Tutorial on WTI & Brent

North America Crude OilWTI-Brent Teach-In

March 28, 2013

NORTH AMERICA CRUDE OIL

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M O R G A N S T A N L E Y R E S E A R C HGlobal

Morgan Stanley & Co. LLC

Adam Longson, CFA, [email protected]+1 212 761 4061

Chris [email protected]+1 212 761 6005

Alan [email protected]+1 212 761 3266

M O R G A N S T A N L E Y R E S E A R C H

2

North America Crude OilMarch 28, 2013

North America Crude Oil Teach-In: Overview

How Key US Crudes Price and Why

Implications for Commodities and Equities

Background on the Problem

Appendix


3


Historically, North American Crudes Traded Off Pipeline Tariffs

Crude Oil Differentials: Cost of moving the marginal barrel typically sets relative crude pricingThe cost of transporting the marginal barrel tends to set the price differential between similar quality crudes.

On the water, differentials are mostly the cost of a tanker between the source of the crude and its end market. On land, pipeline tariffs dictate prices.

If pipeline capacity is insufficient, differentials are set by higher costs modes of transport like barge, truck and rail.

That’s the situation today in North America. If those higher cost modes don’t have enough capacity to clear the market, differentials widen to shut-in levels.

4 Key Questions to understand when assessing crude oil differentials:1) What is the marginal barrel for a given crude oil benchmark? 2) Where is that marginal, highest cost barrel headed (i.e. what is the end market customer)?3) How is the marginal, high cost barrel getting to its end market (tanker, pipeline, rail, etc.)?4) How much does that marginal barrel cost to transport relative to alternative sourcing options for that customer?

-8

-6

-4

-2

0

2

4

6

8

2000 2002 2004 2006 2008 2010 2012

LLS Olmeca Saharan Blend

Source:

Company Data, CAPP, Morgan Stanley Equity Research estimates

-50

-40

-30

-20

-10

0

10

20

Jan-08 Oct-08 Jul-09 Apr-10 Jan-11 Oct-11 Jul-12

WTI-LLS WTI Midland-Cushing WCS-Maya Syncrude-WTI

Seaborne Crudes Tend to Trade Within A Range—Determined by Freight Cost

Source:

Bloomberg, Morgan Stanley Commodity Research

(Key light seaborne crude oil differentials vs. Brent) (Key North American crude oil differentials)


4


2

Refineries

RefineriesRefineries

MIDLAND

HOUSTON

ST. JAMES

PATOKA

CHICAGO METRO

CUSHING

Infrastructure Not Configured for New Crude Flows, Particularly Out of the North

Infrastructure Designed to Handle West Texas and Gulf Coast Originations…

Source: Purvin

& Gertz,Morgan Stanley Commodity Research

500

700

900

1,100

1,300

1,500

1,700

1,900

2,100

2,300

2,500

2000 2002 2004 2006 2008 2010 20124,000

4,500

5,000

5,500

6,000

6,500

PADD2 Canada Imports + Midwest ProductionPADD 3 to 2Gulf Coast Imports (RHS)

…But Flows Shifting From South to North With Rising Bakken/Canada Production

Source: DOE, Morgan Stanley Commodity Research

(Left axis: kb/d; right axis: Gulf Coast imports, kb/d)

• US pipeline infrastructure was designed to handle crude flows moving North from the Gulf. Historically, US refiners sourced crude from the southern US (the Mid-continent, West Texas and the US Gulf Coast) to feed refineries in Texas, Louisiana and the Midwest

• Surging Canadian and Midwest production has reduced the need for

Gulf Coast imports and transfers north from the South. Midwest refineries are increasingly becoming self sufficient, reducing the need to move crude north from West Texas and the Gulf.

• Crude must now flow south from the Midwest, against the natural design of pipeline infrastructure.

The old pipeline regime is being reversed, but this takes time. New pipelines are coming but are lagging demand. These infrastructure challenges are creating bottlenecks and forcing the use of temporary higher cost transportation alternatives to clear new crude volumes, which manifests in wider differentials to cover the higher cost of bringing the marginal barrel to market.

(traditional US pipeline flows)


5






Appendix


6


Key US Crude Benchmarks: Quality Matters for Crude Oil Differentials

Source:

CAPP, Morgan Stanley Commodity Research

• Regularly quoted light and heavy crude oil benchmarks are listed.

• Light and heavy crudes have very different properties and customers and trade at different prices.

The heavier a crude means the more viscous it is, which is typically associated with a higher sulfur content as well.

• Light crudes cost less to process and therefore tend to be more valuable, but they also typically generate a higher gasoline yield.

• Heavy crudes are more expensive to process and require special equipment.

Heavy crude oil also requires more power to move through pipelines, which tends to result in lower pipeline capacity on heavy crude lines.

• Crude quality matters when assessing differentials. In North America, you generally want to assess heavy crude benchmarks against other heavy crudes and light crude benchmarks against other light crude oils.


7


Bakken: Higher Cost East Coast Rail Is Now The Clearing Barrel• The Bakken is reliant on rail to clear production and will be for some time. Pipeline infrastructure out of the Bakken and surrounding regions

has been insufficient to support the magnitude of production growth in the region for some time. Since early 2012, substantial investment in rail terminals has allowed the Bakken to avoid these bottlenecks and tap new markets first on the Gulf Coast, and now the East and West Coast. While new pipeline projects are scheduled for the coming years, they do not appear sufficient to fully clear Bakken production.

• However, the clearing barrel for the Bakken has shifted to rail to the East Coast with material implications for pricing. As production has grown, the Bakken has shifted from pricing off pipeline economics to Gulf Coast rail economics to US East Coast rail economics today. The need to support high cost East Coast rail economics, with the marginal move involving rail and barge, implies a $20-30/bbl differential vs. the delivered cost of an imported East Coast barrel, which is typically not Brent.

• Even if Cushing clears, it should have little impact on Bakken pricing.

As long as Bakken producers need to support East Coast rail economics, prices cannot rally above the cost of an imported barrel less transport economics.

Bakken to Rely on Rail to Keep Production Debottlenecked

Source:

Bloomberg, Genscape, Morgan Stanley Commodity Research

(kb/d)

Source:

Company Data, Morgan Stanley Commodity Research estimates

x

NORTHSEA

Bakken

Clearbrook

Chicago

WESTAFRICA

Albany

Philadelphia

$1-2/bblTanker rates

$13-16/bblMarginal rail +

transload

$-1 to +4/bbl

differential

$3-5/bblbarge +

transloading

$4-8/bblgathering+ trucking/

transloading + leasing

USGC$12-15/bblMarginal rail0

400

800

1200

1600

2000

Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14

Pipeline Takeaway Rail Takeaway Bakken Production

Marginal Clearing Barrel to East Coast Costs $20-30/bbl from the Wellhead


8


2

NORTH SEA

CHICAGOMETRO

Clearbrook

CUSHING

$20-25/bblMarginal rail +

truck/barge to the East Coast

$1-2/bblTanker rates

Bakken

~$3/bblPipeline into

Cushing

EAST COAST

$2+/bblpipeline +

congestion

WTI: Marginal Barrels Come from the North And Dictate Pricing• WTI is currently pricing off the marginal barrel flowing into Cushing from the North, which is dictated by exit capacity from Cushing.

Spare capacity into Cushing exists via both pipeline and rail, but is not being maximized given congestion. WTI is pricing off whether to either incentivize greater inflows into Cushing on these various routes from the North.

• With additional takeaway capacity, WTI is now pricing to support

greater pipeline inflows.

At $20/bbl, WTI-Brent was pricing to slow pipeline inflows into Cushing. However, with Seaway now offering greater outflow capabilities, Cushing can now accept greater inflows. Sending barrels into Cushing via pipeline from the North costs a few dollars, which implies WTI-Brent should be in the mid-teens to cover this incremental cost.

• The next marginal barrel would be rail into Cushing = Low-teens WTI-Brent.

Rail volumes into Cushing used to run as high as 60 kb/d, but are now gone as economics ($8-9/bbl) are no longer supported. If new pipelines drain enough volume from Cushing, rail could be required again, which would push WTI-Brent to the low-teens. We see this as a possible 3Q13 event.

• The XL Gulf pipeline will finally clear Cushing in 4Q13 = $6-10/bbl.

At that point, WTI will price off the Gulf Coast with WTI-LLS at $6/bbl based on pipeline economics. WTI-Brent will simply be $6 + the amount of any discount in LLS-Brent due to the glut of light crude in the Gulf.

Transport Economics and Differentials Tend to Dictate Cushing Flows

Source:

Bloomberg, Genscape, Morgan Stanley Commodity Research

(marginal capacity into Cushing by cost and impact on WTI-Brent)

Opening Pipeline Arbs

Should Justify WTI-Brent In the Mid-teens into 3Q13

Note: $20-25/bbl is from the rail terminal. Source:


Cost Marginal BarrelCapacity

(kb/d)

Cum. Inflow (kb/d)

Implied WTI-Brent

($/bbl)LOW Limited Inflows 0 160 ~$20+

Spearhead 190Keystone - Cushing 160 350Rail - Hawthorne 90 440 ~$12

HIGH Barge Unwind 60 500 $7-9Cushing Clear $6+

~$15


9


Imports

ST. JAMES

PATOKA

CUSHING

HOUSTON

GoMLight

LLS: Gulf Coast to Be Oversupplied, But LLS More ProtectedThe Gulf Coast is at risk of being oversupplied with light crude

oil. As US shale production grows, the US is quickly displacing all its light crude imports in the Gulf. The US also restricts US crude oil exports, which means the US could end up with too much light crude oil and the Gulf relative to the natural level of demand. That should cause prices to discount to turn off imports, discourage flows, or incentivize demand.

Greater light flows will pressure the Gulf Coast light crude oil

prices, especially around Houston.

XL Gulf will be forced to move primarily light crude barrels given a lack of heavy capacity into Cushing before mid-2014, which should easily than displace all light crude imports. Given the size of XL Gulf, the impact could be magnified early on as elevated inventories at Cushing are drained into the Gulf Coast. But there are offsets come 2014.

The market is too bearish LLS, which is becoming a poor benchmark for the Gulf.

As a light crude importer, most regions of the Gulf Coast used to price similarly to support imports. As imports are displaced and flows move South, that is no longer the case. St. James is a difficult market to reach, limiting the potential impact on prices, and there are numerous potential mitigating measures that would prevent a significant discount from developing.

Growing US Production Displacing Light Crude Oil Imports in the Gulf…

Source:

EIA, Morgan Stanley Commodity Research

(Gulf Coast light crude oil imports by state, kb/d)

…But LLS Is Relatively Insulated from Oversupply in Houston

Source:


-

200

400

600

800

1,000

1,200

1,400

Jan-

10

Apr-

10

Jul-1

0

Oct

-10

Jan-

11

Apr-

11

Jul-1

1

Oct

-11

Jan-

12

Apr-

12

Jul-1

2

Oct

-12

TX LA Other Gulf Coast


10


WTI-Brent and LLS-Brent Are Not Purely A Bet on US FundamentalsThe US does not import Brent.

Investors have focused on light crude differentials vs. Brent (LLS, WTI, Bakken, etc.) as indicative of evolving North American fundamentals and where US crudes must price to displace imports. However, the US has not imported a barrel of light crude oil from Europe since June 2012. The only North Sea crude imported into the US today is some condensate from Norway to the East Coast.

Imported crudes represent the barrel that needs to be displaced that differentials must match.

In reality, many North American crudes must price against the true imported barrel, not Brent. East Coast light crude imports are from West Africa, Latin America, Canada and the FSU. Similarly, Gulf Coast light crude imports are from Mexico, Venezuela and West Africa. As a result, rail arbs for Bakken are not directly linked to Brent pricing. Similarly, LLS-Brent can see substantial volatility without impacting Gulf Coast imports.

Import prices are only loosely associated with Brent through global differentials and arb opportunities.

If Brent trades well above or below these crudes (as it does now), it can result in a significant disconnect between US crude pricing and Brent. These disparities can have a material impact on key differentials such as WTI-Brent, LLS-Brent and Bakken-Brent.

An Improper Benchmark: The US No Longer Imports Brent

Note: 35-40 API crudes; Source:

EIA, Morgan Stanley Commodity Research

(US European light crude imports, kb/d)

Light Crude Differentials vs. Brent Can Be Volatile

Source:

Bloomberg, Morgan Stanley Commodity Research

(Key light crude oil differentials vs. Brent)

-

50

100

150

200

250

300

Jan-

10

Apr-

10

Jul-1

0

Oct

-10

Jan-

11

Apr-

11

Jul-1

1

Oct

-11

Jan-

12

Apr-

12

Jul-1

2

Oct

-12

Light

-$10

-$8

-$6

-$4

-$2

$0

$2

$4

$6

Jan-11

Apr-11

Jul-11

Oct-11

Jan-12

Apr-12

Jul-12

Oct-12

Jan-13

US: LLS NG: Qua Iboe ALG: Saharan BlendSA: Arab Extra Light MX: Olmeca


11






Appendix


12


Base 1Q 2Q 3Q 4Q Full Year2013 -$19.00 -$15.00 -$13.50 -$11.50 -$14.502014 -$9.50 -$9.50 -$8.00 -$7.00 -$8.50

Bull2013 -$21.50 -$21.50 -$18.50 -$14.50 -$19.002014 -$12.50 -$12.50 -$11.00 -$10.50 -$11.50

Bear2013 -$17.50 -$10.00 -$7.00 -$4.50 -$10.002014 -$5.50 -$5.50 -$5.50 -$5.50 -$5.50

WTI-Brent

-$4.50

-$4.00

-$3.50

-$3.00

-$2.50

-$2.00

-$1.50

-$1.00

-$0.50

$0.00

3Q13 4Q13 1Q14 2Q14 3Q14 4Q14

LLS-Brent Forw ard Curve MS Base

The Commodity View: Some Takeaways for North America Crude Oil in 2013Differentials will not return to historical levels

• The structural realignment of crude flows in the US has permanently altered pricing and differentials

• We see WTI-Brent settling at $6/bbl long term with LLS-Brent at parity, which is still advantageous for US refiners

Light crude differentials are set to narrow in 2013, particularly WTI-Brent

• Narrower diffs are bullish for Permian and Midcon producers.• That said, WTI-Brent may be getting ahead of itself and won’t

reconnect until 4Q13 when XL Gulf comes online• Our base case assumes a small disconnect in LLS-Brent by year-

end, but that is conservative and should be resolved by mid-2014.

Bakken will still price off East Coast rail• East and West Coast refiners will increasingly gain access to

advantaged crude and could see the greatest EPS positive revisions.

Canada will be the story for 2014• The US will see a notable rise in light crude exports to Canada in

2014, both via pipeline and exports out of the Gulf. • WTI may end up pricing off of Eastern Canada, and exports should

alleviate oversupply problems in the Gulf.• WCS differentials should see significant relief in mid-2014 with the

Flanagan South pipeline, which is bullish for oil sands producers.

Key Commodity Trades:• LLS-Brent could be at parity by mid-2014

vs. a forward market of -$4/bbl in mid-2014.

WTI-Brent Should Fall To $6-10/bbl in 4Q

Source:

Bloomberg, Morgan Stanley Commodity Research estimates

(WTI-Brent quarter average price forecast,$/bbl)

The Market Is Too Bearish LLS-Brent

Source:

Bloomberg, Morgan Stanley Commodity Research estimates

(LLS-Brent, $/bbl)


13


Evolving North America Differential Story: An Alpha PlaygroundPlenty of alpha opportunities within the differential story:

Equities offer more opportunities to play the evolving North American crude oil story than commodities. There are a number of ways to play the differential story on a thematic basis, but also on a company specific basis.

North American differential story here to stay, but will continue to evolve.

The resurgence in North American oil and gas production is one of the great themes in the market today, and it will take several years to play out. The story and differentials will continue to change over time with new pipelines, plays and production growth that will recast the landscape of winners and losers. Understanding and forecasting how the story evolves should create significant investment opportunities.

Key Crude Oil Basins: Relative Pricing Revision in 2013

Thematic Framework and Potential Ways to Play Differentials1. Industry Exposure to Wider Differentials

2. Geographic or Crude Exposure (i.e. by basin) by Company• Thematically, northern geographies typically face wider differentials • Changes in differentials for various plays lead to earnings revisions

3. Individual Consumers Crude Appetite and Cost of Sourcing

Industry Impact Comment

Refiners ▲ Product prices set by Brent. Refiners can process cheap North American crudes and capture the margin benefit.

Midstream ▲ Wider dif ferentials indicate grow ing production and a need for greater pipeline capacity or investment.

Transports ▲ Wider dif ferentials and grow ing production support alternative modes of transportation, like crude-by-rail.

E&P ▼Typically sell closer to the marginal price. Wider dif fs w eigh on FCF and returns. Infrastructure constraints associated w ith w ider dif fs also limit production grow th.

Integrated ▬ Truly integrated models are hedged. Cheaper crudes w eigh on E&P realizations, but result in better ref ining realizations.

Oil Services ▼ / ▬Wider dif ferentials mean low er prices and less FCF for E&P capex. Associated infrastructure constraints also slow drilling.

Source:

Morgan Stanley Commodity Research

Industry Exposure to Wider Crude Oil Differentials

1.

Permian

2.

Midcon: MS Lime, Granite Wash, etc.

3.

Syncrude

4.

WCS

5.

Bakken

6.

LLS

7.

Eagle Ford

PositiveRevision

NegativeRevision


14


$95

$100

$105

$110

$115

$120

Oct-12 Nov-12 Dec-12 Jan-13

Bakken - Gulf Bakken - East Coast LLS WAF

0

2

4

6

810

12

14

16

18

20

Enb

ridge

/M

usta

ng/X

OM

Enb

ridge

/S

pear

head

/S

eaw

ayTS

OA

naco

rtes

PB

F's

Del

City

TSO

N. C

alifo

rnia

TSO

S. C

alifo

rnia

PS

X B

ayw

ay

US

GC

Rai

l

Phi

lade

lphi

a

Alb

any

Pipeline

Wide Range of Bakken Rail Prices, with PBF Leading East Coast Rail Economics

Company Specific Opportunities Are Prevalent: Transportation Costs Vary And Can Lead to A Competitive Advantage

Source:

Company Data, Morgan Stanley Commodity Research

Transportation Advantages Can Create Meaningful Value

Source:

Bloomberg, Company Data, Morgan Stanley Commodity Research

( US Gulf Coast estimated average delivered price at St. James by month, $/bbl)

Product prices trade off of Brent assuring relatively similar revenue for refined products in a given region.

However, the cost of crude and processing varies dramatically between regions and refiners.

The cost of transportation varies across customers creating opportunities for alpha capture.

The cost to move the marginal barrel sets the differential, but differentials do not represent the average cost to access a given crude. Many customers can access crude for cheaper prices through other means. Even in markets where pipeline capacity is limited, some customers can avoid bottlenecks with contracts for committed pipeline capacity, which provides a competitive advantage. Uncovering these advantages can lead to significant alpha capture.

Example: The impact of an LLS disconnect is overstated. Many Gulf Coast refiners are already receiving advantaged crude, which diminishes the importance of LLS for Gulf Coast realizations. For example, Bakken is now pricing to support higher cost East Coast rail economics, but Gulf Coast rail is still ongoing, creating an arbitrage opportunity for refineries in Louisiana relative to East Coast rail and LLS.

(Bakken crude by rail cost, $/bbl)Marginal

CostArb opportunities


15






Appendix


16


Key Debates Related to Crude Differentials for both Commodities and Equities• Timing of new infrastructure (pipeline and rail) and the impact of various differentials

• How will the marginal cost of transportation change for various crude oil basins?

• When will WTI pricing reconnect with the Gulf Coast?

• Will the BP Whiting refinery return early and run crudes out of Cushing?

• Will new West Texas pipelines in 2Q and 3Q be sufficient to drain inflows and clear Cushing?

• Will an oversupply of light crude oil in the Gulf result in significantly wider differentials?

• How far below Brent will Gulf Coast light crude oil prices (esp. LLS) trade?

• What is the outlook for Canadian crude oil differentials, particularly challenged heavy crude oil (WCS)?

• What is the next catalyst and where do WCS differentials trade?

• Will enough pipeline capacity be built to allow Canada to reach its long term production goals?

• What is the opportunity for crude by rail and how long can it last?

• How much will US production grow and what does that mean for pricing?

• Is there an ability to absorb all of this light crude oil?

• Will US production growth result in much lower global prices?

• What does all this production mean for crude oil differentials long term?


17


US and Canada Pipeline Map

Source: Canadian Association of Petroleum Producers


18


US Oil and Gas Shale Plays

Source: EIA


19


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