north american upstream cost & technology trends · 2018-04-26 · • world demand. world...

Confidential. © 2018 IHS MarkitTM. All Rights Reserved.Confidential. © 2018 IHS MarkitTM. All Rights Reserved.

Presentation

North American Upstream Cost & Technology Trends

April 2018

Pritesh Patel, Executive Director, CCS/OCS, + 1 713 369 0275, [email protected]

David Vaucher, Associate Director, CCS/OCS, + 1 281 670 6896, [email protected]

Costs and Expenditures

mailto:[email protected]

mailto:[email protected]

Confidential. © 2018 IHS MarkitTM. All Rights Reserved.

Copyright notice and disclaimer

2

© 2018 IHS Markit. All rights reserved.

This presentation is not to be construed as legal or financial advice, use of or reliance on any

content is entirely at your own risk, and to the extent permitted by law, IHS Markit shall not be liable

for any errors or omissions or any loss, damage, or expense incurred by you or your organization.

Upstream Cost Evolution


Contents

I. IHS Markit Product Scope

II. Upstream Outlook

III. Cost Trends

IV. Technology Trends


IHS Markit Product Scope


Upstream Costs & Technology Subscriptions

5

Project Cost Planning | Strategic Sourcing | Technology Strategy

Upstream Costs & Expenditures

• Upstream Costs & Expenditures

• North America Costs & Expenditures

• Brazil Costs & Strategic Sourcing

Oilfield Equipment & Services

• Engineering & Fabrication

• Offshore Services & Vessels

• Onshore Services & Materials

• Subsea & Capital Equipment

• Rig Markets

Upstream Technology & Innovation

• Upstream Technology & Innovation

5


Oilfield Equipment & Services - Segment coverage

6

Industry Trends Upstream Spend Report

OCTG

Offshore Rigs -

Floaters

Offshore Rigs - Jackup Well LoggingOnshore Drilling Rigs

FLNG LNG Regasification

Facilities

Onshore Prod. Facilities

Oil Sands

Topsides Fabrication

Jacket Fabrication

FPSO, FSO

Floater (Semi, TLP,

Spar)

LNG Liquefaction

Facilities

Gas Compressors

Line Pipe

Umbilicals and Flexible

Pipe

Subsea Equipment

Heat Exchangers

Gas TurbinesValves

Construction LaborEngineering

Services

Helicopter Services IMR (Platforms)

Onshore PipelayOffshore Pipelay

Offshore Heavy Lift

Offshore

Accommodation

Offshore Installation

(DSV/ROSV)

RIG MARKETS

ENGINEERING &

FABRICATION

OFFSHORE

SERVICES &

VESSELS

SUBSEA &

CAPITAL

EQUIPMENT

OFFSHORE ONSHORE OFFSHORE AND ONSHORE

Onshore Drilling Rigs

Well Logging

Drilling Fluids

Well Completions

Hydraulic fracturing

Proppant

Stim. Chemicals

Oilfield Water

N. Am. Upstream Spend Report

ONSHORE

SERVICES &

MATERIALS

Drilling Fluids


Upstream Outlook


Global economic outlook continues to strengthen and is expected to

boost global oil demand over the coming years

Market fundamentals IHS Markit, Cost & Technology – Industry Trends, March 2018

8

-

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

1 2 3 4 5 6 7 8

%

Global GDP growth 2014-2021 (real)

Source: IHS Markit © 2018 IHS Markit

Avg. 3.2Avg. 2.9

2014 2015 2016 2017 2018 2019 2020 2021


OPEC’s production cuts finally started to impact inventories during

2017…

Market fundamentals

© 2018 IHS Markit

2,400

2,500

2,600

2,700

2,800

2,900

3,000

3,100

3,200

Jan-13 Jul-13 Jan-14 Jul-14 Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17

OECD total oil industry stocks

Notes: Total oil industry stocks include crude, refined product, NGL, and feedstocks. Data are monthly, through December 2017.


Mill

ion

ba

rre

ls

Total stocks

5-year average

Data through December 2017.

9

IHS Markit, Cost & Technology – Industry Trends, March 2018

OPEC production cuts have started to take effect…

Inventories approaching 5-year

average


…however US producers have passed the “tight oil test” by adjusting

costs to lower prices and remain competitive

Market fundamentals

10

0

10

20

30

40

50

60

70

80

90

Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017

Bakken Shale Bone Spring Eagle Ford Shale Wolfcamp Delaware Wolfcamp Midland

Median break-even prices for five key US oil plays, 2014–17

© 2018 IHS Markit

Bre

ak-e

ve

n p

rice

in te

rms o

f W

TI (U

S$

/bb

l)

Notes: The break-even price is the WTI crude oil price required for the project to cover all of its estimated well capital and operating costs and generate a 10% rate of return. Data are through 3Q 2017.

Source: IHS Markit Performance Evaluator


50-60% reductions in

break-even prices


US oil production responds quickly to price changes, though growth can be

sustained with oil prices in the mid-$50/bbl range

0

10

20

30

40

50

60

70

6.0

6.5

7.0

7.5

8.0

8.5

9.0

9.5

10.0

10.5

11.0

11.5

12.0

Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 Oct-18 Jan-19 Apr-19 Jul-19 Oct-19

Sp

ot

pri

ce a

nd

av

era

ge b

reak

-ev

en

($/b

bl)

Chart Title

>$80

$70-$80

$60-$70

$50-$60

$40-$50

$30-$40

Base wedge

Avg. monthly break-even (right axis)

Spot price (right axis)

US oil production volumes by break-even price

© 2018 IHS Markit

Mm

b/d

Source: IHS Markit

US oil production forecast / January 2018

11


US crude oil production will reach nearly 11.0 MMb/d by the end of 2018,

representing exit-rate growth of over 1.0 MMb/d from 2017 levels

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 Jan-23

Mm

b/d

Chart Title

Alaska

GOM Shelf

GOM Deep

Fluid Type - Oil

Fluid Type - Gassy Oil

Fluid Type - Wet Gas

Fluid Type - Dry Gas

Other Plays

STACK

SCOOP

Niobrara Frac Play

Wattenberg

Permian - Other

Bone Spring

Wolfcamp Midland

Wolfcamp Delaware

Spraberry

Bakken

Eagle Ford

Q417 abundant capital scenario

US crude oil production by play, 2012-23: Rangebound (median) case

© 2018 IHS MarkitSource: IHS Markit

9.889.46 8.779.23 10.91 11.67


12


(5.0)

(4.0)

(3.0)

(2.0)

(1.0)

-

1.0

2.0

3.0

4.0

0

20

40

60

80

100

120

140

Jan-2009 Jan-2010 Jan-2011 Jan-2012 Jan-2013 Jan-2014 Jan-2015 Jan-2016 Jan-2017 Jan-2018 Jan-2019

Market balance Dated Brent (USD/bbl)

Market balance and oil price development


US

D/b

bl

mill

ion

ba

rre

ls p

er

da

y

Strong demand growth Economic slowdown Supply glut

OPEC

Rebalancing US comeback

As inventories again start to build, prices should come down later this

year

Market fundamentals

13



IHS Markit Global Crude Oil Markets Short-Term Outlook – February 2018

14

Oil prices to fall from recent highs as balance reverts to loosening trend

Source: IHS Markit, Argus Media Limited (historical)

Benchmark crude price outlook (dollars per barrel)

3Q 2016 4Q 2016 1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2Q 2018 3Q 2018 4Q 2018 1Q 2019 2Q 2019 3Q 2019 4Q 2019

Dated Brent $45.80 $49.35 $53.66 $49.58 $52.07 $61.22 $65.38 $63.07 $64.34 $60.38 $56.09 $56.07 $55.32 $57.94

WTI $44.88 $49.23 $51.70 $48.11 $48.16 $55.23 $61.58 $60.43 $61.96 $55.59 $49.52 $51.87 $52.24 $56.67

Assumptions

• World demand. World liquids demand growth stays

robust this year, at 1.9 MMb/d, fueled by strong non-

OECD Asia refined product and US NGLs demand

gains. Growth eases to 1.6 MMb/d in 2019; partly as

US NGLs demand growth slows.

• OPEC and Russia production. OPEC and Russia

maintain output restraint through 2018 to continue

supporting prices.

• US production. With WTI prices averaging well

above $50/bbl, US crude output rises at a blistering

annual pace of 1.3 MMb/d in 2018 and 0.9 MMb/d in

2019.

• Global liquids balance. Fast-rising US output will

moderate upward price pressure from continued

robust world liquids demand growth.

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

Q1 1

5

Q2 1

5

Q3 1

5

Q4 1

5

Q1 1

6

Q2 1

6

Q3 1

6

Q4 1

6

Q1 1

7

Q2 1

7

Q3 1

7

Q4 1

7

Q1 1

8

Q2 1

8

Q3 1

8

Q4 1

8

Q1 1

9

Q2 1

9

Q3 1

9

Q4 1

9

Dated Brent WTI-Cushing

Qu

art

erl

y a

vera

ge p

rice p

er

barr

el

Outlook

Dated Brent and WTI-Cushing crude oil price outlook to 2019

Notes: WTI = West Texas Intermediate.

Source: IHS Markit, Argus Media Limited (historical) © 2018 IHS Markit


0

20

40

60

80

100

120

2000 2005 2010 2015 2020

History Rivalry (base case)

Dated Brent price outlook to 2022 in three IHS Markit Scenarios

© 2018 IHS Markit

US

do

llars

pe

r b

arr

el (n

om

inal)

Notes: Rivalry price outlook for 2018-19 consistent with monthly short-term crude oil markets price update released in February 2018. Rivalry price outlook for 2020-22 is consistent with the IHS Markit Global Crude Oil Markets Long Term Price Outlook: Fourth Quarter

2017 Update, released in November 2017. Autonomy and Vertigo price outlooks from 2018 on are consistent with the IHS Markit Scenarios update, released in July 2017.

Source: IHS Markit

0

20

40

60

80

100

120

2000 2005 2010 2015 2020

History Rivalry (base case) Autonomy Vertigo

Dated Brent price outlook to 2022 in three IHS Markit Scenarios

© 2018 IHS Markit

US

do

llars

pe

r b

arr

el (n

om

inal)

Notes: Rivalry price outlook for 2018-19 consistent with monthly short-term crude oil markets price update released in February 2018. Rivalry price outlook for 2020-22 is consistent with the IHS Markit Global Crude Oil Markets Long Term Price Outlook: Fourth Quarter

2017 Update, released in November 2017. Autonomy and Vertigo price outlooks from 2018 on are consistent with the IHS Markit Scenarios update, released in July 2017.

Source: IHS Markit

Oil price outlook

Increasing geopolitical tension Nationalist movements

Civil unrest and terror incidentsCrisis and natural disasters

Renewables and technology

Industry development

Our long term oil price expectation is bound to face the realities of our

world


15


What you need to know: Upstream

16

• Increased capex will drive higher production growth, reaching 10.9 MMb/d by December 2018, representing year-over-year growth of over 1.0 MMb/d. Oil

prices began strengthening in the third quarter 2017, as US companies locked in hedges for 2018 and set capital plans. Higher prices will enable the 1.0 MMb/d of

growth, but with stronger cash flows than in prior years, when growth came at the expense of cash flow. Consequently, US onshore capital expenditure continues its

upward February, with upstream spending expected to increase from $69.2 billion in 2017 to $96.9 billion in 2018. We expect companies will achieve production

growth in 2018 similar to that in 2014 despite 2018 capex remaining 40% below the 2014 peak of $161 billion.

• Oil production growth of 1.0 MMb/d in 2018 is nearly certain. Rising oil output is fueled by supportive Permian, Eagle Ford, and STACK economics in a mid-

$50/bbl price environment, in addition to a recent price rally that has enabled companies to lock in approximately 25% of 2018 oil volumes at an average strike price

of $53.40/bbl. The ever-prolific Permian Basin, for its part, will remain insulated from possible price declines through mid-2019 because Permian-focused companies

have hedged approximately 63% of 2018 oil

• Continued well productivity gains. Operators continue to optimize logistics and well configuration. The Eagle Ford and Permian plays continue to be developed

with ever-longer lateral lengths and higher proppant loads, leading to greater volumes from fewer wells. IHS Markit has modeled type curve improvements both from

lateral lengths and completion operations, though continued productivity growth is expected to taper off through 2020 as operators reach the limits of well designs.

• Fleeting drilling efficiency improvements. Following several years of impressive drilling efficiency gains, average drill days per well are expected to remain

largely unchanged in 2018 and 2019. Contributing factors include rig reactivations undertaken by less experienced crews, as well as ongoing increases in average

lateral lengths.

• Well counts increase, despite flattening rig count, because of DUC conversions. US onshore rigs averaged 855 in 2017, up from 502 in 2016. Well additions

during those two years remained stagnant, hovering below 15,000 wells each year. In 2018, IHS Markit expects the onshore rig count to average 919, a 7% increase

over the previous year. Onshore well counts, however, are projected to increase by 20% over 2017 levels, primarily because of an anticipated drawdown in the

number of DUC wells: IHS Markit forecasts a total of 17,955 well additions during 2018, of which 1,172 are DUCs. These rigs are drilling longer laterals and more

productive wells to provide wedge volumes of 2.9 MMb/d, countering a base decline of 1.7 MMb/d, to grow US volumes by about1.0 MMb/d.

• Strong production growth in 2017; the cycle continues into 2018. Despite slower associated gas production growth because of a pullback in oil-directed drilling,

expanded takeaway capacity in Appalachia will spur a rapid expansion in Marcellus and Utica output. In total, US gas production is expected to increase by 5.5 Bcf/d

during 2018, surpassing a total of 80.0 Bcf/d by year-end.

• Growth moderates post-2018, but nevertheless remains significant. Although production from 2019 onward is likely to grow more slowly than in 2017-18, IHS

Markit forecasts that US natural gas volumes will rise by an average of nearly 3.8% per year through 2023, reaching 89.2 Bcf/d.

• Appalachia and associated gas remain the twin drivers of US supply growth. Combined, Marcellus, Utica, and associated gas production currently make up

nearly 62% of total US output, up from just 20% in 2011. By 2023, IHS Markit projects that combined Appalachian and associated gas volumes will account for 75%

of total US production.


Risks and assumptions

• Debottlenecking the Permian. We project that Permian drilling activity will continue at a furious pace in 2018, averaging 377 active rigs through 2018, including 328

targeting the three major unconventional Permian plays. This level of activity cannot be matched by the undersupplied service sector, which is particularly

constrained by labor shortages for completions crews. Nevertheless, service sector bottlenecks are expected to ease somewhat during the second half of 2018,

bringing completions activity into alignment with drilling levels. As completions activity ramps up, oil production growth will accelerate as newly completed wells bring

additional volumes to market. As a result, any change in the timing of the ending of service sector bottlenecks will alter the short-term outlook for production growth.

• Productivity gains in the Eagle Ford and Delaware Basin. IHS Markit research shows continued improvements in well productivity across several plays,

particularly in the Eagle Ford and in the Wolfcamp Delaware in the Permian Basin. Operators continue to achieve incremental productivity improvements through

ever-increasing lateral lengths and proppant intensities. Should these productivity improvements not materialize as expected, IHS Markit’s current projections for

December 2018 oil production could be reduced by as much as 275,000 b/d.

Assumptions

Risks

• OPEC/Non-OPEC agreement and geopolitical issues. All signs point to continued adherence to the OPEC/Non-OPEC agreement, with the top-line volume

restrictions being respected. However, the political situation in the Middle East, particularly Iran, could trigger a breakdown in cooperation. If the existing agreement

were to collapse, oil prices would likely face dramatic downward pressure, leading to declining activity in non-Permian oil plays such as the Bakken and the Eagle

Ford. Nevertheless, such a price decline would likely take at least six months to affect drilling activity, creating the potential of a more prolonged downturn.

• In-field execution. Despite the impressive acceleration in onshore activity achieved during the second half of 2017, some execution risk remains because of

continued growth in lateral lengths and completions intensity. This risk is compounded by relatively inexperienced service-sector crews. As a result, delays and

inefficiencies are more likely now than at any time since 2014, though the overall impact on production would be relatively minor.


17


Cost Trends


Following two years of massive spending cuts, global upstream spending

bottomed out in 2016 and is now expected to rise as costs have come down

Market fundamentals

19

0

20

40

60

80

100

120

-

100

200

300

400

500

600

700

800

900

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

South America Russia & Caspian North America Med. & Middle East Europe Central America Asia Pacific Africa Date Brent oil price (nominal)

Total upstream spending by region (USD billion)

© 2017 IHS Markit

US

D b

illio

n

Source: IHS Markit Global Upstream Spending, August 2017

Oil

price

(U

SD

per

barr

el)

0

20

40

60

80

100

120

-

100

200

300

400

500

600

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Onshore upstream spending by region (USD billion)

© 2017 IHS Markit

US

D b

illio

n


Oil

price (

US

D p

er

barr

el)

0

20

40

60

80

100

120

-

50

100

150

200

250

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Offshore upstream spending by region (USD billion)

© 2017 IHS Markit

US

D b

illio

n


Oil

price

(U

SD

per

barr

el)

26%

% of total spending in 2017% of total spending in 2017

74%



Onshore US capex reaches nearly $97 billion in 2018 and $105 billion in 2019,

with 41% deployed in the Permian Basin

0

20

40

60

80

100

120

140

160

180

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Chart Title

Fluid type - Oil

Fluid type - Gassy Oil

Fluid type - Wet Gas

Fluid type - Dry Gas

Other plays

Marcellus WV

Marcellus PA

Utica

Niobrara fracture play

Wattenberg

Permian - Other

Spraberry

Wolfcamp Delaware

Wolfcamp Midland

Bone Spring

Bakken

Eagle Ford

US onshore capex by play, 2012-23

© 2018 IHS Markit

An

nu

al

cap

ital exp

en

dit

ure

($ b

illio

n)

Source: IHS Markit


20


0

50

100

150

200

250

300

350

2000 2005 2010 2015 2020 2025 2030 2035 2040

NACI - Historical NACI - Rivalry Base Case

NACI - Low Case NACI - High Case

North American Capital Cost Index Historical and Forecast Values


The North American Capital Cost Index is forecast to increase significantly

under all three scenarios

Outlook

• Similarly to the Upstream Capital Cost Service and

Upstream Operating Cost Service, the North

American Cost Service tracks a portfolio of North

American projects, both onshore (conventional and

unconventional) and in the Gulf of Mexico

• There was little movement in the markets in Q4 2017,

with the exception of onshore drilling & completions

• For both of these areas, the largest increases came

from the Permian; it is expected that in 2018, overall

costs will increase there nearly 13%

• Canada is showing strong signs of increasing activity

in completions, largely due to the fact that this area is

in a recovery phase following a deep trough

• Turning offshore, costs are only expected to increase

about 1% overall in 2018

21


Technology Trends


Dramatic activity increases, and an improved oil price environment have

resulted in several changes, and challenges for the industry

• Increased demand for equipment, coupled with regulations, and poor quality of cold stacked equipment has

resulted in demand for equipment and parts, and thereby long lead times

• Long lead times in some segments has resulted in a short term rental model as companies wait on equipment

orders but are not willing to have additional downtime or lose production time

• As companies continue to develop their preventative maintenance programs, we expect maintenance issues

and related downtime to decrease, however, at the moment shortages in parts, and maintenance challenges

have also driven demand for extra horsepower on location to compensate

Equipment

• Downturn driven layoffs resulted in a lean workforce, with many “hands” reluctant to come back to the

industry despite improved conditions

• Several companies conducting new hire classes every week, with cannibalization between service

companies rampant

• Newer labor force, and associated training requirements, resulting in lower efficiencies and downtime

• Labor shortages go beyond just oilfield services firms, hauling is another major constraint especially for

hydrocarbons and sand, but manufacturing, and office locations also reporting shortages

Labor

• Frac stages have continued to intensify, with increasing proppant intensities, but recently proppant intensities

appear to be levelling off

• An increased incidence of “frac hits”, interference between frac stages and either production, or drilling, on

adjacent wells may result in increased focus on improved frac design and control, with an impact on intensity

• While cost remains a focus, with an improved oil price environment, there has been a renewed focus in some

of the chemicals and technologies including gelling and diverting agents which could impact proppant and

horsepower requirements

Frac Design

23


Rig counts remain relatively flat through 2018 before returning to growth

after 2019 because of increased activity in most liquids plays

0

200

400

600

800

1,000

1,200

0

50

100

150

200

250

Jan-16 Aug-16 Mar-17 Oct-17 May-18 Dec-18 Jul-19 Feb-20 Sep-20 Apr-21 Nov-21 Jun-22 Jan-23 Aug-23

To

tal L

48 O

nsh

ore

Rig

Co

un

t

Rig

co

un

t b

y p

lay

Chart Title

Total L48 Onshore Rig Count

Bakken

Eagle Ford

Bone Spring

Wolfcamp Midland

Wolfcamp Delaware

Permian Conventional

Wattenberg/Niobrara

SCOOP/STACK

Other Plays

Fluid Type - Dry Gas

Fluid Type - Wet Gas

Fluid Type - Gassy Oil

Fluid Type - Oil

US crude oil production by play, 2012-23

© 2018 IHS MarkitSource: IHS Markit

US land rig count by play, 2016-23

• Although rig counts remain relatively flat in the short term, IHS Markit projects that the number of completed onshore wells will rise from 14,913 in 2017 to 17,955

during 2018

• Well completions will accelerate faster than rig counts as DUC well inventories start to decline, beginning in the second half of 2018 and continuing through 2019


24


Permian expected to increase its share of North American proppant market to

over 40% by 2022; US average proppant mass per HZ well up 15% since 4Q16• 3 key regions – Midland, Delaware and Appalachia are expected to account

for the majority (54%) of proppant demand in North America in 2018

• Proppant demand in the Delaware and Midland is expected to increase 24% and 16% in

2018, respectively

• Canada accounted for 8% of North American proppant demand in 2014 but is expected to

decrease its market share to 4% by 2022 due to decreased activity

• Eagle Ford proppant demand is forecast to be flat in 2018 due to a drilling slow down next

year resulting in a lower number of wells frac’ed

• IHS Markit believes there is room for incremental proppant intensity growth in

the Eagle Ford, Delaware basin and Marcellus, which could lift frac sand

mass/ well estimates higher; but slower rate that previously

Market Share

% mass 2016 2017 2018 2019 2020 2021 2022Eagle Ford 19% 15% 13% 13% 14% 15% 15%

Permian 32% 41% 40% 42% 45% 45% 43%

Appalachia 15% 12% 14% 14% 12% 10% 9%

Canada 5% 6% 6% 5% 5% 4% 4%

Total 70% 74% 73% 74% 75% 74% 70%Source: IHS Markit, IHS Markit FracDB / FracFocus.org, IHS Markit WellIQ © 2018 IHS Markit

25

ProppantIQ 1Q18 / February 2018

86

119105

83

154

188

239

280

316

350

0

50

100

150

200

250

300

350

400

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Delaware Midland Other Permian Eagle Ford Appalachia

Bakken Anadarko DJ Basin Barnett Fayetteville

Haynesville Other US Piceance Canada

Regional proppant consumption (billion lbs)

Source: IHS Markit, IHS Markit FracDB / FracFocus.org, IHS Markit WellIQ © 2018 IHS Markit

0

5

10

15

1Q

11

2Q

11

3Q

11

4Q

11

1Q

12

2Q

12

3Q

12

4Q

12

1Q

13

2Q

13

3Q

13

4Q

13

1Q

14

2Q

14

3Q

14

4Q

14

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

Marcellus Bakken Eagle Ford Delaware Midland US Land Avg.

Average frac sand mass per HZ well (MM lbs)

Source: IHS Markit, IHS Markit FracDB / FracFocus.org © 2018 IHS Markit

Mass/Well =


While horizontal stage counts remain biggest driver for horsepower demand,

frac intensity has driven significant increases

• IHS Markit has adjusted its activity forecast for 2018; stage count (+18%) and

frac demand (+23%) are expected to grow at higher rates than previously

projected

• In 2018, frac intensity is expected to have a greater impact on demand in

comparison to stages frac’ed

• Increasing proppant placement, zipper frac’s, reduced downtime and maintenance are

factors driving the frac horsepower demand

• While proppant intensity is expected to level out, IHS Markit expects that in the short term

horsepower demand will remain high due to frac intensities and equipment conditions but

as predictive maintenance programs continue to develop, demand is expected to flatten

PumpingIQ – 1Q18 / February 2018US frac stage count and frac demand

26

US frac data

2018 2019 2020 2021 2022 2018∆ 2019∆ 2020∆ 2021∆ 2022∆

Rig count 905 1,080 1,214 1,303 1,370 5% 19% 12% 7% 5%

Frac demand

('000)13,541 15,822 17,523 18,833 20,346 23% 17% 11% 7% 8%

Stage count

('000)484 638 742 815 881 18% 32% 16% 10% 8%


0

100

200

300

400

500

600

700

800

900

1,000

0

5,000

10,000

15,000

20,000

25,000

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Frac demand HZ Stages Total stages

US frac demand and stages


Ho

rsep

ow

er

('000)

Sta

ge

co

un

t ('

000)


IHS Markit Customer Care

[email protected]

Americas: +1 800 IHS CARE (+1 800 447 2273)

Europe, Middle East, and Africa: +44 (0) 1344 328 300

Asia and the Pacific Rim: +604 291 3600

Disclaimer

The information contained in this presentation is confidential. Any unauthorized use, disclosure, reproduction, or dissemination, in full or in part, in any media or by any means, without the prior written permission of IHS Markit Ltd. or any of its affiliates ("IHS Markit") is

strictly prohibited. IHS Markit owns all IHS Markit logos and trade names contained in this presentation that are subject to license. Opinions, statements, estimates, and projections in this presentation (including other media) are solely those of the individual author(s) at the

time of writing and do not necessarily reflect the opinions of IHS Markit. Neither IHS Markit nor the author(s) has any obligation to update this presentation in the event that any content, opinion, statement, estimate, or projection (collectively, "information") changes or

subsequently becomes inaccurate. IHS Markit makes no warranty, expressed or implied, as to the accuracy, completeness, or timeliness of any information in this presentation, and shall not in any way be liable to any recipient for any inaccuracies or omissions. Without

limiting the foregoing, IHS Markit shall have no liability whatsoever to any recipient, whether in contract, in tort (including negligence), under warranty, under statute or otherwise, in respect of any loss or damage suffered by any recipient as a result of or in connection with

any information provided, or any course of action determined, by it or any third party, whether or not based on any information provided. The inclusion of a link to an external website by IHS Markit should not be understood to be an endorsement of that website or the site's

owners (or their products/services). IHS Markit is not responsible for either the content or output of external websites. Copyright © 2018, IHS MarkitTM. All rights reserved and all intellectual property rights are retained by IHS Markit.

USAEE Luncheon/April 2018

north american upstream cost & technology trends · 2018-04-26 · • world demand. world...

Documents