94

2016

109

2017

127

2018

Discussion

■ Sand supply and demand have balanced out in the last 6 months as significant new frac sand capacity has hit the market

■ Primary constraint in NAM frac sand is no longer the sourcing / mining, but the logistics operation

■ Single frac may require as many as 25 railcars of frac sand, making the logistics of getting sand from mine to well a logistics challenge

Other Grades 40/70 30/50 20/40

Lots of sand capacity in NAM, but where will Argentina frac sand come


from??



Guar prices spiked over 2011-2012 due to seedstock constraints and rapidly increasing demand, resulting in price spikes

Guar Gum Supply/Demand

‘000 Tons

1 000

900

800

700

600

500

400

300

200

100

-

$6 000

Guar Gum Supply vs. Demand

Price spike!!

Prices are

FOB Mundra

$8 500 $10 250

$3 250

2008 2009 2010 2011

Supply

$15 750

Demand

$9 250

Forecast

2012 2013 2014 2015 2016

Estimated Avg. Prices

Note: Capacity represents end-of-year capacity, not average capacity


$/Ton

$18 000

$16 000

$14 000

$12 000

$10 000

$8 000

$6 000

$4 000

$2 000

$-

Discussion

■ Wholesale prices for oilfield guar have climbed to nearly

$25/kg over the last year, from a typical historical price of

$1.50/kg

■ High wholesale prices have stressed the margins of pressure pumpers

■ There has been much speculation of a shortage of guar gum in the summer but there have been no reports yet of a shortage in the field

■ Based on recent PacWest work in India to assess guar supply market, probability of a guar shortage in the next six months is high



Guar price increases forced NAM pressure pumper costs to double to nearly $1 billion during 2012 Q2

US Total Guar Consumption by Pressure Pumper

$300

$250

$200

$150

$100

$50

Estimated 2012 Q1 vs. Q2 Guar Costs

Q1 Total = $478 million

Q2 Total = $930 million

95% increase

Major cost impact QoQ

2012 Q1

2012 Q2

Discussion

■ Guar costs increased an estimated 95% from 2012 Q1 to 2012 Q2

Due to both price increases and larger purchases

■ Pressure pumpers spent an estimated $478 million on guar to support 2012 Q1 US oilfield activity

Based on an estimated average

2012 Q1 price of $11,000 per ton for oilfield grade guar powder

$-




Rapid growth of hydraulic fracturing activity has driven significant increases in the use of water in the oilfield

Frac Water Demand: Demand & Flowback

Hydraulic Fracturing Water Demand

■ In 2011, the average unconventional/shale frac in the US consumed

65,000 barrels of water (2.7 million gallons)

That’s a lot of water!!

Flowback

■ Water that flows back within 15-

45 days after a frac job is called

“frac flowback”

■ Average of 10-35% of the total water pumped downhole flows back during the flowback period

Average of 7,000-23,000 barrels of water (0.3-1.0 million gallons)

Some areas (Mississippi Lime) flowing back nearly 100%!!

■ Flowback water is handled in one of several ways:

Disposal via injection well

Treatment and re-use for other frac jobs

Evaporation via ponds

(largely restricted to Rocky

Mountain region)

Source: PacWest analysis; PacWest FracDB / FracFocus.org; Newfield Exploration



Many areas face constraints for water sourcing and disposal, adding costs to operations and, at times, halting operations

Water Constraints

Region/Basin Constraints Drivers

Legend: L H

Marcellus

Bakken

Barnett

DJ Basin

Eagle Ford

Fayetteville

Haynesville

Permian

San Juan

Granite Wash

Lack of Disposal Wells, Regulatory Pressure

Water Quality, Infrastructure Constraints

Water Scarcity

Water Scarcity, Regulatory Pressure

Water Scarcity, Infrastructure Constraints

Lack of Disposal Wells

Water Scarcity, Lack of Disposal Wells

Water Scarcity

Regulatory Pressure, Water Scarcity

Water Scarcity

Constraints are driving increased water treatment/reuse; environmentally positive, but costs $$

Source: PacWest Analysis; Conestoga-Rovers & Associates; WorleyParsons; additional expert interviews with operators and service providers



Shortage of oilfield labor has constrained service capacity in North

America; labor availability even more limited internationally

Supply Chain Constraints: Labor

■ Shortage of oilfield labor is the primary constraint to deploying new frac fleets

■ Shortage of labor to staff up drilling rigs is also the key constraint holding back the rig count

■ Labor shortage is particularly acute in the Permian and Bakken plays, where between

40% and 50% of oilfield labor travels from other areas

■ Average experience of deployed oilfield personnel has decreased dramatically over the last two years as service providers have hired anyone available

■ Arguably the MOST difficult to address, particularly given the industry-wide challenge of experienced staff retiring over coming years

Potentially hardest problem to address!!



Infrastructure constraints are often at the root of supply chain constraints; fracs require massive volumes of material inputs

Critical Infrastructure Constraints & Risks

Rail Capacity

■ Fracturing a well requires large volumes of consumables, particularly sand and chemicals

Typical Bakken well requires 15 railcars of sand

■ Rail is generally the only cost-effective method to transport these materials to a region

■ Transloading facilities and railcar capacity are common capacity constraints

Storage

■ Storage capacity is a critical infrastructure component that helps service companies manage equipment and consumables

■ Proper storage facilities are critical to maintain quality of high-grade frac sand and other completion chemicals

■ Limited storage infrastructure has led to shortages of critical materials that were not available for delivery to wellsite for frac

Takeaway Capacity

■ Siting and constructing new pipeline capacity for hydrocarbon ‘takeaway’ requires 2+ years

■ Prior to development of pipeline capacity, rail is the preferred method to transport hydrocarbon

Use of rail for takeaway exacerbates frac consumable transport

■ Trucks are easiest, but most expensive transport method!!

Neuquen benefits from existing infrastructure, though investments will be required as activity increases



Agenda






6) Questions



The EIA’s 2011 study of shale gas resources sized up resources across 14 regions outside the US

Global Shale Resources

Source: EIA, World Shale Gas Resources Report



A study by the Baker Institute forecasts shale gas production across key regions through 2040

Global Shale Resource Estimates & Production Forecasts

Global Shale Resource Estimates (bcf) Gas Production Forecasts (tcf)

India

France

Poland

Brazil

Algeria

Libya

Canada

S Africa

Mexico

Argentina

USA

China

63

180

187

226

231

290

388

485

681

774

862

1 275

200 400 600 800 1 000 1 200 1 400

70

60

50

India

France

Poland

Brazil

40

30

Algeria

Libya

Canada

Mexico

20

10

Argentina

USA

0

2010 2015 2020 2025 2030 2035 2040

China

Source: EIA, World Shale Gas Resources Report; Baker Institute, Shale Gas and US National Security



However, more than just technically recoverable resources are required to successfully produce unconventionals; many critical risk factors

Non-Technical Risks Factors

Demand

Supply Chain

Domestic E&P

Industry

Markets

Regulatory

Frameworks

Infrastructure

Development

Constraints

 The level of natural gas demand within the country and neighboring countries that can serve as consumers

 Quality of existing supply chain, number of rigs currently in-country, ease of entry for new players, etc.

 Number of existing domestic E&P firms, level of unconventional experience, ease of entry, etc.

 Regulatory structure, midstream/downstream demand dynamics, etc.

 Fragmentation, tax policies, government incentives for unconventional development, etc.

 Quality of existing midstream, ease of developing new infrastructure, etc.

 Water, population densities, political/social acceptance, etc.




International frac capacity is forecast to grow 133% over the five years to 2016 to a total of 5.6 million HHP

International Frac Capacity Growth Forecast

2011-2016 International Frac Capacity Discussion

6

5

4

3

2

1

2,4

5-Year International Growth = 133%

International capacity is forecast to more than double!

2,5

3,2

4,0

4,8

5,6

0

2011 2012 2013 2014 2015 2016

Notes: Internationally deployed frac equipment is generally built and produced in NAM


Region

Other 100%

MENA

5-Year

■ International capacity is generally manufactured in NAM

Growth

China is exception; bulk of capacity

233% likely manufactured in-country

Mexico

Argentina

300%

150%

■ Russia is currently the largest int’l frac market; expected to maintain that lead with healthy growth

Poland 60%

■ Australia capacity demand is

China 167% growing and it is forecast to experience the largest growth rate

Offshore

Australia

Russia

52% ■ Offshore market will likely see steady stim vessel demand growth

700% ■ China will see strong growth, though much of its demand could be satisfied internally

114%

■ Argentina activity will likely increase driving capacity demand

■ Mexico and Middle East/North

Africa likely see frac demand as well



Argentina has made steady progress on unconventional resources and has drilled/completed more shale wells than any region outside NAM

Argentina Activity & Supply Chain Update

■ More than 125 unconventional wells expected to be drilled and completed by 2012 end-of-year (25 in 2011, 100 in 2012)

Mostly small (3-5 stages) vertical wells, several multi-stage horizontal

Multi-stage horizontal wells extremely expensive: $24 million for the 1 st (Apache)

YPF leading development activities, accompanied by multiple NAM E&Ps

■ Major service centers already established and service companies are steadily adding fracturing equipment/capacity

~15 rigs active in-country (H&P, Nabors, others); ~2 rigs per frac crew

Estimated 190,000 HHP (8 fleets) in-country – additional deployments planned??

Schlumberger, Halliburton, Baker Hughes, Calfrac, San Antonio, Weatherford – others??

■ Infrastructure sufficient to support early-stage activity

Established oil and gas pipeline network

Capacity available within existing network, including export capacity

■ Experienced oilfield labor; augmented by NAM staff with hands-on shale experience

Strong candidate to be one of the first major unconventional resource basins to be developed outside of NAM



Poland was once the primary focus for international shale efforts, but slow progress has dimmed optimism

Poland Activity & Supply Chain Update

■ More than 50 unconventional wells drilled by 2012 end-of-year (10 in 2011, 40+ in

2012)

Only 6-8 of ~25 wells to date were horizontal, only 4 wells completed

Mixed results, with multiple wells drilled by key operators (i.e. PGNiG, Marathon,

BNK, Orlen) with gas shows from multiple wells

Exploration programs on-going with many more wells to drill under concessions

ExxonMobil pull out was blow to optimism , though geopolitics had bigger role

■ Leading service companies have set up bases and/or partnerships to operate incountry

Schlumberger, Halliburton, Baker Hughes all have bases established; Weatherford

Schlumberger completed 13-stage frac for 3Legs Resources, largest to date

Capital beginning to flow to develop domestic supply chain: United Oil Services

■ Infrastructure limited and may potentially slow development efforts

Logistics/ transportation issues already emerging

■ Extremely small domestic E&P industry means that nearly all labor imported



Australia has made meaningful progress on CBM, just starting with shale; supply chain constraints already emerging

Australia Activity & Supply Chain Update

■ Strong geology, economic incentives, regulatory framework

■ More than 1,000 CBM wells drilled to date, though far short of 3,000-well target; shale development just beginning

Significant stakeholder issues with CBM, particularly focused on water, has halted some activities

Numerous domestic and international operators participating

First multi-stage horizontal shale well just completed; Cooper Basin, Beetaloo,

Kidson, Perth, and Eromanga sub-basins are targets of activities

D&C costs for shale well likely in excess of $20 million

■ Significant supply chain bottlenecks emerging across multiple products/ services – need for greater supply chain support

Both rigs and fracturing equipment scarce

Less than 100,000 HHP of fracturing capacity currently in-country; far more needed

Halliburton, Baker Hughes, Schlumberger, Trican operating

Water sourcing for fracturing will present challenges

■ Infrastructure availability inland poses challenges

■ Oilfield labor available due to major offshore projects, but Australia labor is expensive



There have been some recent roadblocks to shale production in select countries around the world

Global Shale Progress

■ Canada: Quebec put temporary moratorium in place

■ EU: Considering stricter shale guidelines to the protests of Poland

■ France: Shale moratorium in place, halting exploration activity in the highly promising oil-bearing Paris Basin

■ Bulgaria: frac moratorium in place, though politicians already reconsidering hasty decision

■ India: Licensing round delayed until 2013

■ South Africa: Temporary moratorium in place pending assessment of environmental impact report; multiple delays

Source: EIA, World Shale Gas Resources Report

■ Sweden: Has seen protests to

Shell’s exploration activity

■ UK: Has seen protests, then embrace by government;

Cuadrilla put its exploration activities on hold after minor seismic activities during drilling



One thing to keep in mind is how supply chain needs differ for exploration versus development phases

Exploration vs. Development Phase

Exploration Phase

 Data collection exercise

 Goal: collect enough data to prove that hydrocarbons are present

 Priorities: speed, logistical simplicity

 Willingness-to-pay: relatively high

 Staffing: in-country team small

Development Phase

 Supply chain development and mgmt

 Goal: build a long-term supply base that will help you reduce costs and optimize production, while minimizing risks

 Priorities: cost management, diversification

 Willingness-to-pay: low to moderate

 Staffing: build local resources

Implications

 Bundling strategies are common to simplify logistics, mgmt, admin

 Work with local equipment providers

(i.e. rigs) if possible for speed

 Big 4 and majors often best positioned

 More likely to distribute work between majors and local players

 Willing to invest time/effort in building local supply base

 Fwd-looking sourcing strategies



Agenda






6) Questions



The US Bakken play has boomed over the last three years, placing significant strains on existing infrastructure and supply chain

The Bakken Formation

US Analogue: Bakken

Formation

 Huge contiguous oil accumulation spanning North Dakota and Wyoming in the US, Saskatchewan and Manitoba in

Canada

~14,700 square-miles; largest ever assessed by USGS

Challenges

 Existing infrastructure limited

 Has seen tremendous growth over last two years

 Growth has placed major strains on the supply chain

 Effectively starting from zero

Source: Continental Resources



Since late-2009, the rig count has increased 2-3x, with counts forecast to remain above 200 rigs

Bakken Rig Count & Forecast

80

60

40

20

0

Rig Count – Dir/Hor vs. Vertical

200

Land Rigs

180

160

Directional/Horizontal

Vertical

140

120

100

Land Rigs

Average Rig Count Forecast

250

200

210

220

200

180

150

100

50

0

2011 2012 2013 2014

Source: PacWest Analysis; Macquarie; Baker Hughes



Overwhelming demand in the Bakken led to a significant under-supply of pressure pumping capacity in 2011

Sensitivity Analysis of 2011 Bakken Pressure Pumping Capacity Utilization

250% 241%

42%

200%

150%

100%

50%

2011 completions + backlog

2011 completions

161%

28%

121%

21%

100%

100% utilization of

2011 capacity

133%

201%

35%

166%

199%

0%

15 20

Average Stages per Well

25 30

The Bakken will be 61% under-supplied in 2011, conservatively assuming 20 stages/well

Sources: CIBC World Markets; Macquarie; PacWest analysis



For approximately two years, demand for pressure pumping capacity outpaced supply

Sensitivity Analysis of 2012 Bakken Pressure Pumping Capacity Utilization

200%

180%

160%

140%

120%

100%

80%

60%

40%

20%

0%

159%

45%

114%

100% utilization of 2012 capacity

152%

43%

109%

2012 completions + backlog

2012 completions

146%

42%

104%

140%

40%

100%

30% 40% 50%

Capacity Growth (2011 – 2012)

60%

Note: Sensitivity analysis assumes an average of 20 frac stages / well in 2012, a conservative estimate

Source: CIBC World Markets; Macquarie; PacWest analysis



Staffing experienced crew has been a critical challenge faced by pressure pumping service providers, particularly in the Bakken

The Quality vs. Quantity Dilemma

■ Completion increases = HHP increases = Frac crew increases = Need for trained staff!!

■ North American pressure pumping industry is expanding rapidly (~20% YoY increase

2010-2011) and needs to add new hires to meet expansion targets

■ Major increases in completions require major increases in frac crews, for example:

Typical 25K HHP frac fleet in the Bakken requires 2-3 crews of 30 staff = 60 – 90 experienced employees

PacWest forecasts an increase in frac fleets in the Bakken from 38 fleets (May 2011) to 52 fleets (year-end 2011) = 840-1,260 experienced employees

■ Fact: Critical driver of oilfield safety = experienced staff

■ Problem: There are no more experienced field workers left; pumpers are forced to manage deployment of large numbers of inexperienced employees



Supply chain constraints held back the deployment of new equipment and the ability to consistently supply pumping services

Bakken Supply Chain Constraints

Logistics

■ Railway (primarily BNSF) import capacity into the Bakken is limited for all products, particularly proppant due to the large volumes required (1 railcar has capacity of 200K lbs of proppant; average 3 million lbs frac job requires 15 railcars)

Proppant

■ Global proppant consumption has reached unprecedented levels and most domestic producers are essentially sold out of product

■ Greatest constraint is in 20/40 raw sand

Guar

■ Demand has reached record highs and the guar supply chain is not highly responsive due to its length (90% of raw guar seed grown in rural India)

Equipment

■ Manufacturers of pumping equipment reporting order backlogs of up to 1 year

Labor

■ Local labor force in the Bakken is limited and unemployment is extremely low



Bakken pressure pumping supply was unable to keep pace with demand resulting in a significant well completion backlog

Days Required for D&C in North Dakota

180

120

60

172

90

67

85 76

50

87

72

96

57

81

67

82

80 81

103

99 95 98 103

107

93

118

0

Bakken Well Count (May 2011)

500

400

300

200

100

0

Uncompleted Drilling

Bakken

Montana

429

57

162

6

North Dakota 372 156

Sources: Montana Board of Oil & Gas; North Dakota Industrial Commission; PacWest analysis

Permitted

413

67

346



Operator D&C performance varied, in some cases depending on supply chain sourcing and contracting practices

Bakken Ratio of Uncompleted Wells to Active Rigs (May 2011)

Anschutz/OXY

Continental Resources

Whiting Oil & Gas

Zenergy

Brigham Oil & Gas

ConocoPhillips

Hess

Slawson

Newfield

EOG Resources

Marathon

Oasis Petroleum

1,0

1,8

1,9

2,0

Backlog was result of frac

2,4 equipment shortages

2,6

2,7

2,8

3,0

3,4

3,6

Well

Backlog

Rigs

7 7

45 25

29 15

12 6

17 7

13 5

48 18

17 6

15 5

34 10

25 7

27 6 4,5

0 1 2 3 4 5

Note: Well backlog is best estimate based on data from Montana and North Dakota oil/gas regulators; rig count is from April 2011

Sources: Montana Board of Oil & Gas; North Dakota Industrial Commission; PacWest analysis



Agenda

1) Introduction





6) Questions


Developing Emerging International Shale Plays

Developing Emerging International Shale Plays

Supply Chain Challenges & Constraints

Bakken

DJ Basin/Niobrara

Granite Wash

Permian Basin

Eagle Ford

Oil rigs up!!

Dramatic slowdown in fleet/capacity additions!!

Good news: low NAM utilization makes business case for redeploying fleets internationally much more compelling

We will briefly talk through each of these

Good news: frac equipment manufacturing capacity is in place to support international frac demand

Lots of sand capacity in NAM, but where will Argentina frac sand come

from??

Constraints are driving increased water treatment/reuse; environmentally positive, but costs $$

Potentially hardest problem to address!!

Neuquen benefits from existing infrastructure, though investments will be required as activity increases

Strong candidate to be one of the first major unconventional resource basins to be developed outside of NAM

Related documents

Products

Support

Developing Emerging International Shale Plays

Developing Emerging International Shale Plays

Supply Chain Challenges & Constraints

Bakken

DJ Basin/Niobrara

Granite Wash

Permian Basin

Eagle Ford

Oil rigs up!!

Dramatic slowdown in fleet/capacity additions!!

Good news: low NAM utilization makes business case for redeploying fleets internationally much more compelling

We will briefly talk through each of these

Good news: frac equipment manufacturing capacity is in place to support international frac demand

Lots of sand capacity in NAM, but where will Argentina frac sand come

from??

Constraints are driving increased water treatment/reuse; environmentally positive, but costs $$

Potentially hardest problem to address!!

Neuquen benefits from existing infrastructure, though investments will be required as activity increases

Strong candidate to be one of the first major unconventional resource basins to be developed outside of NAM

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