dynamic imbalances in gas/ngl/crude flows and consequences, judenfinal.pdf · mckinsey &...

McKinsey & Company | 0

Dynamic Imbalances in Gas/NGL/Crude Flows and Consequences,

CONFIDENTIAL AND PROPRIETARYAny use of this material without specific permission of McKinsey & Company is strictly prohibited

Houston Texas – February 6, 2014

© McKinsey & Company

Mike Juden, McKinsey & Company, Inc., Houston


A perspective on key structural trends in North American gas, NGLs and crude markets

A

C

Supply/demand: To meet expected demand and field declines, gas production to 2020 is expected to be driven by Appalachian gas and LTO associated gas

B Natural Gas: Compared to historical levels, primarily, regional, incremental, gas infrastructure is needed to 2020; with Marcellus moving quickly to exports, Bakkenassociated gas increasingly displacing WCSB gas, and volumes flooding toward Chicago and the Gulf South

E

Crude oil: Crude oil transportation needs are extensive, and the mix between pipelines and rail transport will vary by basin

D

Conversions: Gas transmission conversions are driven by dramatically lower utilizations; repurposed pipelines are expected to have limited near-term gas grid impacts

NGLs: Ethane prices are expected to remain low for years; sufficient ethane export capacity out of Appalachia is expected from 2016 and beyond


Most incremental production is expected out of Appalachia

Niobrara

Cody

Mowry

Gammon

Hilliard-Baxter-Mancos

Excello-Mulky

Fayetteville

Haynesville/Bossier

Woodford/Caney

Barnett

Eagle Ford /Pearsall

Woodford

Barnett and Woodford

Bend

Pierre

Lewis

Hermosa

MancosMarcellus

Devonian

Chattanooga

Conasauga

Antrim

New Albany

Utica

262

Floyd-Neal

Horn River Shale

Montney

MODELED

Cumulative incremental production – Bcfd growth vs. 2013

-2

0

2

2020201920182017201620152014

Southern Supply

Appalachia Area

Rockies Area

WCSB

-6

-4

-2

0

2020201920182017201620152014

0

2

4

6

8

10

12

14

16

18

2016 202020192018201720152014

-2

0

2

2020201920182017201620152014

0

1

2020201920182017201620152014

Midcon Area

NATURAL GAS SUPPLY/DEMAND; CRUDE SUPPLY

A

SOURCE: McKinsey Energy Insights North American Supply Model; Energy Insights, a McKinsey Solution


Boom in North America oil could bring 4-13 Bcfd of incremental associated gas production by 2020 vs. 2011

US associated gas production

Bcfd

1 Assumes LTO wells have 15% gas content (at 6:1 ratio)

A


MODELED

SOURCE: McKinsey Energy Insights North American Supply Model; Energy Insights, a McKinsey Solution; EIA

US oil production under different scenarios

MM b/d


To 2020 our reference case outlook for US demand is for modest growth, increasing from 69 Bcfd (2013) to 83 Bcfd (2020), driven by LNG exports

SOURCE: EIA April 2013 with team adjustments for LNG exports, transportation, power and industrial demand

US natural gas demand outlook – EIA reference caseBcfd

0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

Residential

Commercial

Industrial

Electric power

Gas to liquids

Transportation

Other

LNG Exports

2020

83

2019

81

2018

77

2017

75

2016

74

2015

70

2014

69

2013

69

2012

70

2011

67

2010

65

2.6%

▪ GDP growth at 2.8% / yearOverall:

▪ Energy intensity decline -1.3%

▪ Household growth +1% (116 to 128 MM)

▪ Energy per square foot declines (-0.4%), more than offset floor space growth +1%

▪ Energy-intensive industries take advantage of low natural gas prices

▪ Shipments increase at +3% to 2020

▪ ~8-10 new Ammonia/Methanol plants

▪ Coming off of peak switching in 2012

▪ Natural gas generation grows at 1.6%

▪ ~47 GW of coal retirements

▪ Begins 2016, 0.6 Bcfd; 7 Bcfd by 2020

▪ Lease & plant fuel, pipeline fuel

▪ Vehicle fuel estimated ~1.5 Bcfd by 2020


A

▪ No world-class GTL plants build by 2020


-20

42

Appalachian production is significantly displacing piped imports to the Northeast – pipelines to Appalachia will eventually reverse

SOURCE: Ventyx Energy Velocity; team analysis

1 Production estimated based on flows onto interstate pipelines from production and processing plants 2 Canada includes net imports into NY, VT, NH and ME

Northeastern supply1

Bcfd

Flows at key pointsBcfd

-2024

0

Jul-13

Jan-13

Jul-12

Jan-12

Jul-11

1

2

Jan-10

Jan-11

Jul-10

2

1

0

4

2

0

TGP (Tenn) – OH/PA Border

TETCO - Berne compressor (OH/PA)

Transco – Station 180

Columbia Gulf – Leach KY

TGT (Texas Gas) – Dillsboro compressor

x% 2013 utilization

x% 2012 utilization

-15%23%

52%

34%

16%

-12%

73%

56%

34%

1%

NATURAL GAS TRANSPORT

B

TGT

2013

14.1

Production

REX

Canada2

MA LNG

TGP

TETCO

Transco

Col. Gulf12.9

2011

13.4

2010

12.6

2012

MA LNG

TGP

TETCO

Transco

Col. Gulf

TGT

REX

Canada

Production


Receipts from Bakken are starting to displace Canadian volumes, and as Bakken LTO grows, displacements could reach an additional 2 Bcfd

SOURCE: Ventyx Energy Velocity; SNL; North Dakota Department of Mineral Resources, Oil and Gas Division;team analysis

� Increased Bakkenassociated gas volumes have begun displacing Western Canadian volumes . . .

� . . . driving down Bakken prices towards Canadian price levels

� Up to ~2 Bcfd of incremental Bakkenassociate gas is expected to displace additional Western Canadian volumes . . .

� . . . further pressuring Western Canadian gas prices

Capacity

Basis differentials to HHUSD/MMBtu

0

0.5

1.0

1.5

2.0

2.5

3.0

Aug-13

Feb-13

Aug-12

Feb-12

Aug-11

Feb-11

Aug-10

Northern Border Receipts Upstream of VenturaBcfd

-$2.00

-$1.50

-$1.00

-$0.50

$0

$0.50

Watford City (ND)

Empress

AECO

Ventura (Iowa)

Cheyenne

Bakken

Canada

Rockies

Canadian volumes displacing Rockies volumes from Bison

Associated gas from LTO displacing volumes from Alberta driving ND prices towards AECO/Empress

B



Proposed1 natural gas, interstate pipeline projects –are all regional pipelines, expansions or laterals

SOURCE: Ventyx Energy Velocity, EIA; Company websites and presentations; Trade press; team analysis

1 Includes projects under construction, approved, filed and proposed in all regions. Reversals included as expansions. Does not include any pipeline conversion projects 2 Laterals to storage, LNG, terminals, power plants, other pipelines, LDCs, et

Expansion

Regional

Laterals

Trunklines

Number of projects

65

39

10

16

0

Proposed1 natural gas pipelines

1,331

Miles

3,751

3740

2,046

Bcfd

28

16

9

30

PRELIMINARY

AIM (Algonquin)ConstitutionEagle Ford to MXFlorida SouthEast ConnectionHillabee (Transco)ND to MN (MDU)Nexus Gas (Spectra)Northeast Expansion (TGP)OPEN (TETCO)Pacific Connector (Northwest)Sabal Trail (Spectra)Southeast Exp. (Gulf South)TEAM 2014 (TETCO)Upstate (Millenium)Virginia Southside (Transco)Washington Exp. (Northwest)

Proposed Natural Gas Pipeline Projects


B

Areas of primary activity▪ Appalachian

supply▪ Routes to

NE/Midwest


14132012

2,000

1,800

1,600

1,400

1,200

1,000

800

202524232221201918171615

2,200

2,000

1,800

1,600

1,400

1,200

1,000

800

2,200

SOURCE: IHS; Goldman Sachs, ICIS; Hodson; literature search; team analysis

Existing capacity to consume

US ethane supply outlook

Ethane price will remain low while supply greatly exceeds cracker capacity

to consume ethane

▪ Greenfield – 7 new crackers; >8 mtpaethylene

– (1.5 mtpa with 2017 start)

– (1.5 mtpa in 2018)

– (0.8 mtpa in 2018)

– (1.5 mtpa in 2019)

– (1.4 mtpa in 2019)

– (0.5 mtpa in 2019)

– (1.1 mtpa in 2020)

▪ Mariner East exports to Europe

▪ Unannounced speculative capacity – a second wave of 3 -7 crackers1

▪ Feedstock flexibility (1.3 mtpa) –increases capacity as part of projects to increase cracker flexibility (i.e., switch from naphtha/propane to ethane)

▪ Expansions and restarts (2.2 mtpa) –literature sourced estimates of expan-sions

US ethane prices are expected to remain low for many years because the capacity growth to consume ethane is expected to lag supply growth

1 Includes Braskem (Marcellus), Hanwha, potentially Sabic, etc.

Thousand bbl per day

US cracker capacity to consume (CTC) ethane at “normal yields” ROUGH ESTIMATES

NGLs

C


Mariner East4

Regional consumption

ATEX3

Mariner West2

Bluegrass Pipeline5

SOURCE: McKinsey Energy Insights North America Gas Model; EIA; government and company reports; press clippings; team analysis

KbdMcKinsey Gas Model projection

Forecast ethane/ethylene mass balance in PADD 1 (New England)

1 Team estimate assumes an average of 2.5 GPM for all of Appalachian gas, including 4 GPM for wetter Marcellus and Utica volumes, and 0.9 for remained; Regional consumption assumed to hold steady at 2012 levels (~25 MBPD)

2 Mariner West to commence in late 2013 with 50 MBPD in capacity3 ATEX to commence in 2014 with 125 MBPD in capacity, ramping up to 190 MBPD in 20154 Ethane flows in Mariner East to commence in 2015 with ~50 MBPD in capacity (70% of pipeline capacity)6 Initial capacity is 200 MBPD of NGLs, it was assumed that 50% of this capacity will be ethane 5 ATEX and Bluegrass have designed capacity for expansions of up to 100 MBPD each (Bluegrass assumes 50% ethane capacity out of 200MBPD expansion potential)

0

50

100

150

200

250

300

350

400

450

500

202018161412

Potential expansions6

Regional consumption

�Regional production could be matched by growth in transporta-tion capacity

�ATEX likely to provide the key evacuation route for regional ethane production –thus setting netbacks at Mt. Belvieu minus ~$0.24 per gallon

�Relatively limited exit routes exposes producers to a number of risks

There will potentially be excess C2 evacuation capacity from 2016 onwards

NGLs

C

• Nearly all ethane currently remaining in pipelines

• Long ethane position in 2012 – 2014

• Issue has been on TETCO, because of high Btu gas from Western Appalachia, requiring blending


CRUDE OIL TRANSPORTATION NEEDS

D

1 L48 = Lower 48 states (excludes Alaska & GoM)

Key questions raised

US LTO production1

MM b/d

▪ Where will crude pipeline bottlenecks emerge due to LTO growth?

▪ How long will these pipeline bottlenecks last?

▪ Which routes will see extensive crude-by-rail flows and for how long will these flows continue?

▪ How will the crude mix run in various refining centers evolve?

▪ Which imported crudes will get backed out and in what order?

SOURCE: HPDI, EIA, NEB, Energy Insights, a McKinsey Solution

Rapid growth in LTO production is raising a number of questions for industry players

McKinsey & Company | 11SOURCE: Industry press; team analysis

Hardisty

Chicago

Wood River - PatokaCushing

Houston

Enbridge

Transcanada(Keystone)

Kinder Morgan (Express)

(Pegasus)

Sarnia

Oil Sands

Bakken

W Texas

Centurion

Edmonton

Burnaby/Anacortes

Trans Mountain

GULF OCS

Major bottlenecks

xxxCrude supply

sources

In the last few years the major pipeline bottleneck to refining capacity has been between the Midwest and the US Gulf Coast

“The Brent-WTI

differential … will shrink as the bottleneck at

Cushing eases amid increased pipeline

expansion, including the

Ho-Ho line …

Brent’s premium to WTImay rebound as early as

2014 as the market becomes saturated with

light, sweet crude.”

- Bloomberg, May 2013

“While US shale oil

production is flourishing pipelines are being built,

reversed and expanded to accommodate the

growth of local, abundant

crude supply.”

- Citigroup, Apr 2013


D


Even after the pipeline additions, we see new pipeline bottlenecks developing by 2016


D

Crude pipelines>= 99% utilization> 90%<99% utilization< 90% utilization

2016 NA Crude Pipeline Network

SOURCE: Energy Insights, a McKinsey Solution; EI North American Crude Midstream Model

MODELED SCENARIO


We expect to continue seeing substantial volumes of crude on rail, although the pipe/rail mix will vary by basin


D

SOURCE: Energy Insights, a McKinsey Solution; EI North American Crude Midstream Model

Thousands barrels per day

Canadian oil sands

Crude oil disposition

Bakken

Permian basin

1 Pipeline flows include local transport from basin

MODELED SCENARIO


Energy East(TCPL conversion) – crude oil

Bluegrass PipeineBoardwalk/Williams

JV (NGLs)(TGT conversion)

KM/MarkWestUtica EMG – JV (NGLs)

(TPG conversion)

Eastern Gulf Crude AccessEnergy Transfer

(Trunkline conversion)

Energy Transferconversion

Pony Express conversion (crude)Tallgrass

Southern Trails conversion(crude oil)

SOURCE: Ventyx Energy Velocity; Industry press; company announcements/web sites; team analysis

Major North American natural gas conversion/repurposing projectsE

GAS TRANSMISSION CONVERSIONS


-2

0

2

Pipeline conversions and repurposing projects are supported by low pipeline utilizations

GAS TRANSMISSION CONVERSIONS

2

0

TGT (Texas Gas) – Dillsboro compressor

34%

Trunkline – Mainline North of Tuscola (downstream of conversion)

Pony Express

TGP (Tenn) – OH/PA Border

0.2

0.1

0

TIGT – N Waverley to Col/Kan Border

36%

2

0

97%97%

1%

Trunkline – Mainline Shaw

2

0

Jul-13

Jan-13

Jul-12

Jan-12

Jul-11

Jan-11

Jul-10

Jan-10

35%83%

x% 2013 utilization

x% 2012 utilizationE

TCPL deliveries to TGP – Niagara

TCPL deliveries to Iroquois – Waddington (downstream of conversion)

2

0

Jul-13

Jan-13

Jul-12

Jan-12

Jul-11

Jan-11

Jul-10

Jan-10

1

2

1

2

3

3

4

5

4

5

6

6

7

7

1.0

0

-1.0

-33%-4%

16%

23%

-12%

46%46%

SOURCE: Ventyx Energy Velocity; Industry press; company announcements/web sites; team analysis


Pipeline and Midstream Operations Roundtable guiding questions

2

1 Natural Gas: What is the expected impact of the projected, dramatic increases in Marcellus and Utica production on the regional and interstate pipeline grids? Other basins (e.g., Permian/MidContinent)?

4

Crude oil: How to you see crude pipelines developing vs. rail transport for crude? Operational issues?

3

Conversions: Do you see flow or operational issues associated with gas pipeline conversions (e.g., Marcellus to Gulf, Midcontinent, South Texas, West)?

NGLs: Will there be sufficient NGL pipeline capacity in the Marcellus to maintain pipeline quality gas for the gas pipeline grid, or will drilling be restricted by lack of liquids take-away capacity? Other basins (e.g., Eagle Ford, Bakken, and Permian)? Operational issues?

5 Equipment: Do you see changes in near-term equipment purchases now vs. this time last year (what has changed or is expected to change and why)?


Dynamic Imbalances in Gas/NGL/Crude Flows and Consequences,

CONFIDENTIAL AND PROPRIETARYAny use of this material without specific permission of McKinsey & Company is strictly prohibited

Houston Texas – February 6, 2014

© McKinsey & Company

Mike Juden, McKinsey & Company, Inc., Houston


APPENDIX


Energy Insights brings together McKinsey’s analytical models, benchmarking capabilities and proprietary insights

▪ Enables fact-based decisions for commercial due diligence, strategic planning, and business development through expert professionals and proprietary models

Diligence and Business Intelligence

Market Analytics

▪ Informs strategic decision making and performance improvement by delivering robust forecasting and advanced market analytics on global crude, refined product, and natural gas markets

▪ Analytical services

▪ Market Overviews –reports & subscriptions

Bench-marking

▪ Performance benchmarking

▪ Helps drive asset productivity and performance by providing in-depth quantitative benchmarks, objective assessments of comparative performance and practices, and actionable insights into major areas for improvement

A McKinsey Solution

▪ 35+ team of dedicated experts

▪ Proprietary methodologies, insights,

and data on global markets and

supply chain

▪ Suite of integrated models and new

online technologies

▪ 20 year track record and multiple

offerings in benchmarking

▪ Focused Diligence capability

▪ Linked to McKinsey’s global network

of energy expertise

▪ Commercial due diligence

▪ Micro-market analysis

▪ Bespoke analysis

SOURCE: Energy Insights, a McKinsey Solution


Market Analytics maintains an integrated and granular suite of models –including the NA Supply Model and the NA Oil Midstream Model

N. America Supply Model

Global Gas Model

(incl. LNG)

Global Energy

Perspective

Global Liquids

Supply Model

Offshore SD Rig model

Global Downstream

OilDesk

Midstream and Downstream

Refining market conditions

Global oil supply

Upstream

Gasdemand

NA gas supply

NA oil supply

Petroleum products demand

Global gas supplyOFSE

Demand

Global oil supply

N. America oil midstream


US Onshore SD Rig model

FPSOmodel

1

2


The NA Supply Model incorporates all major sources of NA Gas, Oil, & NGL production into a single integrated analytical tool

NA NGL production

NA Oil production

NA Gas production

NA Supply Basins

Gas

Oil

Gas & Oil

NA NGL cost curve

NA Oil cost curve

NA Gas cost curve

1,5001,3001,100900700500300100 1,6001,4008006004002000 1,000 1,200

Conventional

CBM

Tight

Shale

Costs, reserves, and production profiles for 118

basins

1. NORTH AMERICA SUPPLY MODEL


1


It comprises of 5 interdependent modules that together generate the North American supply outlook

1 Does not cover Alaska, Gulf of Mexico offshore and Canadian oil sands

Monthly to 2030

Supply/demand and pricing

Well economics

Drilling and production constraints

Rig count decision

New production

Vintage production

NA Oil & Gas Supply Model1

▪ Marginal gas basin determines gas price

▪ Uses basin IP and decline

▪ Gas basin rigs scaled to meet gas demand

▪ Considers total NA rigs and basin-specific constraints

▪ Uses NPV10/ CAPEX to assign rigs (oil and gas)

▪ Calculates NPVfor each basin

well type

1. NORTH AMERICA SUPPLY MODEL


For any questions on our NA supply model contact:

Mike Juden([email protected]) Katie Jolly ([email protected])

1


We have created an integrated NA crude market tool to understand the impact of new production on netbacks and refinery crude slates

▪ Over 150 refineries in US and Canada (>95% of total NA capacity)

▪ Refinery level optimization to capture relative value of crude grades

▪ ~120 domestic supply basins, including new LTObasins

▪ 20 grades of crude oil -domestic and international

▪ All major crude oil pipelines in US and Canada

▪ Alternate modes of transport including rail, barge, truck

Midstream Downstream (Refining)Upstream (Supply)


2. NORTH AMERICA OIL MIDSTREAM MODEL

For any questions on our midstream model contact: Mike Juden ([email protected]) or Anant Shankar ([email protected])

2

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