West Texas Intermediate Crude Oil Futures

Summary

The long-term success of physically delivered futures for West Texas Intermediate (WTI) and other acceptable

grades of light, sweet crude oil at Cushing, Oklahoma has proven so successful in building and maintaining crude oil

inventories at Cushing as to affect the term structure of WTI futures as well as key spreads between WTI and

Louisiana Light Sweet (LLS) at the U.S. Gulf Coast. These effects are particularly noticeable in the late winter as

the U.S. refining system goes into its annual “turnaround,” or maintenance cycle.

Markets treat these short-term effects as opportunities for long-term investment. Once this are made and new

pipelines are completed, WTI at Cushing will resume its role as the unquestioned price benchmark for the North

American crude oil market, and for good reasons.

Not only does WTI serve as a benchmark for mid-continent refineries and for Canadian crude oil moving south into

the U.S., an increasingly important source of supply, it serves as a spreading benchmark for high-sulfur West Texas

Sour (WTS) crude oil and thus for other sour crude oil streams coming into the U.S. Gulf Coast.

Waterborne cargoes priced off the North Sea Brent-Forties-Oseberg-Ekofisk (BFOE) benchmark can be and are

directed elsewhere in the Atlantic Basin to the highest price. Unlike a pipeline-delivered crude oil whose destination

is known from the moment it leaves the wellhead for a pipeline gathering system and whose supply is predictable

both in quantity and in rate of delivery, Brent-basis cargoes have a higher and more unstable volatility of price and

volume.

The depth and liquidity of physically delivered WTI remain unmatched, especially during periods of supply

uncertainty. Moreover, its projected stability of supply exceeds that of the BFOE supply stream for Brent futures;

this allows for it to serve as the basis for a wide array of long-term strips and swaps and for various financial

instruments.

Pipeline Vs. Waterborne Markets

Any comparison of WTI and Brent as crude oil benchmarks requires an understanding of the differences between

pipeline and waterborne markets. They are completely different. BFOE crude oils produced in the U.K. sector of

the North Sea are delivered by undersea pipeline to the terminal at Sullom Voe for transshipment and depend on a

conceptual marker called “Dated Brent” and an actual cash market, the 21-day BFOE index, for pricing.

Dated Brent refers to a cargo loading within the next 10-21 days, or 23 days if the trade date is a Friday. The 21-day

BFOE index is based on the cheapest crude oil to deliver against the Brent futures contract and is used to price the

Brent futures market on a daily basis and to settle the Brent futures contract on a cash basis.

A market for the contracts-for-differences (CFDs) between Dated Brent and BFOE crude oils in the 21-day BFOE

market determine, in a very circular turn, the assessment for Dated Brent. The CFDs’ prices are influenced by the

forward curve of the Brent futures market. If the forward curve is in backwardation, the condition prevailing when

futures trade at a discount to cash, the CFD is a positive value. If the forward curve is in contango, the condition

prevailing when futures trade at a premium to cash, the CFD is a negative value.

Dated Brent thus is not an actual spot market; it is a short-term forward market whose level is affected by CFDs, the

forward curve of Brent futures and short-dated cash market options. Many of the crude oils identified as being

benchmarked to Brent are traded on a basis to Dated Brent.

WTI and other crude oils are delivered to Cushing via pipelines. These have defined capacity, can flow in only one

direction at a time and seldom are reversed. While a waterborne cargo arrives all at once and frequently is priced

for final delivery on a formula basis involving the days before, during and after the bill-of-lading date, pipelines

deliver crude oil at a constant rate and can be priced either continuously or over a strip of dates.

This “ratable” delivery system for pipeline markets brought scheduling considerations to prominence. A crude oil

producer needs to nominate space on a pipeline for next-month delivery; this is why crude oil deliveries are set in a

window between the 25th day and the end of the current month and why, in turn, the WTI futures contract expires on

the third business day prior to the 25th day of the month.

2

The combination of physically delivered futures and the structure of the pipeline market opened the North American

crude oil market up to the range of strategies we see today. These futures allowed for fixed-price deliveries over the

next month. Previously, prices were “posted” by refiners for each day during the delivery month. This posting or

“posting-plus” market still exists and is vital in setting the floating leg for crude oil swaps whose fixed leg has been

determined by WTI futures.

The physical delivery aspect of WTI also cements the basis, or spread between physical crude oil and the futures

contract. Basis includes physical and financial costs of storage and transportation, differentials produced by location

and grade and the time to the futures’ expiration. Basis convergence toward zero at expiration is a feature of the

WTI market that is not duplicable in the Brent market due to the circular nature of the contract’s pricing.

The ability to use futures to price and deliver a fixed volume of crude oil delivered at a fixed price over a fixed

period of time is the key feature of the North American crude oil market. While other crude oil futures markets can

and do serve as price indicators, only the physically delivered WTI futures allow for seamless delivery of a fixed

volume of crude oil to a specific place over a specific period of time and at a specific price. It also allowed for other

grades of crude oil, including sour streams in the North American market to be quoted as a differential to WTI based

upon differences in location and refining values. A waterborne cargo market simply cannot meet these criteria of

delivery place and time. This does not even mention the potential for production and shipping disruptions during the

Gulf of Mexico’s hurricane season.

The discussion below is enabled by one feature of the WTI market too often taken for granted, the richness and

timeliness of the data available. U.S. inventory data are available on a next-week basis as are statistics on refinery

runs and imports. The Department of Energy’s Energy Information Administration provides a wealth of data at a

variety of frequencies, nearly all of which are of value to the industry and to traders. No comparable system of

detailed and timely data is available for the world of non-U.S. petroleum.

The Cushing Storage Market

The physical delivery mechanism has allowed for the growth of the Cushing storage market and indeed for the

entirety of PADD II (Petroleum Administration Defense District). PADD II includes the Mid-Continent, Midwest

and East North-Central regions. Ironically, this growing storage market is the very factor affecting the spread

between crude oil priced at Cushing and, say, the U.S. Gulf Coast. The storage market is based on cash-and-carry

arbitrage and works quite simply:

1. Go long a futures contract for next-month delivery; say January 2011;

2. Go short a futures contract in the succeeding month of February 2011;

3. Take delivery of the crude oil during January 2011;

4. Pay the physical costs of storage, pump-over, insurance and other charges;

5. Account for the cost of capital;

6. Hold the crude oil in storage, hedged by the short February futures contract; and

7. As the February contract approaches expiration, either deliver the crude oil in storage against the contract

or repurchase the short February contract and sell March or some other month whose price will allow you

to cover the costs of storage.

The threshold discount or level of contango required for inventories to be build changes continuously. As interest

rates rise, a greater discount is needed to cover the financing cost, and vice-versa for falling interest rates. As

storage levels rise, each incremental unit and class of storage requires a greater discount. A simple tank at Cushing

can be filled and hedged at a smaller cost than can a pipeline, a barge, remote tankage or a waterborne vessel

moored off the U.S. Gulf Coast. As storage levels increase and as incrementally more expensive storage facilities

are brought on-line, contango levels move in a stairstep fashion in response.

The snapshot below uses actual NYMEX settlement data for Monday, April 11, 2011 and calculates the annualized

convenience yield of the forward curve at a $0.65/barrel/month storage charge and current LIBOR cost of capital.

As these convenience yields are positive at these numbers, refiners would find it unprofitable to add to storage; a

negative convenience yield is required.

3

NYMEX Forward Curve And Convenience YieldApril 11, 2011

$109.50

$109.75

$110.00

$110.25

$110.50

$110.75

$111.00

$111.25

$111.50

$111.75

$112.00

Ma

y-1

1

Ju

n-1

1

Ju

l-1

1

Au

g-1

1

Se

p-1

1

Oct-

11

No

v-1

1

De

c-1

1

Ja

n-1

2

Fe

b-1

2

Ma

r-1

2

Ap

r-1

2

Ma

y-1

2

Contract Month

Cru

de

Oil F

utu

res

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%

4.5%

5.0%

5.5%

6.0%

6.5%

7.0%

7.5%

Co

nv

en

ien

ce

Yie

ld

Price

Convenience Yield

$0.65 / Barrel / Month Storage

Source: Bloomberg

National inventories have risen and fallen in response to the simple contango displayed below, simply the spread

between second- and first-month WTI futures divided by the second-month future itself. National inventory levels

trended lower from the early 1990s into 2003 as just-in-time inventory management became popular. National

inventory levels trended higher from 2003 onwards as the term structure of WTI futures moved into more frequent

contango.

National Inventories Rise And Fall With WTI Contango

260,000

270,000

280,000

290,000

300,000

310,000

320,000

330,000

340,000

350,000

360,000

370,000

380,000

390,000

400,000

19

83

19

84

19

85

19

86

19

87

19

88

19

89

19

90

19

91

19

92

19

93

19

94

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

Inv

en

tori

es

, T

ho

us

an

d B

arr

els

-14.0%

-11.5%

-9.0%

-6.5%

-4.0%

-1.5%

1.0%

3.5%

6.0%

8.5%

11.0%

13.5%

16.0%

18.5%

21.0%

[Mo

nth

2 -

Mo

nth

1]

/ M

on

th 2

Inventories

Simple Contango

Source: Bloomberg

If we isolate storage at PADD II and at Cushing itself, a more dramatic pattern becomes apparent. Inventory levels

shifted higher during the financial crisis of late 2008 and have remained at this higher level ever since. Moreover,

these inventory levels respond to changes in the simple contango of WTI futures; as contango rises or falls,

inventories follow by four weeks on average. This is a highly efficient market in operation.

4

The profits available from inventory storage at Cushing predictably have attracted new storage capacity into the

market. An additional 14 million barrels of capacity are planned for 2011. This would bring capacity up toward 65

million barrels. The larger storage capacity means contango levels do not have to move toward the exaggerated

discounts seen in early 2011 to bid successfully for storage capacity. This will narrow the differential between

Cushing and the U.S. Gulf Coast and Atlantic Basis Brent Blend markets.

PADD II Inventories Respond To Crude Oil Forward Curve

50,000

60,000

70,000

80,000

90,000

100,000

110,000

Mar-

04

Jul-04

Nov-0

4

Mar-

05

Jul-05

Nov-0

5

Mar-

06

Aug-0

6

Dec-0

6

Apr-

07

Aug-0

7

Dec-0

7

Apr-

08

Aug-0

8

Jan-0

9

May-0

9

Sep-0

9

Jan-1

0

May-1

0

Sep-1

0

Jan-1

1

PA

DD

II

Inven

tori

es L

ed

4 W

eeks,

Th

ou

san

d B

arr

els

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

12.5%

15.0%

17.5%

20.0%

22.5%

[Mo

nth

2 -

Mo

nth

1]

/ M

on

th 1

PADD II Storage

Simple Contango

Source: Bloomberg

Cushing Inventories Respond To Crude Oil Forward Curve

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

Mar-

04

Jul-04

Nov-0

4

Mar-

05

Jul-05

Nov-0

5

Mar-

06

Aug-0

6

Dec-0

6

Apr-

07

Aug-0

7

Dec-0

7

Apr-

08

Aug-0

8

Jan-0

9

May-0

9

Sep-0

9

Jan-1

0

May-1

0

Sep-1

0

Jan-1

1

Inven

tori

es A

t C

ush

ing

Led

4 W

eeks,

Th

ou

san

d B

arr

els

-5.0%

-2.5%

0.0%

2.5%

5.0%

7.5%

10.0%

12.5%

15.0%

17.5%

20.0%

22.5%

[Mo

nth

2 -

Mo

nth

1]

/ M

on

th 1

Cushing Storage

Simple Contango

Source: Bloomberg

New North American Supply Factors

The history of the energy exploration business, natural gas as well as crude oil, is one of imminent shortage and

higher prices followed by the opening up of new supply sources as new resources become economic. Two major

supply developments have affected the Cushing market over the past decade. The first is an increased role of

Canadian exports to the U.S., particularly crude oil from the high-cost Alberta oil sands projects. The second is

5

expanded production from North Dakota’s Bakken Shale, a resource previously uneconomic at lower prices and

before improved technology.

Not only have Canadian imports increased absolutely, the ratio of Canadian to non-Canadian imports of crude oil

and refined products has increased sharply. Higher prices induce new supplies in an efficient market and this is no

exception.

The Increased Role Of Canadian Imports

35,000

40,000

45,000

50,000

55,000

60,000

65,000

70,000

75,000

80,000

19

93

19

94

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

Ca

na

dia

n Im

po

rts

of

Cru

de

Oil &

Re

fin

ed

Pro

du

cts

,

Th

ou

sa

nd

Ba

rre

ls / M

on

th, O

ne

-Ye

ar

Ro

llin

g A

ve

rag

e

15%

17%

19%

21%

23%

25%

27%

29%

Ca

na

dia

n / N

on

-Ca

na

dia

n S

up

plie

s

On

e-Y

ea

r R

ollin

g A

ve

rag

e

Canada/Non-Canada

Canada

Source: Energy Information Administration

The increase in North Dakota production since 2004 has been even more dramatic. North Dakota’s Williston Basin

had been a oil production province for decades, but was considered in long-term decline. To say the addition of the

Bakken Shale production changed the state’s outlook dramatically since 2003 would be an understatement.

The Increased Role Of North Dakota Production

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

19

81

19

82

19

83

19

84

19

85

19

86

19

87

19

88

19

89

19

90

19

91

19

92

19

93

19

94

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

ND

Pro

du

cti

on

of

Cru

de

Oil, T

ho

us

an

d B

arr

els

/ M

on

th,

On

e-Y

ea

r R

ollin

g A

ve

rag

e

1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%

4.5%

5.0%

5.5%

6.0%

ND

/ U

.S. E

x-N

D S

up

plie

s

On

e-Y

ea

r R

ollin

g A

ve

rag

e

ND / U.S. Ex ND

North Dakota Production

Source: Energy Information Administration

6

Once again, markets can and do find solutions to opportunities created by surpluses in one region and deficits in

another. The simplest solution to bring new North American production to wherever it is needed is to build a

pipeline running south from Cushing to refining centers at the U.S. Gulf Coast. TransCanada Corporation, which

has a clear interest in finding a market for Canadian crude oil has announced plans for a 150,000 barrel per day

pipeline it hopes to have operational in 2013. When this link is operational, the role of Cushing as the North

American benchmark will be stronger than ever.

Long-Term Supply

The expansion of North American supply sources is of vital importance in the long-term relative viability of WTI

and Brent as benchmark crude oils. The North Sea has been a productive petroleum province since the 1970s;

indeed, its discovery and production history is parallel to that of the Prudhoe Bay field of Alaska’s North Slope. But

all petroleum provinces face reserve depletion and production decline issues eventually, and the outlook for the

North Sea is poorer in comparison to the remaining potential serving the North American pipeline market.

The BP Statistical Review pegged the proven reserves, defined as those recoverable at present prices and

technology, for the U.K. and Norway at 3.10 and 7.10 billion barrels, respectively, at the end of 2009. Production

from those reserves was 1.448 and 2.342 million barrels per day in 2009.

The comparable figures for North American reserves were 73.3 billion barrels of conventional crude oil and 143.26

billion barrels in the Canadian oil sands. Production from the U.S. and Canada in 2009 was 7.196 and 3.212 million

barrels per day.

Many of the reserves of West Africa, including those of Nigeria and Angola, are priced on a Brent basis as are many

of the crude oils coming into both the Mediterranean and Baltic basins from North Africa, the Middle East and

Russia. These crude oils will face separate pricing comparability issues as North Sea production declines. The real

issue is whether such a relatively small resource base located in a different region can and should serve as a North

American benchmark.

Refinery Seasonality

Supplies are not the only factor determining swings in inventories. While refineries are designed to operate

continuously when in operation, they also have an annual maintenance or “turnaround” cycle. Not only does this

involve switching the plant from winter to summer configurations, it involves retooling, adding new processing

units, changing catalyst configurations, replacing worn and damaged equipment and all of the other factors designed

to keep these exquisitely complex industrial plants operating.

The turnaround cycle is concentrated in the first quarter of each year. The average seasonal adjustment factors for

the American Petroleum Institute’s data on refinery capacity utilization and “runs” or refinery throughput show this

very distinctly. Both utilization rates and runs are low during the first quarter and high during the summer months.

7

Refinery Utilization Highly Seasonal

96.0%

96.5%

97.0%

97.5%

98.0%

98.5%

99.0%

99.5%

100.0%

100.5%

101.0%

101.5%

102.0%

102.5%

103.0%

103.5%

Ja

n

Fe

b

Ma

r

Ap

r

Ma

y

Ju

n

Ju

l

Au

g

Se

p

Oct

No

v

De

c

<=

==

Seaso

nall

y W

eak

||

S

easo

nall

y S

tro

ng

=

==

>

Utilization

Runs

Annual

"Turnaround Cycle"

Source: American Petroleum Institute

Crude Oil Spread Distortion

Quite predictably, this seasonal decline in refining has intersected with the increased production flow from Canada

and North Dakota to produce seasonal dislocations in the spread between WTI and LLS. The spikes in the spread

between LLS and WTI since 2007 have tended to occur during and immediately after the first quarter turnaround

cycle.

The Mid-Continent DislocationGulf Coast To Cushing

$(3)

$(2)

$(1)

$-

$1

$2

$3

$4

$5

$6

$7

$8

$9

$10

$11

$12

$13

$14

$15

$16

$17

$18

$19

$20

Ju

l-8

8

Ma

r-8

9

De

c-8

9

Se

p-9

0

Ju

n-9

1

Ma

r-9

2

De

c-9

2

Se

p-9

3

Ju

n-9

4

Ma

r-9

5

De

c-9

5

Se

p-9

6

Ju

n-9

7

Ma

r-9

8

De

c-9

8

Se

p-9

9

Ju

n-0

0

Ma

r-0

1

De

c-0

1

Se

p-0

2

Ju

n-0

3

Ma

r-0

4

De

c-0

4

Se

p-0

5

Ju

n-0

6

Ma

r-0

7

De

c-0

7

Se

p-0

8

Ju

n-0

9

Ma

r-1

0

De

c-1

0

Se

p-1

1

LL

S @

St.

Ja

me

s -

WT

I @

Cu

sh

ing

, $

/Ba

rre

l

Source: Bloomberg

It is this spread, the consequence of crude oil pipelines flowing north from the U.S. Gulf Coast into Cushing and not

south from Cushing to the U.S. Gulf Coast that has been affected by rising inventories at Cushing. While the spread

between WTI and Brent, with Brent’s price being adjusted by half of the intermonth spread to account for voyage

time, moved to record levels in early 2011, the spread between LLS and Brent remained well within its normal

range.

8

The Mid-Continent Dislocation In Sweet Crude Oil

Impact On The Brent-WTI Spread

-$2.0

-$1.0

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

$9.0

$10.0

Ju

l-8

8

Ma

r-8

9

De

c-8

9

Se

p-9

0

Ju

n-9

1

Ma

r-9

2

De

c-9

2

Se

p-9

3

Ju

n-9

4

Ma

r-9

5

De

c-9

5

Se

p-9

6

Ju

n-9

7

Ma

r-9

8

De

c-9

8

Se

p-9

9

Ju

n-0

0

Ma

r-0

1

De

c-0

1

Se

p-0

2

Ju

n-0

3

Ma

r-0

4

De

c-0

4

Se

p-0

5

Ju

n-0

6

Ma

r-0

7

De

c-0

7

Se

p-0

8

Ju

n-0

9

Ma

r-1

0

De

c-1

0

Se

p-1

1

LL

S -

Bre

nt

Ble

nd

, A

dju

ste

d

-$16.50

-$15.50

-$14.50

-$13.50

-$12.50

-$11.50

-$10.50

-$9.50

-$8.50

-$7.50

-$6.50

-$5.50

-$4.50

-$3.50

-$2.50

-$1.50

-$0.50

$0.50

$1.50

$2.50

$3.50

$4.50

$5.50

$6.50

WT

I -

Bre

nt

Ble

nd

, A

dju

ste

d

LLS-Brent(Adj.)

WTI-Brent (Adj.)

Source: Bloomberg

Another indication WTI futures have continued to function normally within the context of the U.S. pipeline markets

is the spread between it and West Texas Sour (WTS) at Midland, Texas. This spread tends to widen during periods

of refining system stress or high demand as refiners who have made the investment in desulfurization units prefer

the cheaper high-sulfur WTS and only buy the more expensive WTI when they have to do so.

When the spreads between WTI and both Brent and LLS were moving to record-wide levels in early 2011, the

“sweet-sour” spread between WTI and WTS was rising as well. Both grades of crude oil were in high demand and

were acting normally in relation to one another; the only difference is both were in high supply relative to sweet

crude oil at the U.S. Gulf Coast.

The Sweet-Sour Spread And Sour Prices

15

25

35

45

55

65

75

85

95

105

115

125

135

145

Ja

n-0

2

Ap

r-0

2

Au

g-0

2

De

c-0

2

Ap

r-0

3

Au

g-0

3

De

c-0

3

Ap

r-0

4

Ju

l-0

4

No

v-0

4

Ma

r-0

5

Ju

l-0

5

No

v-0

5

Ma

r-0

6

Ju

l-0

6

No

v-0

6

Ma

r-0

7

Ju

l-0

7

No

v-0

7

Ma

r-0

8

Ju

n-0

8

Oct-

08

Fe

b-0

9

Ju

n-0

9

Oct-

09

Fe

b-1

0

Ju

n-1

0

Se

p-1

0

Ja

n-1

1

Ma

y-1

1

We

st

Te

xa

s S

ou

r, $

/Ba

rre

l

-1

0

1

2

3

4

5

6

7

8

9

10

11

WT

I -

WT

S, $

/Ba

rre

lWTS @ Midland

Midland Sweet-Sour

Source: Bloomberg

9

Not only was this spread perfectly normal within the context of the U.S. pipeline market, but it remained in synch

with the second-month crack spread with a normal 96-day lag. If WTI futures had lost their utility as a benchmark

for the U.S. refining system, they were not showing it by any of these key industry metrics.

The Sweet-Sour Spread And Second Month Crack SpreadA 96 Trading Day Leading Relationship

3.0

4.5

6.0

7.5

9.0

10.5

12.0

13.5

15.0

16.5

18.0

19.5

21.0

22.5

24.0

25.5

27.0

28.5

Ja

n-0

2

Ap

r-0

2

Au

g-0

2

De

c-0

2

Ap

r-0

3

Au

g-0

3

De

c-0

3

Ap

r-0

4

Ju

l-0

4

No

v-0

4

Ma

r-0

5

Ju

l-0

5

No

v-0

5

Ma

r-0

6

Ju

l-0

6

No

v-0

6

Ma

r-0

7

Ju

l-0

7

No

v-0

7

Ma

r-0

8

Ju

n-0

8

Oct-

08

Fe

b-0

9

Ju

n-0

9

Oct-

09

Fe

b-1

0

Ju

n-1

0

Se

p-1

0

Ja

n-1

1

Ma

y-1

1

Se

co

nd

Mo

nth

2-1

-1 C

rac

k S

pre

ad

, $

/Ba

rre

l

-1

0

1

2

3

4

5

6

7

8

9

10

11

WT

I -

WT

S, $

/Ba

rre

l L

ed

96

Da

ys

2-1-1 Crack Spread

Midland Sweet-Sour

Source: Bloomberg

The reference to refining margins and crack spreads underscores a critical aspect of WTI as the North American

benchmark, and that is the well-established system of performance bond offsets available on the NYMEX. These

include straight offsets against heating oil and RBOB gasoline futures as well as credits for more complex crack

spreads and spreads against other crude oil futures and swaps, including Brent. More than a quarter-century of

industry practice has led to a system of U.S. refined product spreads and basis differentials linked financially to WTI

futures as well as physically via the contract’s delivery mechanism.

Depth And Liquidity

As investor interest in commodities in general and crude oil in particular has increased since the mid-2000’s, the

NYMEX WTI contract has increased its lead over two other crude oil futures contracts, the Intercontinental

Exchange Europe’s (ICE) Brent futures and a cash-settled version of WTI futures. This can be seen in the weekly

average volume and open interest data for all contracts traded on each exchange.

10

Volume: Thirteen-Week Rolling Average

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

Co

ntr

acts

NYMEX WTI

ICE Brent

ICE WTI

Source: Bloomberg

Open Interest: Thirteen-Week Rolling Average

-

150,000

300,000

450,000

600,000

750,000

900,000

1,050,000

1,200,000

1,350,000

1,500,000

1,650,000

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

Co

ntr

acts

NYMEX WTI

ICE Brent

ICE WTI

Source: Bloomberg

Not only is NYMEX WTI futures volume and open interest far greater on an aggregate basis, its cumulative

distribution over time shows greater depth and liquidity as well. The chart below depicts the cumulative average

daily volume of NYMEX WTI, and ICE Brent and WTI contracts across the first four years of monthly contracts.

11

Cumulative Average Daily Futures Trading VolumeWeek Of March 21-25, 2011

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,000

May-1

1

Jul-11

Sep-1

1

Nov-1

1

Jan-1

2

Mar-

12

May-1

2

Jul-12

Sep-1

2

Nov-1

2

Jan-1

3

Mar-

13

May-1

3

Jul-13

Sep-1

3

Nov-1

3

Jan-1

4

Mar-

14

May-1

4

Jul-14

Sep-1

4

Nov-1

4

Jan-1

5

Mar-

15

Contract Month, First Four Years

Co

ntr

ac

ts

NYMEX WTI

ICE Brent

ICE WTI

Source: Bloomberg

A similar cumulative chart of open interest for the three contracts over the first four years indicates a much longer

maturity schedule for NYMEX WTI open interest. This is a clear signal to commercial traders in the very active

swap and strip market their trading demands can be accommodated more efficiently in NYMEX WTI.

The market has been presented with a choice between a physically delivered WTI contract regulated by the U.S.

Commodity Futures Trading Commission and a cash-settled WTI contract offered by a non-U.S. exchange and has

expressed a clear preference for physical delivery even though the financial risk profiles of the two contracts are

quite similar. The market has been presented with another choice, that between a contract based on WTI and one

based on Brent Blend and has expressed a clear preference for WTI for all applications of futures markets combined,

including price discovery, risk management, physical delivery and diversification of investment activities into the

commodities markets.

Cumulative Futures Open InterestWeek Ending March 25, 2011

-

150,000

300,000

450,000

600,000

750,000

900,000

1,050,000

1,200,000

1,350,000

1,500,000

May-1

1

Jul-11

Sep-1

1

Nov-1

1

Jan-1

2

Mar-

12

May-1

2

Jul-12

Sep-1

2

Nov-1

2

Jan-1

3

Mar-

13

May-1

3

Jul-13

Sep-1

3

Nov-1

3

Jan-1

4

Mar-

14

May-1

4

Jul-14

Sep-1

4

Nov-1

4

Jan-1

5

Mar-

15

Contract Month, First Four Years

Co

ntr

ac

ts

NYMEX WTI

ICE Brent

ICE WTI

Source: Bloomberg

12

Stability And Relative Volatility

Average depth and liquidity are fine, but what is really important to a market is its surge capacity or its ability to

handle increased activity during times of crisis. The outbreak of violence in Libya in late February 2011 provides an

excellent case study for comparing the surge capacity of the WTI and Brent futures markets. Between Friday,

February 18, 2011 and Monday, March 7, 2011, the price of April 2011 WTI, then the front-month contract, jumped

from $97.88 to $105.44 on a closing basis. The comparable numbers for April 2011 Brent were $102.52 and

$116.35. These represent price increases of 7.72% and 13.49%, respectively, over the same timeframe. While the

larger price increase for Brent can be explained in large part by the disruptions to exports of Brent-Basis Es Sider

crude oil from Libya to European refineries, the susceptibility of the Brent futures contract to events in the

Mediterranean Basin raises concerns about the viability of a waterborne cargo priced off North Sea crude oil for the

North American crude oil market.

More curious, though, are the relative movements of implied volatility in the two markets. The implied volatilities

of the respective May contracts are plotted over dates in the range above as a function of their “moneyness,” with

values over 100% corresponding to prices higher than the current-at-the-money level. We should expect implied

volatilities to rise during a price jump of this nature accompanied by a rise in uncertainty. In addition, the higher-

priced strikes’ volatility should rise more to account for the very real risk prices could go much higher given the

situation at hand. Finally, Brent volatilities should exhibit this behavior more than WTI volatilities.

What we see, however, is a pattern where WTI volatility rose much more responsively on Tuesday, February 22,

2011 than did Brent volatility. The Brent skew finally converged to its expected pattern by Thursday, February 24,

2011.

90.0

%

95.0

%

97.5

%

100.0

%

102.5

%

105.0

%

110.0

%

18-F

eb

22-F

eb

24-F

eb

7-M

ar

27.5%

30.0%

32.5%

35.0%

37.5%

40.0%

42.5%

45.0%

47.5%

Imp

lied

Vo

lati

lity

Moneyness

May 2011 WTI Volatility During Libyan Crisis

Source: Bloomberg

13

90.0

%

95.0

%

97.5

%

100.0

%

102.5

%

105.0

%

110.0

%

18-F

eb

22-F

eb

24-F

eb

7-M

ar

25.0%

27.5%

30.0%

32.5%

35.0%

37.5%

40.0%

42.5%

45.0%

47.5%

Imp

lied

Vo

lati

lity

Moneyness

May 2011 Brent Volatility During Libyan Crisis

Source: Bloomberg

WTI As A Financial Instrument

The depth and liquidity of the WTI futures market and the demand by investors for exposure to this market has led

to a wide array of financial instruments based on the contract. These include exchange-traded funds (ETFs) such as

the U.S. Oil Fund and the U.S. 12 Month Oil Fund, exchange-traded notes (ETNs) such as the iPath S&P GSCI

Crude Oil Total Return Index, and broader commodity instruments such as the iPath DJ-UBS Commodity Index

Total Return ETN, the PowerShares DB Commodity Index Tracking Fund and the iShares S&P GSCI Commodity-

Indexed Trust. WTI is and has been a dominant component of the most widely benchmarked investable commodity

indices, the S&P/GSCI index and the Dow Jones-UBS index. Conclusion

The WTI market has played a vital and central role in the evolution of North American petroleum markets since the

introduction of futures in 1983. It has evolved and in a way has created its own financial ecosystem; it has served as

the benchmark for other crude oils, for refined product spreads and prices, for the creation of a vibrant market for

inventory management at Cushing, for new investment products and for new energy infrastructure.

It has adapted to previous shifts in global energy markets and it is already in the process of adapting to the periods of

mid-continent dislocations in late winter. Once new investments are complete, the pipeline market for WTI and the

physically delivered futures that make it so efficient and transparent will return to unquestioned prominence as the

benchmark for the North American crude oil market. Moreover, the simple imperatives of where global reserves

and production potential lie will make the WTI benchmark stronger relative to its competition.