ANALYST CERTIFICATIONS AND IMPORTANT DISCLOSURES ARE IN THE DISCLOSURE APPENDIX. FOR OTHER IMPORTANT DISCLOSURES, PLEASE REFER TO https://firesearchdisclosure.credit-suisse.com.

What’s the real price of oil? Commodities Research

Broken WTI benchmark poses dilemmas • The remarkable divergence of prompt and deferred prices of West Texas

Intermediate crude oil (WTI), traded on the CME/NYMEX and Brent, traded on the ICE, is raising critical questions among petroleum specialists as well as macro-level analysts.

• For specialists the main issue is how and when bottlenecks to the evacuation of crude oil from the US mid-continent will be removed.

• For the economic generalist used to using WTI as an indicator of the price of oil and the WTI futures curves as a means of gauging a number of other issues, the question is what to use as a substitute measure. There is no easy answer to this.

• For all of its problems as an appropriate benchmark for global oil prices, Brent remains the leading second-best solution. That doesn’t mean it is without problems – it clearly is also ”breaking” along a number of fronts. Additionally, data about options and market participants are less transparent and less useful than for WTI. Dubai crude oil or the OPEC basket might well be more representative of the average global crude oil price, but neither offers a forward curve.

Exhibit 1: WTI vs. Brent Prices, Jan-10 – Present Exhibit 2: WTI vs. Brent Forward Curves $/bbl $/bbl, as of 2/14/2011

65

70

75

80

85

90

95

100

105

Jan-10 Mar-10 May-10 Jul-10 Sep-10 Nov-10 Jan-11-20

-15

-10

-5

0

5

WTI vs. Brent (rhs) WTI (lhs) Brent (lhs)

80

85

90

95

100

105

110

Mar

-11

Sep-

11

Mar

-12

Sep-

12

Mar

-13

Sep-

13

Mar

-14

Sep-

14

Mar

-15

Sep-

15

Mar

-16

Sep-

16

Mar

-17

Sep-

17

Mar

-18

Sep-

18

Mar

-19

Sep-

19

-15

-13

-11

-9

-7

-5

-3

-1

WTI vs. Brent (rhs) WTI (lhs) Brent (lhs)

Source: the BLOOMBERG PROFESSIONAL™ service, Credit Suisse Global Commodities Research

Source: the BLOOMBERG PROFESSIONAL™ service, Credit Suisse Global Commodities Research

17 February 2011Fixed Income Research

http://www.credit-suisse.com/researchandanalytics

Contributors

Joachim Azria Associate

+1 212 325 4556 joachim.azria@credit-suisse.com

Edward Morse

Managing Director +1 212 325 1013

edward.morse@credit-suisse.com

17 February 2011

What’s the real price of oil? 2

This time the break in WTI is here to stay for a while It’s difficult to exaggerate the role WTI has played as the world’s notional benchmark of the price of oil. As an abundant crude oil stream in the mid-continent of the US, WTI became the physical crude oil backing the successful futures contract established by the New York Mercantile Exchange in 1983. The success of the contract both propelled WTI into the lexicon of the oil industry and the global understanding of the price of oil, and helped consolidate the NYMEX as the world’s largest commodity exchange with physical settlement. It is no exaggeration to say that the most commonly understood price of oil is the WTI daily settlement price on the CME/NYMEX. Open interest in WTI grew rapidly in the 1980s and 1990s and even faster during the last decade. WTI has been the favorite instrument through which long-term investors have gained exposure to the price of oil.

Later on, a Brent contract was established on the International Petroleum Exchange in London based on Brent crude oil. The ICE bought the IPE and changed the contract in a number of ways. But the relationship between Brent and WTI prices was more or less fixed, with Brent trading at a premium to WTI with the difference between the two crude oil prices based largely on the costs of transportation between Northwest Europe and Cushing Oklahoma, a one-way transport from East to West.

Exhibit 3: Open Interest on NYMEX WTI and ICE Brent In thousand contracts

0

2,000

4,000

6,000

8,000

10,000

12,000

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

NYMEX WTI Futures and Options ICE WTI Futures and Options ICE Brent Futures and Options

Open Interest in Brent

Open Interest in WTI

Source: the BLOOMBERG PROFESSIONAL™ service, ICE, Credit Suisse Global Commodities Research

WTI has held its critical position as the

global benchmark…

…but there’s significant growth in

Brent open interest

17 February 2011

What’s the real price of oil? 3

Over the year that started in April 2006 and ended in April 2007, the relationship between WTI and Brent prices and forward curves started to shift.1 In early April 2006, WTI was trading out the curve at a more or less fixed premium of about $1.75 over Brent. But the prompt price of WTI was starting to converge with Brent and the forward curve was in considerably steeper contango than Brent. The common explanation at the time was that the front-end convergence of the two crude oil streams was the result of the financial impact of monthly index rolls and the persistent increase in investor flows into commodities. Additional explanations related to the changing volume of flows of crude oil in the mid-continent of the United States. Even so, it had not dawned on most analysts that there was something physical and underlying and longer term that was starting to unfold.

Exhibit 4: WTI vs. Brent Prices, Apr-06 – Present $/bbl

0

20

40

60

80

100

120

140

160

Apr-06 Oct-06 Apr-07 Oct-07 Apr-08 Oct-08 Apr-09 Oct-09 Apr-10 Oct-10

US

$/bb

l

-20

-15

-10

-5

0

5

10

15

20WTI vs. Brent (rhs) WTI Brent

Mar-07 - Jul-07:Lowest: -$6.54

Mid Dec-08 - Mid Mar-09:Lowest: -$10.67

Source: the BLOOMBERG PROFESSIONAL™ service

Why was WTI expected to be trading at a permanent premium to Brent? Because the two essentially lookalike crude oil streams were trading in different places – WTI was in the US crude-short mid-continent and Brent was in the crude-long export center of the North Sea. The premium was required to pull North Sea crude to North America.

By September 2006 the prompt prices of the two crudes as well as their deferred prices converged for the first time. There was no open arb for North Sea crude oil to flow to North America and the pricing of the two benchmarks were indeed close to identical twins. In retrospect what was happening in physical markets was starting to be reflected in the financial markets in which the two crude oil streams were trading.

1 The CME/NYMEX has long objected to the view that WTI is a broken benchmark. It hired consultants Purvin & Gertz, Inc. to

undertake an assessment of physical markets and their changes in a thorough study entitled "The Role of WTI as a Crude Oil Benchmark," published in January 2010. NYMEX has also countered arguments such as those put forward in this report in a number of places, including in a slide presentation by the CME Group's Managing Director for Energy Research & Product Development, Robert Levin, "WTI: Understanding the Global Crude Oil Benchmark."

The first glimpse of change was in 2006-07

By late 2006 WTI lost its

premium…for a while

17 February 2011

What’s the real price of oil? 4

Exhibit 5: WTI vs. Brent Forward Curves, As of April 3, 2006

Exhibit 6: WTI vs. Brent Forward Curves, As of September 22, 2006

$/bbl $/bbl

63

64

65

66

67

68

69

70

May

-06

Sep

-06

Jan-

07

May

-07

Sep

-07

Jan-

08

May

-08

Sep

-08

Jan-

09

May

-09

Sep

-09

Jan-

10

May

-10

Sep

-10

Jan-

11

May

-11

Sep

-11

Jan-

12

May

-12

Sep

-12

WTI Brent

59

60

61

62

63

64

65

66

67

Nov

-06

Mar

-07

Jul-0

7

Nov

-07

Mar

-08

Jul-0

8

Nov

-08

Mar

-09

Jul-0

9

Nov

-09

Mar

-10

Jul-1

0

Nov

-10

Mar

-11

Jul-1

1

Nov

-11

Mar

-12

Jul-1

2

Nov

-12

WTI Brent Source: the BLOOMBERG PROFESSIONAL™ service, Credit Suisse Global Commodities Research Source: the BLOOMBERG PROFESSIONAL™ service, Credit Suisse Global Commodities Research

A short history of the “breaking” of the WTI benchmark • Changes were starting to develop on both sides of the Atlantic Basin affecting the

pricing relationship between Brent and WTI, with the pull on the European side of the Basin tightening the North Sea market and the push on the US side leading to congestion in the US mid-continent.

• On the North Sea side, production out of the UK, Norway and other sectors was starting to decline rapidly. For example, total North Sea output exceeded 6-million b/d well into 2003. By 2005 output was starting to fall rapidly and averaged 5.27-m b/d for the year as a whole. In 2006, when Brent/WTI convergence became a noticeable part of the landscape, North Sea output averaged 4.88-m b/d and in the summer it fell to under 4.5-m b/d, 700-k b/d less than the summer flows two years earlier. In short, the Brent market was getting tighter and as the North Sea arena moved from being a net export to a net import area, the relative value of Brent was rising. North Sea production averaged 3.39-m b/d in 2010.

• In the US mid-continent a reverse situation was developing with respect to production. Just as the Brent market was itself getting tighter, the core WTI market was changing as local production started to decline (it is now growing again), but imports from Canada started to grow rapidly. There was also a modest reduction of total refining capacity in PADD2 of the United States, so refining demand for crude oil was being reduced just as growing production from Canadian oil sands were adding about 150-k b/d of new supply per year, with nowhere to go other than into the mid-continent of the United States. In 2000, when total North Sea production was regularly exceeding 6-milllion b/d, Canadian production averaged slightly more than 2-m b/d. By 2006 Canadian production was over 2.5-mb/d and almost the entire increment flowed into the US mid-continent, displacing crude oil brought in from PADD3 on the US Gulf Coast. Canadian crude oil output is now averaging 3.1-m b/d.

17 February 2011

What’s the real price of oil? 5

Exhibit 7: Crude Oil Production in North Sea and U.S. Mid-Continent kb/d

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

7,000

Jan-

90

Jan-

91

Jan-

92

Jan-

93

Jan-

94

Jan-

95

Jan-

96

Jan-

97

Jan-

98

Jan-

99

Jan-

00

Jan-

01

Jan-

02

Jan-

03

Jan-

04

Jan-

05

Jan-

06

Jan-

07

Jan-

08

Jan-

09

Jan-

10

400

450

500

550

600

650

700

750

800

850North Sea (lhs) U.S. Mid-Continent (rhs)

Source: EIA, Energy Intelligence, Credit Suisse Global Commodities Research

• As Canadian output continued to rise, refiners in the Chicago area, with significant upgrading capacity, opted to consume Canadian oil, which was selling at a discounted price to waterborne crude oil flowing up the 1.1-m b/d capacity Capline pipeline from St. James Louisiana. Canadian pipeline company, Enbridge, bought the 190-k b/d Spearhead pipeline, which had been bringing crude oil from Cushing, Oklahoma to Chicago. Enbridge reversed the line and crude oil started flowing from Chicago and on to Cushing and its growing storage capacity.

Exhibit 8: Canadian Crude Oil Production '000 bbl/d

2,300

2,400

2,500

2,600

2,700

2,800

2,900

3,000

3,100

3,200

3,300

J F M A M J J A S O N D

2007 2008 2009 20102011E 5yr MAX 5yr MIN

Source: Credit Suisse

• It’s critical to understand the role played by the Enbridge pipeline system in linking the Canadian and US markets (see Appendix). It is a vast system with a throughput capacity of 2.1-m b/d, responsible until very recently for about 70% of total exports from Western

17 February 2011

What’s the real price of oil? 6

Canada to the US, and also to Eastern Canada, partly through the US. The main system to the US is the “Lakehead” System with 2-m b/d capacity bringing crude from Western Canada to the US via North Dakota and on to Chicago (with an extension across the Niagara River to Buffalo).

• At the same time that the Spearhead pipeline was reversed, in spring 2006, WTI fell steeply into front-end contango and was selling at a $5/bbl discount to Brent.

• WTI recovered after nine weeks, and by and large regained its premium to Brent by summer 2008. It was the case that one of the critical factors that was at work was the build out of storage capacity in Cushing. Total crude oil stocks in Cushing were halved by almost 14.5-m bls during the second half of 2007.

Exhibit 9: WTI Price vs. Crude Oil Stocks in Cushing Jan-2006 – Dec-2009

0

20

40

60

80

100

120

140

160

Jan-06 Jul-06 Jan-07 Jul-07 Jan-08 Jul-08 Jan-09 Jul-09

$/bb

l

10,000

15,000

20,000

25,000

30,000

35,000

40,000

'000

bar

rels

Cushing Stocks (rhs) WTI Price (lhs)

Source: the BLOOMBERG PROFESSIONAL™ service, EIA, Credit Suisse Global Commodities Research

• The next severe episode in the breakdown of the WTI benchmark came in the winter of 2009, a time during which refinery demand for crude oil fell globally, including in PADD 2, in the wake of the collapse in petroleum product demand throughout the OECD. By then, however, storage capacity in Cushing was substantially greater than it had been in 2007, and with WTI in steepening contango and a steepening discount to Brent, investors had a clear incentive to buy and store the increased flows of oil into PADD 2. That particular episode ended with the return of refiners to full operation and the rise of refinery demand for crude oil in the mid-continent, leaving an additional cushion for increased storage at Cushing.

• Accommodating changes in the physical market of the US mid-continent were several additional pipeline changes, include changes last year and this year, which are the background to the current blowout in WTI-Brent spreads and in the steepening current WTI contango. The first change was the building of the Alberta Clipper, from Hardisty Alberta to Superior Wisconsin, which vastly expanded Enbridge’s capacity, adding 450-k mb/d of new capacity and eventually expanding to 800-k b/d. Line fill was completed in October 2010. Accompanying that line was the Southern Lights Project to bring back to Canada diluent liquids used to move heavy oil to Chicago and other places in the US. Enbridge also has announced plans to build a line from Patoka Illinois to Beaumont Texas, with a capacity of 400-k b/d, which would, if built, create a waterborne safety valve for crude in the US mid-continent.

17 February 2011

What’s the real price of oil? 7

• An additional new system, the TransCanada Keystone line, also started flowing oil into the midcontinent last year, bringing oil from Alberta through the US PADD4 to Steele City, Nebraska and on to Patoka, Illinois adding another 435-k b/d of capacity. The Keystone extension from Patoka to Cushing with 155-kb/d capacity, just started flowing

What’s different this time? • Since last summer a new set of dynamics have been at work in PADD 2. The major

change on the supply side has been the growth of indigenous production in PADD2, in particular production of oil that started with the development of shale gas in the middle of the last decade. PADD 2 shale plays have been particularly rich in liquids, just as PADD 2 output has been generally particularly rich in NGLs. PADD 2 production had fallen from its peak over 1-m b/d in 1984 to around 430-k b/d, a level at which it had stabilized from 2004-2007. But 2008 output started to increase, particularly in the Bakken play in North Dakota. At year-end 2008 PADD 2 production rose by over 100-k b/d from the year before. At year end 2009 output rose another 130-k b/d, and it looks as though year-end 2010 it rose y-o-y by some 150-k b/d. By the end of 2011 it is expected to grow by more than 200-k b /d and at 850-k b/d would be more than double what it was in 2006.

Exhibit 10: U.S. Midwest (PADD 2) Crude Oil Production kb/d, Jan-1981 – Nov-2010

350

450

550

650

750

850

950

1,050

1,150

Jan-

81

Jan-

83

Jan-

85

Jan-

87

Jan-

89

Jan-

91

Jan-

93

Jan-

95

Jan-

97

Jan-

99

Jan-

01

Jan-

03

Jan-

05

Jan-

07

Jan-

09

Sep-84: 1,118-k b/d

Jan-04: 416-k b/d

Nov-10: 737-k b/d

Source: EIA, Credit Suisse Global Commodities Research

• The main result of the two new pipelines described above – the expansion of the Enbridge System and the addition of the Keystone line – is to debottleneck crude oil that has not been able to flow from Canada to the US. If all of the pipelines are fully operational, Canadian crude will be able to flow freely into the US – but a new problem emerges in that the former Canadian bottleneck is being pushed from Alberta to Cushing, exacerbated by the new flows into Cushing from North Dakota and elsewhere in PADD 2.

• Stocks in PADD 2 and at Cushing reached record levels last summer as new storage capacity could absorb flows from within PADD 2 and from Canada. But even as inventories of crude oil were growing and as refiners were reaching very high levels of capacity utilization within PADD 2, flows from Canada were interrupted by a series of problems that arose on Enbridge’s pipeline system bringing crude oil from Canada into the mid-continent of the United States.

17 February 2011

What’s the real price of oil? 8

• Soon after new flows started from Canada last summer, WTI moved into a discount to Brent, but disruptions to the flows reversed the process and in September 2010 WTI regained a $1.50 premium to its sister benchmark. Enbridge encountered two problems in its system. First a spill occurred near Lake Michigan on the line carrying 190-k b/d of crude from Indiana to Sarnia, Ontario. But then in September US regulators reportedly shut down Enbridge’s Line 6A pipeline after a leak was discovered near Chicago in the 52 year old line. These accidents simply deferred the inevitable, which now appears to be unfolding.

Exhibit 11: Crude Oil Stocks in PADD 2 Exhibit 12: Crude Oil Stocks in Cushing, Oklahoma mmbl. 2005 – 2011 mmbl. 2005 - 2011

55

65

75

85

95

105

J F M A M J J A S O N D

Prior 5 Year Range Prior 5 Year Average 2010 2011

12

17

22

27

32

37

42

J F M A M J J A S O N D

Prior 3 Year Range Prior 3 Year Average 2010 2011

Source: EIA, Credit Suisse Global Commodities Research Source: EIA, Credit Suisse Global Commodities Research

• It is no accident the recent near total bifurcation of the WTI and Brent markets has coincided with the opening of the Keystone line to Cushing. Now that there are no foreseeable pipeline constraints impeding Canadian flows into the United States, the combined new flows from within PADD 2 and from Canada are being gathered at Cushing, which is the effective end terminal for expanding Canadian and PADD 2 production. Like last August when storage was rising at Cushing at a time when refineries in PADD 2 were on full throttle, so too is the same situation unfolding now.

• The only ways to deal with the combined new flows from Canada and from within PADD 2 are to add new storage to absorb higher volumes, and to find relief by moving crude oil out of Canada to the Pacific Coast via new pipelines, by backing out more crude oil flowing into PADD 2 from PADD 3 and/or by either reversing two main lines into PADD 2 or building a new line to move crude oil from Cushing to the US Gulf Coast. All of these options are being pursued, but none seems feasible in the near term.

• Exhibits 9 and 10 show the recent history of the growth in storage in PADD 2 and at Cushing, while Exhibit 11 depicts the growth in Cushing’s crude oil shell storage capacity. The current 54-m bbls of capacity at Cushing works out normally to about 45-m bbls of working storage capacity, according to the EIA. But in practice, there is incremental demand for isolated storage tanks to deal with the multiple streams of crude oil and blending materials required by refiners. Today’s steep contango, with a $3 spread between the prompt and second month as well as between the second and third month indicates to us that tanks are at effective operating capacity today.

• Industry sources indicate that between the last DOE survey of Cushing storage and the end of Q1 some 3.5 million additional storage capacity will have been built. The same industry sources indicate that an additional 10-m bbls of storage capacity at Cushing can be expected to come into service by the end of 2011. Announcements by Plains All American Pipeline, Gavilon Group and Magellan Midstream Partners would effectively increase Cushing storage by 25% by year-end. Current crude in tanks at Cushing is 37.7-m bbls, up 250-k bbls from a week ago with total PADD 2 inventory now at 99.1-m bbls, up 1.3-m bbls over the past week.

17 February 2011

What’s the real price of oil? 9

Exhibit 13: Cushing Crude Shell Storage Capacity Mmbls

0

10

20

30

40

50

60

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Source: Credit Suisse, EIA

• It is extremely difficult to reverse either of the two pipelines from the Gulf Coast into PADD 2. The 350-k b/d capacity Seaway pipeline brings crude oil from Texas City to Cushing. Conoco-Phillips has indicated substantial interest in the pipeline, which it uses to bring its own equity crude production to its refineries in Oklahoma and the Texas panhandle. It has no incentive to reverse the line. The 1.2-m b/d Capline, from St. James Louisiana to Texas brings a significant amount of term contract crude including from the Middle East, to refineries as far north as Chicago. Although throughput has declined along the pipeline for a half decade, the lube-rich Middle East crudes have become fundamental to the refiners’ economics.

• TransCanada Pipeline’s Keystone line’s planned expansion from Cushing to the US Gulf Coast has been delayed from permitting because of environmental issues. If permitted, the Keystone Express line would have a capacity of over 500-k b/d from the mid-continent to the US Gulf Coast. The US Department of State has delayed a ruling on the line, but according to news reports, it now appears that a favorable decision might be made in the third quarter of this year, which would make early 2013 the earliest likely time for construction to be completed. Enbridge’s similar plan would have a line from Cushing to the Gulf Coast in place by 2014.

• As far as a connection from Alberta to the West Coast, the main project under discussion is Enbridge’s Northern Gateway Project, which involves two pipelines from Edmonton, Alberta, to a marine terminal in Kitimat, British Columbia. In addition to regulatory approval from Canada’s National Energy Board, the project also needs approval from several aboriginal groups. Construction would start on the project in 2013 at the earliest, with potential completion in 2016. The project envisages a 525-k b/d pipeline to the Pacific, with a reverse pipeline bringing condensates used to facilitate heavy oil flow back to Edmonton.

• Meanwhile, companies are at work to find ways to move crude oil from PADD 2, and from both North Dakota and Cushing to the US Gulf Coast. The prime new medium is rail. Already shipments by rail have doubled over the last year and plans are for much more significant growth. The main incentive is the discrepancy between crude oil

17 February 2011

What’s the real price of oil? 10

produced in PADD 2 and crude oil markets in Louisiana and takes. The current $20-$22 spread makes the move profitable even if the shipping costs are $7-$12 per barrel. At present the US Development Group claims to be able to move 60,000 b/d of crude oil from North Dakota to St. James Louisiana, the same place where Capline brings Gulf Coast and foreign crude into other parts of PADD 2. Current runs are about one-third that level. At present there is one crude-by-rail terminal in North Dakota and it is operated by EOG Resources. Hess has announced plans to build its own 130-k b/d rail terminal in North Dakota and perhaps 8-10 additional terminals are being planned.

• The other potential solution is moving crude by truck. But that has logistical problems and the system isn’t readily set up for truck shipments (as opposed to petroleum products, which work on a wholesale rack basis). The economics are similar to the economics by rail – about $7 a barrel in all in costs to move crude oil in large tanker trucks that can handle roughly 200-240 barrels (10,000 gallons) each. The economics are significantly less compelling for smaller tanker trucks with 3,000 gallon (71.4 barrels) capacity since a similar amount of diesel has to be consumed in each. Thus while individual truckers might find it profitable to make a trip in which the driver/owner can make $300-$500 in a day, it would take a significant armada of trucks to dent the oil in Cushing. It would be far more profitable to move material by rail or to store it given the current front-to-back spreads.

• Until a more permanent solution is found for debottlenecking growing crude flows from the Canada and the mid-continent, WTI will likely have a very volatile financial relationship to Brent crude oil. Stoppages on flows from Canada can raise the price of crude at Cushing. Refinery outages can cause storage capacity to increase. There are multiple examples of how this can occur. In 2007 a minor fire on the Enbridge line to Chicago resulted in a $4 price spike. A leak on the line last September caused a $2.20 spike, even as inventories of crude oil and petroleum products were at a record level in PADD 2.

• The crude oil glut in PADD 2 has made refining in this district highly profitable. The entire area remains product short as there is inadequate capacity in the region to transform sufficient crude oil into petroleum products. In the last half of 2010 product movements from PADD 2 to PADD 3 averaged 345-k b/d, but this was almost entirely comprised of LPGs. Meanwhile flows of products from the PADD 3 refinery centers into PADD 2 were substantial, averaging 825-k b/d, close to 25% of which was gasoline with a near equivalent amount of low sulfur diesel, and 10% of which was jet fuel. Already some crude lines have been converted into product pipelines, including the smaller of the two Seaway lines. In 2001 a natural gas pipeline was converted into a products line moving product from Beaumont Texas into a larger line to central Illinois. In 2003 the expanded Explorer Pipeline from the Gulf Coast increased its total line capacity by 130-k b/d to 690-k b/d. Magellan Midstream Partners owns the Longhorn Pipeline, which is a 700-mile refined products pipeline that moves refined products from Houston to El Paso (east to west). MMP is currently evaluating a conversion/reversal of a portion of the pipeline. Specifically, MMP is considering reversing and converting the segment from Crane, Texas to Houston so that it can transport crude oil from West Texas to its East Houston Terminal. But this is unlikely to take place before next year. Magellan Midstream Partners expects to make a final decision by the end of the first quarter, and the pipeline could be operational within 18 to 24 months if it decides to proceed.

17 February 2011

What’s the real price of oil? 11

Exhibit 14: Potential Texas Pipeline Conversion

Source: Magellan Midstream Partners, LP

Meanwhile, combined production in Western Canada and PADD 2 is expected to grow by more than 500-k b/d over the next two years. In the absence of a near-term pipeline solution, crude oil is being shipped by rail and truck. Some of this shipping, including as much as 72,000 b/d from North Dakota to Cushing, is exacerbating the storage situation at the Oklahoma gathering point. And the fact that more different types of crude oils are being shipped to Cushing has meant that storage requirements for blending have increased. Thus even if there is significant shell capacity available, the increased demands for isolated storage of different crude streams and blending fluids including condensates, makes the situation appear over-full even if statistically it is only 70% full.

• If the current situation persists – and we see no reason why it should not – the differential between WTI and similar crudes at the US Gulf Coast might well stabilize at the level of the effective physical arb to the US Gulf Coast. In our view, $7 appears to be a reasonable assessment of that physical arb and therefore the equilibrium spread between WTI and LLS or Brent.

Meanwhile distillate demand surge has buoyed Brent We noted earlier that Brent prices have gained buoyancy over WTI as North Sea production has declined. The demand side has also further skewed the Brent “benchmark” making it seasonally more volatile than it otherwise might have been. There are secular and seasonal factors at work. Since Brent is a distillate-rich crude, distillate demand plays a significant role in refinery demand for Brent.

Base load global demand growth is in the middle distillate pool – gasoil, jet fuel, heating oil, and diesel. Towards the end of October last year, crude oil prices broke through their tight range to reach new highs pushed up by a surge in demand and growing tightness in the distillate pool. Global demand last December was up some 2-m b/d m-o-m and 3.7-m b/d y-o-y, which included an increase in US product demand of 690-k b/d and 1-m b/d in China.

Is $7 the new stable spread between WTI

and Brent ?

Brent is also a partially “broken”

benchmark

17 February 2011

What’s the real price of oil? 12

As shown in Exhibits 15 and 16, the world has recovered from the macroeconomic crisis and continues to do so at a strong pace, increasing demand for oil and especially middle distillates. In the second half of 2010, Brent and Light Louisiana Sweet prices increased by nearly 25% while the WTI price increased only by 15%.

After the drop in 2008 and 2009, global IP and global oil demand both rebounded and continued growing above trend at year-end.

Exhibit 15: Global IP vs. Global Oil Demand Exhibit 16: Y-o-Y Global Oil and IP Growth

100

150

200

250

300

350

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

60,000

65,000

70,000

75,000

80,000

85,000

90,000Global IP (lhs) Oil Demand (rhs)

-6.00%

-4.00%

-2.00%

0.00%

2.00%

4.00%

6.00%

8.00%

10.00%

12.00%

1986

1987

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Global Oil Demand Global IP

Source: EIG, Credit Suisse Global Commodities Research Source: EIG, Credit Suisse Global Commodities Research

However, over the course of the fourth quarter of 2010 a set of one-off factors contributed to accelerating this trend, exacerbating market tightness.

• China’s government abruptly decided to meet energy efficiency targets in its five-year plan ending last December. By Q3 of 2010, China was short of its energy efficiency target, having increased efficiency by 16% versus the targeted 20%. The government ordered lower use of inefficient coal, resulting in brownouts and blackouts. Consumers of electricity made up for this by using diesel in small diesel generators. The refiners in China were not prepared for the surge in distillate demand and indeed had run down inventories over the summer. Refiners raised runs by over 1 –m b/d, and started importing distillates, reversing the structural distillate export situation China was in through the first eight months of last year. We estimate the added pull was at least 14 million barrels of distillate demand from China.

• The French port and refinery strikes protesting the one-year rise in the retirement age to 63 also contributed with what was effectively a loss of more than 30-m bls of supply to markets.

• Finally, the coldest winter in three decades that hit the northern hemisphere also played an important part in increasing the demand for heating oil and other middle distillate products.

In total, around 50-m bls of distillates were lost from the supply pool between September and November.

As a result of the surge in distillate demand, refinery runs rose dramatically globally over the fourth quarter of last year, perhaps by 5-m b/d or more. With strong distillate margins, simpler refiners that had reduced their runs raised them and that required more distillate-rich crude oils like Brent.

17 February 2011

What’s the real price of oil? 13

Exhibit 17: Total Product Demand in mmb/d

Source: EIG, Credit Suisse Global Commodities Research

Global oil demand normally falls to the lowest level of the year in May, on average by 2.5-m b/d. Adding the 1-m b/d impact of the one-off factors to this number, we expect product demand in May to drop by 3-m b/d to 5-m b/d from December levels, which as a result should have an impact in correcting the Brent-WTI spread to some degree. We would not be surprised as winter passes and spring arrives to see that spread come in by as much as half. But we doubt it will narrow to the low single-digit levels any time soon. Indeed, we think that the convergence built into the deferred prices of Brent and WTI will widen as deferred prices become more prompt.

So, what does this mean for global crude oil prices? There are two critical issues that result from what appears to be the now near permanent rupture of WTI from Brent prices.

• For investors, especially of index products, with WTI in a steep front-end contango at a significant discount to Brent, and with Brent higher priced and flatter, there has been a significant incentive to move away from WTI and toward Brent. WTI is both more volatile and brings a near-permanent negative roll yield, while Brent has become less volatile and more attractive as an investment vehicle. This can be seen in the relative growth of total open interest for Brent crude oil on the ICE versus WTI on both the ICE and on CME/NYMEZ.

• For analysts interested in examining oil prices as an indicator of inflation or of the impact of rising prices on personal consumption the issue is if WTI no longer works, what should one turn to. And there is no simple answer for that.

Winners and losers in WTI and Brent There is little doubt that the shift by investors from WTI to Brent comes at a cost. One of the benefits of the move toward making data more transparent on US exchanges through regulatory changes brought by the US-based CFTC, is a greater understanding of who the major market participants are and how they express their investment views. We know from CFTC data releases not simply the break down between longs and shorts and the sector from which they are based, but we also can have a transparent understanding of changes in the structure of options and the overall probability assessment of the market on where prices might be heading. Should the shift in overall liquidity and daily trading continue to grow on the ICE at the expense of NYMEX, that understanding could be compromised.

17 February 2011

What’s the real price of oil? 14

Exhibit 18: Distribution of Dec-11 Calls on WTI Exhibit 19: Distribution of Dec-12 Calls on WTI

0%

5%

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25%

50 - 64 65 - 79 80 - 94 95 - 109 110 - 124 125 - 139 140 - 154 155+

Strike

% o

f Tot

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2/12/2010 11/17/2010 2/9/2011 2/14/2011

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% o

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al O

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2/12/2010 11/17/2010 2/9/2011 2/14/2011

Source: the BLOOMBERG PROFESSIONAL™ service, API, Credit Suisse Global Commodities Research

Source: the BLOOMBERG PROFESSIONAL™ service, API, Credit Suisse Global Commodities Research

What’s the real price of oil? Round 1 As we have argued above, neither WTI nor Brent is necessarily reflective of the average barrel of crude oil. WTI has lost its way given the isolation of the US mid-continent from the global waterborne market. But just as WTI represents the fundamental conditions of the physical market in the US mid-continent, so too does Brent represent the physical conditions of the North Sea market. We have commented on two of these conditions.

Exhibit 20: Global Crude Oil Production by Quality ‘000 b/d

Source: ENI World Oil and Gas Review 2010

First, the dramatic drop in physical production of North Sea crude oil and the loss of the exportable surplus of North Sea-produced light sweet crude oil results in a need to pull crude oil from outside the region into the region in competition with other refiners around the world. Just as WTI, once a natural short, had traditionally to pull in North Sea barrels which were in long supply, so now WTI has become both long and bottlenecked, while North Sea crudes have become structurally in short supply.

17 February 2011

What’s the real price of oil? 15

Second, as was the case this past year, with world demand for low sulfur distillate growing, a premium has been placed on distillate-rich low-sulfur crude streams and Brent is a perfect example of this. Most of the world’s crude oil supply remains higher in sulfur and heavier in gravity. Last fall, there were particular one-off factors that placed a premium on Brent, and the spread between Brent and heavier, “more normal” crude streams widened significantly.

The preponderance of global crude oil is significantly heavier than WTI or Brent. As is made clear in ENI’s annual review of world crude oil quality, 40% of the crude oil produced in the world can be categorized as medium and sour, while only 14% of the world’s crude stream is light and sweet. And medium and sour crude streams are generally lower priced than are lighter and sweeter crude oil streams.

The problem however is that there is no sour crude oil stream that has as much liquidity as WTI or Brent. Thus, while there are measures of sour crudes, some of which are tradable like Oman/Dubai on the Dubai Mercantile Exchange, or over the counter, there is no useful liquid futures market for any of them. And with limited liquidity, medium sour crudes that are traded are subject to their own regional distortions and to periodic squeezes, whether one looks at Urals or Dubai or Mars crude oil streams, all of which are traded to some degree.

Exhibit 21: Brent vs. Dubai Prices $/bbl, Jan-10 - Present

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8.00Brent vs. Dubai (rhs) Brent Dubai

Source: the BLOOMBERG PROFESSIONAL™ service, Credit Suisse Global Commodities Research

A more realistic measure of the price of oil might well be the OPEC basket of crude oils, for which OPEC publishes a daily price and for which there is a decent history. But unfortunately it is not a traded or tradable instrument. There is no open interest in the OPEC basket; there is no forward curve; there is only a simple daily assessment and that might in fact be helpful.

17 February 2011

What’s the real price of oil? 16

Exhibit 22: WTI, Brent and OPEC Basket Prices $/bbl, Jan-2010 - Present

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WTI Brent OPEC Basket

Source: the BLOOMBERG PROFESSIONAL™ service, Credit Suisse Global Commodities Research

As seen on Exhibit 22, while the prompt price spread between WTI and Brent priced at $16.5/bbl, the OPEC Basket is priced $4.5/bbl lower than Brent and $12/bbl higher than WTI.

Exhibit 23: Oil Taxes and Final Oil Price

Source: OPEC

For those analysts who are focused on the US economy and on US prices, there is another route that can be taken for determining the price of oil in the US market. The US Department of Energy has, since the 1970s, been publishing both for the US as a whole and for individual PADD areas within the US, data on average refinery acquisition costs. Traditionally, waterborne and importing crude oil areas, including PADDs 1, 3 and 5 see average refinery acquisition costs that are higher than those in the inland districts of PADD 2 and 4. And the blended price, which is available on a monthly lagged basis, is a realistic indicator of average crude oil prices in the US market. It turns out recently to be a price that is lower than Brent and WTI.

17 February 2011

What’s the real price of oil? 17

Exhibit 24: WTI and Brent Prices vs. DOE Composite Crude Oil Refinery Acquisition Cost $/bbl, monthly average, Jan-2009 - Dec-2010

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WTI Brent Refinery Acquisitation Cost

Source: the BLOOMBERG PROFESSIONAL™ service, EIA, Credit Suisse Global Commodities Research

Economists looking at inflation should be less focused, however, on crude oil prices and should focus their attention more on product prices. Here there is both the advantage of a widely traded international market for the major products, but there is also the significant differentiation of retail prices around the world, which range from very low subsidized prices to extremely high end-user prices because of the taxes often imposed on consumption by governments. OPEC provides a service to those interested by regularly publishing these, although the OPEC website lags the rate of tax change in major consuming countries. OPEC’s interest, of course, is to demonstrate that OECD governments collect more money from a barrel of oil than do the producers themselves.

What’s the real price of oil? Round 2 Even if we could settle on what might be the proper benchmark for measuring the price of oil, there is yet another problem that arises. Oil is normally traded in US dollars. But the US dollar fluctuates greatly against other major currencies, and this has especially been the case since 2007. So what’s the best way to look at the price of oil? Is it in US dollars? Real or nominal dollars? Should it be the price of oil in euros? Yen? Yuan? Or should one look at the price of oil in a basket, such as against DXY or in a SDR-trade weighted basket of some kind? There are several exhibits below that depict different ways of looking at the price of oil. It makes a big difference depending on what perspective one takes.

17 February 2011

What’s the real price of oil? 18

Exhibit 25: Nominal, Dollar Adjusted and Inflation Adjusted WTI Crude Oil Prices

Exhibit 26: Brent Price Adjusted by EUR, SDR and DXY

$/bbl, Base Jan-00 $/bbl, Base Jan-10

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Nominal WTI Price Dollar-adjusted WTI Price Inflation-adjusted WTI Price

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Brent SDR Adjusted Brent Euro Adjusted Brent DXY Adjusted Brent

Source: the BLOOMBERG PROFESSIONAL™ service, Credit Suisse Global Commodities Research Source: the BLOOMBERG PROFESSIONAL™ service, Credit Suisse Global Commodities Research

But that’s not the end of the story either. As has often been pointed out, the price targeted by major oil producers has a great deal to do with the costs associated with their own economies. In recent years as the US dollar has depreciated in value against a number of other major currencies, the costs of “break-even” budgets in many oil-producing countries has also risen at a disproportionately high rate. And hence the target or break-even price for these countries has also gone up, as can be seen on Exhibit 27 .

Exhibit 27: Breakeven Oil Price $/bbl, Amounts are for local crudes

Country Budget Oil Price Deemed Break Even PriceAlgeria 37.00 85.00Bahrain 80.00 75.00Indonesia* 60.00 Iran* 60.00 100.00Kuwait* 43.00 35.00Libya* 50.00 Mexico 65.40 Nigeria 65.00 Norway 82.82 Oman 58.00 65.00Qatar* 55.00 38.00Russia 75.00 100.00Saudi Arabia 55.00 65.00Sudan* 60.00 Syria 48.00/55.00 (heavy/light) UAE 55.00Venezuela 40.00 110.00Yemen 55.00 * Budget for 2010 when 2011 budget not yet announced Source: Credit Suisse

17 February 2011

What’s the real price of oil? 19

Does any of this matter? Yes and no. Clearly it makes some difference whether one looks at Brent, or Dubai, or WTI as a global benchmark. And clearly it matters to some degree whether one focuses on nominal or real prices, or prices in US dollars, euros or some other currency. But the extraordinary overall issue is that except for traders and their focus on relative value trades, and for those who seek some precision in the “real” price for whatever their purpose, one major conclusion pops out from our analysis and from Exhibits 25-26: the fluctuations we have seen in price are so positively correlated no matter what currency is used to denominate that they themselves are more “real” than “nominal.”

17 February 2011

What’s the real price of oil?

20

Appendix

Exhibit 28: Major Canadian and US Crude Oil Pipeline and Refineries

Source: Enbridge

17 February 2011

What’s the real price of oil?

21

Exhibit 29: Proposed Pipeline Exports Routes

Source: CAPP, Enbridge, Kinder Morgan

17 February 2011

What’s the real price of oil?

22

Exhibit 30: Major Canadian and US Refined Products Pipelines

Source: Enbridge

GLOBAL COMMODITIES RESEARCH

NORTH AMERICA

Edward Morse, Managing Director Group Head +1 212 325 1013 edward.morse@credit-suisse.com

Teri Viswanath, Director +1 713 890 1604 teri.viswanath@credit-suisse.com

Hugh Li, Vice President +1 212 538 7025 hugh.li@credit-suisse.com

Joachim Azria, Associate +1 212 325 4556 joachim.azria@credit-suisse.com

Stefan Revielle, Associate +1 212 538 6802 Stefan.revielle@credit-suisse.com

Ivan Szpakowski

LONDON

Ric Deverell, Director +44 20 7883 2523 ric.deverell@credit-suisse.com

Tom Kendall, Vice President +44 20 7883 2432 tom.kendall@credit-suisse.com

Martin Yu, Analyst +44 20 7883 2150 martin.yu@credit-suisse.com

TECHNICAL ANALYSIS Christopher Hine, Vice President +44 20 7888 7171 christopher.hine@credit-suisse.com

Disclosure Appendix

Analyst Certification Joachim Azria and Edward Morse each certify, with respect to the companies or securities that he or she analyzes, that (1) the views expressed in this report accurately reflect his or her personal views about all of the subject companies and securities and (2) no part of his or her compensation was, is or will be directly or indirectly related to the specific recommendations or views expressed in this report.

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