Oil Gas Presentation - Bear

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PLEASE READ THE IMPORTANT DISCLOSURE AND ANALYST CERTIFICATION INFORMATION IN THE ADDENDUM SECTION OF THIS REPORT.

Equity Research

MARCH 2007

Energy PerspectivesHow to Analyze Oil and Refining StocksAn Essential Primer on Energy

OUR GUIDE TO K NOWLEDGEABLY INVESTING IN THE ENERGY SECTOR . Thisreport is meant to be an essential guide to understanding and investing in major oil and independent refining stocks. It explains how to analyze the fundamentals

of oil and gas exploration and production and refining and marketing.

FACT VS. FICTION. We dispel such myths as “bigger is better” and “there isseasonality to refiners’ stock price performance.” Also, what are the cues todetermine how a company might perform in the intermediate term? Whatdifferentiates an efficient operator from others? How should an investor evaluatea company’s growth?

VALUATION MATTERS. Upside and downside risk is assessed on historicalvaluation parameters and current fundamental conditions. We show how todetermine what commodity price is reflected in an oil company’s stock price, and

the upside or downside potential of different outcomes.

INFORMATION CENTRAL. We offer tips on how and where to find pertinentinformation. We provide a guide to important publications, Web sites, Bloombergsymbols, and sources for news retrieval.

Research Analysts Nicole L. Decker Eric Richards, CFA Raymond Sulentic

(212) 272-3962 (212) 272-8946 (212) [email protected] [email protected] [email protected]



BEAR, STEARNS & CO. INC.

Table of Contents Page

Executive Summary............................................................................................................................................................5

Section 1.............................................................................................................................................................................7

The Integrated Oil Company .......................................................................................................................................9

Upstream, Downstream, and Midstream ................................................................................................................9

Exploration and Production Basics............................................................................................................................11

Exploration .........................................................................................................................................................12

Appraisal and Development.................................................................................................................................14

Production...........................................................................................................................................................16

Drivers of Integrated Oils’ Upstream Performance ...................................................................................................17

Oil and Gas Prices ...............................................................................................................................................17

Hedging ..............................................................................................................................................................18

Crude Oil Characteristics.....................................................................................................................................19

Operating Costs and Field Reliability...................................................................................................................20

Exploration Expense............................................................................................................................................21

Tracking Industry Fundamentals ...............................................................................................................................22Fundamental Data Sources ..................................................................................................................................22

Worldwide Crude Oil Inventory Levels ...............................................................................................................23

Supply: Non-OPEC Production ...........................................................................................................................24

OPEC..................................................................................................................................................................25

Capacity Utilization.............................................................................................................................................28

Strategic Reserves ...............................................................................................................................................29

Worldwide Oil Demand.......................................................................................................................................31

A Walk Through Our Worldwide Oil Supply/Demand Model ..............................................................................34

Geopolitical Developments..................................................................................................................................35

Investing in the Integrated Oils..................................................................................................................................37Sensitivity to Changes in Oil and Gas Prices........................................................................................................37

Oil Is a Commodity .............................................................................................................................................39

Two Key Operating Measures: Reserve Replacement and Finding and Development Costs..................................40

Company Strategy: Acquirer or Explorer? ...........................................................................................................44

Pointers and Rules of Thumb ...............................................................................................................................45

Section 2...........................................................................................................................................................................47

Independent Refiners .................................................................................................................................................49

The “Downstream” Industry ................................................................................................................................49

The Refining Process...........................................................................................................................................49

Refined Products .................................................................................................................................................51Drivers of Refiners’ Financial Performance..............................................................................................................53

Refining Margins ................................................................................................................................................53

Refinery Complexity ...........................................................................................................................................56

Light/Heavy Spreads and Product Yields .............................................................................................................57

Operating Costs...................................................................................................................................................59

Plant Reliability...................................................................................................................................................59

Financing and Overhead Costs.............................................................................................................................59



ENERGY PERSPECTIVES

Tracking Industry Fundamentals ...............................................................................................................................60

Interpreting DOE Inventory Reports ....................................................................................................................60

Refinery Utilization .............................................................................................................................................64

Product Imports...................................................................................................................................................66

Gasoline Demand ................................................................................................................................................68

Distillate Demand................................................................................................................................................70

Crude and Product Prices vs. Refining Margins ...................................................................................................71Forecasting Light/Heavy Spreads ........................................................................................................................72

Environmental Regulations..................................................................................................................................73

Investing in Refining Stocks......................................................................................................................................74

Investing in Refiners............................................................................................................................................74

No Seasonal Trade in Refining Stocks .................................................................................................................76

Refinery Acquisitions Are Part of Most Refiners’ Growth Strategy ......................................................................77

Pointers and Rules of Thumb ...............................................................................................................................78

Section 3...........................................................................................................................................................................83

Valuation....................................................................................................................................................................85

The Size Factor: Does It Matter? .........................................................................................................................87Valuation for Independent Refiners .....................................................................................................................88

Section 4...........................................................................................................................................................................91

Industry Resources.....................................................................................................................................................93

Publications.........................................................................................................................................................93

Books..................................................................................................................................................................94

Web Sites ............................................................................................................................................................95

Bloomberg Ticker Symbols .................................................................................................................................96

Reuters News Symbols ........................................................................................................................................97

Consensus Oil and Gas Price Estimates on First Call............................................................................................98

Surveys ...............................................................................................................................................................98

Glossary of Terms......................................................................................................................................................99

All pricing is as of the market close on February 22, 2007, unless otherwise indicated.




Executive Summary

The oil and gas business encompasses several operational segments, including

exploration and production, transportation, trading, refining and marketing, and oil

services and equipment. In our coverage universe, the integrated oils and

independent refiners, the focus is on exploration and production and refining and

marketing, respectively. In this report, we explain how these businesses work,

describe the financial drivers, and explore ways to evaluate financial and operational

performance and gauge fundamentals. Lastly, we describe several approaches to

valuation.

We have used a two-part approach to introduce investors to the business. Section 1

of the report covers the exploration and production segment of the business, the

dominant focus of the integrated oil companies. Exploration is the process of

searching for oil and gas resources — a risky, capital-intensive business. Production

entails extracting hydrocarbons from the ground, processing it, and transporting it to

customers (usually refiners).

In Section 2, we discuss how to analyze the refining and marketing business, with anemphasis on the independent refiners. Refining is the process of converting crude oil

into fuels such as gasoline, diesel fuel, jet fuel, and heating oil. Marketing entails

selling these products to middle- and end-users.

Macro trends greatly influence oil and gas prices and refining margins, given oil

companies’ leverage to prices and margins. An investment in the industry most often

hinges on some assumption of how macro conditions will evolve. We walk through

the sources of information, fundamental indicators, and how to read and apply them

to investing in the sector in the first two sections of this report.

The third section of the report addresses valuation. It examines trading and valuationhistory encompassing several different techniques, including earnings, cash flow, and

EBITDA multiples. We have also observed a strong positive correlation between a

company’s return on capital employed (ROCE) and the multiples applied to its stock.

If we can identify companies with improving ROCE, then we might make a case for

upward revaluation of the share price through a higher multiple. All of this is helpful

in setting share price expectations.

The final section lists data sources and industry publications that we believe are

“must-reads” for anyone that is interested in analyzing and investing in the oil

industry. Essentially, this section is a guide to where to find information on prices,

margins, and macro events that influence oil and refining stocks. This section alsoincludes a glossary, which provides a brief explanation of common industry terms.




Section 1




The Integrated Oil Company

Integrated oil companies are engaged in all phases of the oil business: exploration,

production, refining, and marketing. Some companies also are large manufacturers

and marketers of petro- and specialty chemicals, and generate and sell power. The

exploration and production phase is commonly referred to as the “upstream.” For

most integrated oil companies, the upstream part of the business dominates the

company’s attention and resources, as profit margins typically are higher.

Exploration is the process of searching for oil and gas resources. “E&P” is a risky

business, as drilling a single wildcat well can cost tens of millions of dollars, and

success rates often are below 50%. In Graham and Dodd’s well-known book,

Security Analysis, the E&P business was described as “speculative.” Production

entails taking the oil and gas out of the ground and selling it — usually to refiners.

Refining and marketing is referred to as the “downstream.” Refining is the process

of converting crude oil into fuels such as gasoline, diesel fuel, jet fuel, and heating

oil. Marketing entails selling these products to the end-user. Many of the integrated

oil companies have branded retail gasoline outlets and product lines. To the public,

this is the most visible and identifiable part of the oil company; however, it is the

smallest, lowest-margin portion of most integrated oil companies’ business.

Exhibit 1. Four Phases of the Oil Business

(1) Exploration (2) Production

(3) Refining (4) Marketing

Upstream:

Downstream:

Source: Industry sources.

There is one additional area of the oil business — a step in between the upstream and

downstream phases referred to as the “midstream.” The midstream entails

transportation and storage of oil, gas, and refined products. We will not focus on the

midstream business. Most integrated oil companies own pipeline and storage

facilities, particularly at production operations in remote areas. But elsewhere,

particularly in the U.S., pipeline infrastructure is operated by independent pipeline

companies. For most integrated oil companies, transportation and storage is a cost,

rather than a profit center. These costs are included in most companies’ upstream

financial results.

UPSTREAM,

DOWNSTREAM, AND

MIDSTREAM



Interestingly, many integrated oil companies do not attempt to integrate their

upstream and downstream businesses directly. They do not necessarily move their

own oil production through their own refineries, or their own refining output through

company-owned stations, since it is usually more efficient and profitable to buy and

sell crude and refined products locally, to avoid transportation costs. The benefit of

being integrated is twofold: first, it allows companies to capture margins throughout

the value chain, and, second, earnings volatility may be mitigated, as large moves in

one segment may be muted or even partially offset by moves in the other sector.

Nevertheless, earnings are volatile (see Exhibit 2). The most influential factor on

integrated oil company earnings is the price of oil. Refining margins are the largest

driver of earnings in the refining and marketing segment.

Exhibit 2. Major Oil Companies Earnings in E&P and R&M

0

20000

40000

60000

80000

100000

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

O p e r a t i n g E a r n i n g s ( $ m i l )

R&M E&P

E&P

R&M

WTI ($/bbl) $22.14 $20.17 $14.48 $19.15 $30.36 $25.44 $26.02 $31.06 $41.29 $56.51 $66.03

GC Refining Margins ($/bbl) $3.34 $3.63 $2.97 $2.40 $5.64 $5.29 $3.75 $4.98 $6.97 $10.35 $9.76

Source: Company reports.

Investors wishing to focus specifically on E&P or on refining and marketing may

consider an investment in an independent exploration and production company or an

independent refiner — companies whose operations are solely in the upstream or

downstream portion of the oil business.

This section of the report covers the upstream portion of the business (refining and

marketing is covered in Section 2). In this section, we describe how oil and gas is

found and how reserves are developed. We describe the financial and operationaldrivers of the business and how to measure them. In addition, we show how to

evaluate the integrated oil companies.

The exploration and production business is risky and capital-intensive. Large sums

of money can be spent with the risk of a complete loss (i.e., a dry hole). In some

cases, it can take decades before the investment generates any revenue, given long

lead times between exploration and production. Success in this business requires

high technical capabilities, capital discipline, good operational execution, and some

luck.




Exploration and Production Basics

Exploration and production (E&P) is a multipart process oil companies undertake to

locate oil and gas resources (land acquisition, surveying, and drilling), determine

commerciality (appraisal), install the necessary equipment and infrastructure to

commence production (development), and, finally, remove the oil and gas (producing

it) from the ground for sale. This section provides an introductory, nontechnical

description of each phase of the business. Additional resources are provided in the

appendix of this report for further reading.

First, the following background points may be helpful:

How Were Oil and Gas Deposits Formed? It is widely believed that oil and

gas was formed from material derived from dead plants and animals that lived

millions of years ago, transformed by heat and pressure into oil and gas.

Where Are These Deposits Found? Oil and gas deposits can be found in a

variety of environments: on land or offshore, at shallow or deep depths, in

temperate or harsh climates. Oil deposits are common in river deltas (or, in somecases, former river deltas transformed to dry land or sea over time), where the

river’s flow deposited large amounts of organic sediment.

How Do Oil Companies Look for Oil and Gas Deposits? To find oil and gas,

geologists look for the following combination of rocks below the earth’s surface:

rock that contains organic remains (source rock); rock that the oil can flow into

(reservoir rock); and a layer of impermeable rock to prevent the oil and gas from

flowing away (cap rock). Locating prospects is done through a combination of

data surveys such as seismic imaging, and gravitational and magnetic surveys.

Is the Business Different Today than It Used to Be? It has been argued thatthe “easy” oil has been found and produced, that is, oil in shallow wells in a

temperate operating environment. However, in the approximately 140-plus years

since oil was first produced commercially, new technologies have made it

possible to drill deeper, and to operate in the harshest climates, such as Siberia,

Russia, and deep in the tempestuous North Sea — and at low cost. Advances in

seismic imaging and sophisticated reservoir modeling capabilities provide more

comprehensive data on drilling prospects, and new drilling technologies have

extended exploration to deeper, more complex reservoirs. The industry has risen

to the challenge of more than replacing production, and of keeping pace with

rising demand for oil and gas.

The goal of an exploration and production company is to add oil and gas reserves, the

primary assets of the company, at a cost that provides the best return on capital.



Exploration is the effort to add new oil and gas reserves by drilling in an area where

oil and gas has not been discovered. Exploration drilling differs from development

drilling, which is undertaken to produce reserves which are known to exist.

Exploration is perhaps the riskiest yet most critical phase of an oil company’s

operations — risky because of the high cost associated with drilling a well,

oftentimes several thousand feet into the ground, and critical because companies’

assets deplete each day that oil and gas is produced. If production is not replaced bynew resources, the company will shrink and eventually run out of reserves. Organic

growth occurs when the company discovers more recoverable oil than it is producing.

Lease Agreements, Concessionary Agreements, and PSCs

The first step in the exploration process is acquiring the rights to explore for and

develop oil and gas, usually accomplished through execution of a lease with the

landowner. Landowners may be private individuals, such as ranchers and farmers.

This is common in areas of the U.S. and Canada, where the landowner also owns the

mineral rights. Lease terms can differ, but, in general, in addition to a bonus

typically paid to the landowner upon signing, terms may cover the following:

Duration. Duration is the amount of time given to the oil company to establishcommercial production.

Royalty Payments. Royalty payments are usually a fraction of the revenue fromoil and gas produced from the property. Most commonly, private landownersreceive approximately one-eighth of the revenue, but royalty payments may be ashigh as 50% in certain areas.

Drilling Commitment. In some cases, the oil company commits to a certainnumber of exploratory wells.

Surface Access. The oil company is granted rights to conduct operations on thesurface, such as build roads, etc.

Outside the U.S. and Canada, the government typically holds mineral rights,

requiring a contract called a “concessionary agreement” between the government and

the oil company. In a concessionary agreement, mineral rights are transferred to the

oil company. Terms of a concessionary agreement are much like the lease agreement

outlined above, but various types of taxes, such as income tax, a production tax, or a

value-added tax (VAT), may also apply. In some countries, the government retains

mineral rights, and if reserves are discovered, the government would maintain

ownership of these reserves. In this case, the arrangement between the government

and the oil company is called a “production-sharing contract” (PSC). Under a PSC,the oil company (known as the contractor) essentially bears all the risk and cost of

exploration and development. Contract terms allow the contractor to recover these

costs if oil is discovered. It is important to note that, originally, PSCs were set up to

protect the oil companies’ investment in the event that oil prices decline. Under the

PSC, the contractor recovers exploration and development costs by retaining a

portion of the production, known as “cost oil.” This portion can vary depending on

oil prices. “Profit oil” is the amount of oil left after deducting royalties, taxes, and

EXPLORATION




cost recovery. This is typically shared between the partners based on proportions

agreed upon in the contract.

Identifying and Drilling Prospects

Next, an oil company undertakes an information-gathering process, conducted largely

by geologists, to identify possible drilling prospects. What are the geologists looking

for? They are taking clues from surface and subterranean surveys to determinewhether the necessary characteristics exist for a commercial-sized accumulation of

oil and gas (hydrocarbons) beneath the surface of the earth. The surveys help

geologists to determine the presence of a source rock, reservoir rock, and a cap rock

to keep the hydrocarbons in place. These, at a minimum, are necessary in order for a

reservoir of hydrocarbons to exist.

Geologists also look for a combination of rock layers that may “trap” oil deposits. A

trap occurs naturally when rocks have moved or folded beneath the Earth’s surface.

One type of trap is known as an anticline trap, which, shaped like an upside down

bowl, is a layer of impermeable cap rock holding oil in place. Another type of trap is

a fault trap, which is created when rock layers slide past each other underground. Animpermeable rock layer then acts as a dam, allowing a reservoir to accumulate. Salt

domes are another form of trap. Salt domes are formed when rock movements and

pressure thrust salt from deep deposits upward through the layers of rock. If a layer

of porous rock containing oil and gas meets the salt dome, which is impenetrable, the

oil and gas is trapped.

Exhibit 3. Oil Traps

. . .

…

OIL

gas

. . …

Anticline

. . .

.

..

...

. . .

.

.

gas

.

.

.

.

Fault

.

.

.

OIL.

.

.

..

Salt

gas

OIL

.

Salt Dome

.

.

.


Even with today’s advanced technology, interpretation of survey data can be difficult

and uncertain, and until a well is drilled to the target area, there is no guarantee of the

existence of an oil deposit. Typically, oil companies accumulate a portfolio of

prospects, ranked according to potential size and risk.

Selection of prospects to advance to the drilling phase is much like selection of

stocks for a portfolio. Drilling prospects may have a variety of characteristics that

distinguish them in terms of risk, complexity, estimated drilling costs, and potential

size, among other factors. High-risk wells are often those with potentially higher

rewards — a large reservoir of hydrocarbons. Oil companies might select a variety

of types of prospects to drill each year to diversify risk.



The highest-risk prospect is known as a wildcat well — a well drilled in an area

where no hydrocarbons have been discovered. The cost of drilling a single,

deepwater exploration well averages about $30 million, but some may exceed $100

million. The success rate (success meaning an oil or gas discovery) for such wells in

a “frontier,” or unexplored region, is less than 15%. Most integrated oil companies

engage in some frontier, or wildcat, exploration activity, in search of large

discoveries of new resources. A discovery of 200 million-plus barrels of oil

equivalent (boe) would be considered significant by the industry, though smaller discoveries can be developed economically. In the past ten years, several discoveries

have exceeded this size, mostly in offshore deepwater regions, such as Angola,

Malaysia, Brazil, in the Gulf of Mexico, and in the Former Soviet Union.

To reduce risk, oil companies often take on partners, or “farm out” a portion of the

interest in a prospect. One company, usually the largest interest holder, acts as the

operator of the project. Drilling costs are shared and, if successful, the partners share

the development costs. Production revenues are allocated in proportion to each

partner’s interest.

Not all exploration drilling is in search of an “elephant,” as large discoveries arecalled in the industry. Oil companies typically undertake exploration in areas of

producing fields, or in the vicinity of an undeveloped discovery, as in a “satellite”

well. There are two advantages to drilling a satellite well. First, more is known

about subsurface properties, given drilling has already occurred in the area; and

second, production from a successful satellite can usually be “tied in” to

infrastructure at nearby fields, reducing development costs and cycle time. This

might allow for development of a smaller discovery that would otherwise be

noncommercial as a stand-alone development. Another type of exploration well is

known as an extension well, where a company drills a well in hopes of extending the

boundaries of a producing field. Another type of exploration well is a “delineation,”

or “appraisal,” well, which is drilled to determine the extent or boundaries of a newfield. Drilling at these types of wells typically achieve a significantly higher success

rate than a wildcat well.

There are two ways a company can account for the cost of drilling an exploration

well: successful efforts and full cost accounting. The integrated oils all use

successful efforts accounting. With this method, if a well is successful, the

associated costs are capitalized, and development plans are made. If unsuccessful,

the costs are expensed in the time period in which they were incurred — charged as

dry hole expense on the income statement. These expenses can swing from quarter to

quarter, depending on the company’s drilling schedule and success rate. Under full

cost accounting, used by about half of the independent E&P companies, allexploration costs are capitalized.

Oftentimes, the commerciality of a reservoir cannot be determined after drilling just

one well. If hydrocarbons were found in the first well of a prospect, a company will

drill one or more (sometimes as many as five or six) additional appraisal wells in

order to assess the size and properties of a field. After the appraisal process, if the

field is deemed to contain sufficient quantities of recoverable oil and/or gas, the field

undergoes its most expensive phase — development. During development, after

extensive engineering and design work, the company will drill wells from which the

APPRAISAL AND

DEVELOPMENT




oil and gas will be produced, and production equipment is fabricated and installed at

the site. Development costs vary, depending on the size and location of a well, but

on average, we estimate development costs run $5.00 per barrel of oil equivalent

(boe) of proved reserves (onshore wells typically run below this figure, while

deepwater offshore wells could exceed this figure). So, development of a moderate-

sized field, of say, 100 million boe, can cost approximately $500 million, in addition

to exploration costs of, perhaps, $100-$200 million. All the while, the field has yet to

produce any revenue for the company.

All development costs are capitalized. In essence, exploration and development costs

for a field will become the carrying value of the reserves in the field. Finding and

development (F&D) costs, as these costs are known, are a key performance metric in

the oil industry, as they help dictate the return on capital for a field. In general,

development costs comprise approximately two-thirds of F&D costs, though this

proportion can drift higher when services costs are higher, typically when oil prices

are high. The carrying value will be depreciated once production begins. The F&D

costs for a particular field are an indicator for the depreciation, depletion, and

amortization (DD&A) rate at a field once production begins.

The engineering and planning phase of the development process is crucial to the

economic success of a field. Engineers are concerned with reservoir quality —

porosity (a measure of the fraction of the rock containing the oil that is pore space,

expressed as a percentage), permeability (a measure of how well fluids flow between

the pores), and well flow rates (measured in boe per day [boe/d]) — not only today,

but throughout the life of the field. A greater level of porosity and permeability are

desirable, as this facilitates recovery of the oil, which helps keep production costs

down. A field can start out with very promising characteristics, which can deteriorate

rapidly once production begins. For this reason, much effort is given in making sure

a field will perform consistently through extensive well testing before the high front-

end development costs are incurred. The appraisal and testing process for someoffshore deepwater fields can take years.

Oil companies have an array of options on development configurations. Location of

the well is usually the largest factor in determining the type of production equipment

installed. The simplest to develop are onshore wells — often the discovery well is

completed and put on production, a relatively quick process. If the well performs as

expected, additional development wells, or “step-out” wells, may also be drilled and

completed. Development of wells in shallow water (less than 15 feet) is carried on in

the same manner, except the drilling rig is mounted on a barge. The top of the

wellhead, which has been installed beneath the water line, extends above the water.

Development in deeper water requires that a platform, either bottom-supported or a

floating platform, be installed. The platform must be a large structure to support

multiple wells, as well as drilling and production equipment, including pumps,

compressors, a gas flare system, cranes, helicopter pad, and crew living quarters. The

“topside” — the portion resting on top of the structure, can weigh up to 40,000 tons.

During the development phase, a drilling rig is moved around the platform on skids.

Development wells are completed as they are drilled. A platform in a deepwater,

inhospitable climate (such as the North Sea) can cost $3 billion or more.



Production begins when a well is “completed,” and the infrastructure for delivery has

been fully installed. A wellhead is installed on the surface, which connects piping in

the well to pipes above the ground. A valve system known as a “Christmas tree” is

installed on the wellhead to manage the flow (see exhibit below).

Exhibit 4. Christmas Tree and Wellhead Installation


When a field enters the production phase, the oil companies’ focus shifts to reservoir

management to assure maximum oil or gas production over the life of the reservoir.

No reservoir can be drained completely, but poor management will result in

inefficient production and a shortened reservoir life.

Oil companies may consider a variety of options to help lift oil and gas to the surface,

as in most fields only a fraction of the oil can be produced by natural reservoir

pressure. Production at most wells often includes some form of “artificial lift,” or

pumping equipment. When a pump can no longer maintain stable oil flow, an oil

company may further increase recovery using techniques that restore pressure and

flow in reservoirs. This entails injection of water, gas, chemicals, or heat into the

reservoir.

A common enhanced recovery procedure for onshore fields is called “infill” drilling.

As a reservoir becomes depleted, the company may drill a new well in between

producing wells.

In many producing fields, it is common for a mixture of oil, gas, and water to reach

the wellhead. At the wellhead, the mixture is sent through a pipeline gathering

system to a treatment facility, where oil, gas, and water are separated. The oil is then

sent on to storage or markets through pipelines or by truck.

PRODUCTION




Drivers of Integrated Oils’ Upstream Performance

We believe the following items are the most important drivers of oil companies’

financial performance:

Oil and Gas Price. More than any other factor, all oil companies’ revenues are

affected by commodity prices.

Crude Oil Characteristics. The price the oil company receives is dependent

upon the oil’s density and sulfur content, which affect the grade of the crude oil.

Lighter (less-dense) and sweeter (containing less sulfur) crude oil is more

valuable than heavy, sour grades, because less processing is required at the

refining level to create lighter products.

Operating Costs. Operating costs are also called lifting costs, or production

costs. Based on the many possible production configurations described in the

previous section, operating costs can vary by field. An oil company’s

profitability will be affected by the cost of extracting oil and gas from the ground.

Operating costs include labor and energy costs, maintenance, repair, taxes,insurance, and depreciation.

Field Reliability. Unplanned downtime can have a meaningfully adverse effect

on profitability through loss of productivity as well as by well workover expense.

Exploration Expense. As described in the previous section, drilling costs for

unsuccessful exploration wells are expensed by integrated oil companies in the

period in which they were incurred. The high cost of drilling can take a toll on

earnings for an integrated oil company if the exploration program is

unsuccessful.

Oil and gas prices are the most influential factor on oil company revenues and

earnings. Oil prices are dictated by a variety of macro conditions, which are covered

in a later section of this report. Because of this sensitivity, oil company stock prices

often move in tandem with changes in oil prices. This is particularly true when oil

stock performance is measured relative to the broader market (see Exhibit 5).

OIL AND GAS PRICES



Exhibit 5. Integrated Oils’ Relative Price Performance vs. Changes in Oil Prices

0

10

20

30

40

50

60

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

$ / b b l

0.5

0.7

0.9

1.1

1.3

1.5

1.7

1.9

R e l a t i v e P e r f o

r m a n c e

WTI Price (left) Integrated Oils Relative Performance to S&P (right)

Source: Platts; Standard & Poor’s.

To help manage their exposure to commodity price fluctuations, some oil companies

undertake hedging to lock in commodity prices, usually by selling production

forward through derivative instruments, including swaps and collars. Several sets of

circumstances may prompt hedging activity. The most obvious reason to hedge is to

lock in high prices in a favorable price environment. Another situation that may

promote hedging is the anticipation of exceptionally heavy spending, say, to fund the

development of a large field. Oil companies have also hedged production of acquired

assets, assuming a certain return on investment near term and cash flow to offset the

purchase price.

There are also compelling reasons not to hedge. First, it is difficult to know when

prices are at the top, leaving companies vulnerable to hedging losses, particularly

when fees are factored in. Second, although the market for derivative instruments

used for hedging is expanding, it is still limited, making it difficult for major oils to

hedge large volumes of production.

Recently, some oil companies have arranged forward sales of a portion of their oil

and gas reserves and used proceeds to repurchase their stock. The idea is to try to

close the gap between the medium-term futures market for oil and gas, and the

implied oil and gas price that belies the company’s stock price. In 2005, Pioneer

Natural Resources, through a series of volumetric production payments (VPPs)

transferred title on just under 28 million boe and used the proceeds to repurchase

stock and reduce debt. Activist Carl Icahn prompted Kerr-McGee to sell oil and gas

production forward and repurchase stock.

HEDGING




We have observed that investors generally view the impact of hedging as a “onetime”

gain or loss, rather than as a part of sustainable earnings. Therefore, the stock market

rarely rewards a company for hedging. If oil prices rise, management is held

accountable for missing the move. If oil prices fall, the opportunity to sustain

earnings from hedging activities is seen as fleeting.

Crude oil comes in many different grades, depending upon the amount of carbon,

sulfur, and other metals, or other impurities, such as wax (paraffin), it contains.Crude oil is made up of hydrocarbon molecules, a combination of hydrogen and

carbon atoms. The size and type of molecule (as well as the nature and volume of

contaminants it contains) determines the oil’s characteristics. Oftentimes, when an

oil company announces completion of a well, or a successful appraisal, it will release

data on the gravity and quality of the crude. This is because higher-quality crudes

can fetch prices that are an average $2.00/bbl-$15.00/bbl above those of lower-

quality crudes. The price spread between high- and low-quality crude depends on the

various characteristics of the crude, as well as supply/demand for each type of crude.

Light vs. Heavy. Crude oils generally are characterized by their density, or

weight per volume of oil measured as American Petroleum Institute (API)gravity, expressed in degrees. API gravities range from ten to 50 degrees, with

the higher end of the range representing lighter crudes. Most fall in the 20- to 45-

degree API gravity range. The API gravity of freshwater is ten degrees (recall

that oil floats on water; in other words, water is heavier than oil). Density

classifications for crude oil include light, medium, and heavy (also extra light and

extra heavy). The industry defines light crude oil as having an API gravity

higher than 31.1 degrees, medium oil as having an API gravity between 31.1 and

22.3 degrees, and heavy oil as having an API gravity between 22.3 and ten

degrees. Extra-heavy oil (i.e., bitumen) has an API gravity of less than ten

degrees. Lighter crudes are more valuable because they have a higher energy

content. West Texas Intermediate (WTI), the U.S. benchmark crude, has an APIgravity of 40 degrees.

The formula for determining API gravity is as follows:

Degrees API Gravity = (141.5/Specific Gravity at 60° F) – 131.5

Sweet vs. Sour. Crude oil is also classified as sweet or sour, depending upon its

sulfur content. Sweet crude has less than 0.5% sulfur content, while sour crude

has more than 0.5%. Sweeter crude oils are more valuable, as they are less

expensive to refine. Sulfur and other impurities must be removed from the crude

oil to manufacture gasoline and other refined products. WTI is a sweet crude oil,with a sulfur content of 0.3%.

CRUDE OIL

CHARACTERISTICS



Exhibit 6. Crude Oil Grades

Crude Oil Source API Gravity Sulfur Content

Heavy

Maya Mexico 22o3.30% Sour

Oriente Ecuador 25o1.30% Sour

Bow River/Hardisty Canada 25.7o2.10% Sour

Intermediate/Light

Alaska North Slope U.S. 29o1.10% Sour

Cano Limon Colombia 29.5o0.50% Sweet

Dubai United Arab Emirates 31.2o2.01% Sour

Cabinda Angola 32.5o0.13% Sweet

Urals Russia 32.5o1.25% Sour

West Texas Sour U.S. 33o1.60% Sour

Arab Light Saudi Arabia (Ghawar) 34o1.66% Sour

Basrah Light Iraq 34o2.00% Sour

Bonny Light Nigeria 34.5o0.10% Sweet

Minas Indonesia 36o0.08% Sweet

Brent U.K. North Sea 38.5o0.40% Sweet

West Texas Intermediate U.S. 40o0.30% Sweet

Extra Light

Forties U.K. North Sea 40.4o0.35% Sweet

Griffin Australia 55o0.03% Sweet

Source: Platts.

Wax Content. The wax content in oil affects its viscosity, which measures the

oil’s resistance to flow. The less wax present, the easier the oil flows. Highly

viscous oil is thick and/or sticky, and of lower value. Wax may be removed

during the refining process, and sold as “petroleum wax,” the most common type

of wax found in candles. Viscous oil is also the feedstock for base oils used to

make lubricants.

Operating costs, also called production or lifting costs, are an important driver of oil

companies’ profitability. Measured in unit cost per barrel of oil equivalent, average

production costs for the major oils have typically averaged in the $9.00/boe-

$11.00/boe range, including historical average DD&A costs of approximately $4.00-

$5.00/boe (DD&A costs are noncash costs). Production costs typically rise when oil

prices rise. For instance, average total production costs for the major oils rose to

approximately $14.00/boe in the 2005 high oil price environment. Cash operatingcosts, also called lease operating expense, include a high proportion of fixed costs,

including labor and insurance, semi-fixed costs (such as those incurred for gathering,

field processing, and storage), and variable costs such as energy costs. Historically,

average cash production costs for the industry were consistently in the $4.50/bbl-

$7.00/bbl range (see Exhibit 7); however, costs have risen alongside the increase in

oil prices beginning in 2004.

OPERATING COSTS

AND FIELD

R ELIABILITY




Exhibit 7. Cash Production Costs

$4.53 $4.76

$5.97

$6.48

$5.66$6.12 $6.16 $6.23 $6.14

$6.64$6.99

$8.79

$5.38

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

1 9 9 3

1 9 9 4

1 9 9 5

1 9 9 6

1 9 9 7

1 9 9 8

1 9 9 9

2 0 0 0

2 0 0 1

2 0 0 2

2 0 0 3

2 0 0 4

2 0 0 5

C a s h P r o d u c t i o n C o s t s ( $ / b o e )

Source: Company reports.

Exploration costs are those associated with the cost of exploring a property for oil or

gas, including non-drilling costs such as geological and geophysical expense (G&G)

and drilling cost. These expenses are accounted for by two generally accepted

methods in the event of unsuccessful wells — successful efforts, whereby

unsuccessful wells are expensed as incurred, and full cost, whereby unsuccessful

wells are capitalized. These accounting treatments were discussed earlier.

Earnings of a company using successful efforts accounting can be significantly

affected by exploration expense. As discussed earlier, exploration costs can vary,

given a wide range of depths, environment, geological structures, etc. The amount

expensed will also depend on the oil company’s working interest in the prospect. Oilcompanies may manage the exposure to exploration expense by spacing the timing of

the drilling of expensive and risky wells and/or by farming out partial interests in

potential high-cost wells. If a well is successful, a company using the successful

efforts method may capitalize the costs associated with drilling the well. G&G costs

are expensed regardless of the outcome of the drilling. Development costs on a

successful well are capitalized.

EXPLORATION

EXPENSE



Tracking Industry Fundamentals

Oil companies’ earnings are most influenced by oil and gas prices. As with any

commodity, oil prices are driven by supply and demand. An oversupplied market

usually will dampen oil prices (the relationship broke down in 2004), and vice versa.

Investors and analysts usually pay close attention to the following fundamental data:

worldwide crude oil inventory levels;

non-OPEC production;

OPEC production;

capacity utilization of swing producers;

strategic reserves;

worldwide oil demand; and

geopolitical developments.

In the past, oil prices have closely tracked these fundamental indicators. Lately,

however, as we will explain in more detail, oil prices have diverged from indicated

levels. We think this is temporary, but it does introduce the notion that for short

periods, non-fundamental factors (in this case, speculation of a possible price spike

due to a disruption in supply) can also impact the commodity price. Over time, we

expect fundamental indicators to come back into focus.

Two factors make oil prices difficult to forecast: 1) OPEC, which attempts to

influence oil prices by changing supply, and 2) unreliable data. Statistics on oil

supply are voluminous, perhaps more so than for any other commodity or industry.Yet, much of the information is incomplete or just plain wrong. For example, no

attempt is made to count more than half of the world’s oil inventories — secondary

(that held by distributors) or tertiary (that held by consumers) stocks. Many

emerging countries, which recently have had a large impact on demand, do not report

statistics in a timely manner. Some do not report accurate figures. Even in the U.S.,

where two reputable authorities — the Department of Energy (DOE) and American

Petroleum Institute (API) — report weekly oil inventory, production, and import

figures, the weekly releases often show vastly different trends. Both reports are

revised frequently.

A widely used source for worldwide oil industry statistics is the International EnergyAgency (IEA), the main organization that represents a 26-member consortium of oil-

importing nations based in Paris, France. Membership consists predominantly of

Organization for Economic Cooperation and Development (OECD) nations, although

the agency also has relationships with non-OECD nations. In particular, the IEA is

working with China, India, and Russia to formalize reporting procedures. The

agency publishes a monthly statistical report, which is available by subscription, but

is made available for no charge on a delayed basis (see www.IEA.org). The report

contains extensive and detailed analysis of oil supply, demand, and inventories, and

FUNDAMENTAL DATA

SOURCES




includes forecasts. However, despite the IEA’s level of statistical detail, which

sometimes involves supply projections on a field-by-field basis, its data are revised

frequently and significantly. It is not unusual for the agency to add or subtract

millions of barrels from historical supply, demand, or inventories. Oftentimes,

supply, demand, and inventory figures do not reconcile, leading to a mystery of

“missing barrels.”

Reporting in the U.S. is more timely than elsewhere. The DOE’s statistical arm, theEnergy Information Administration (EIA), publishes inventory data on a weekly

basis (10:30 a.m. on Wednesdays), and demand data are published monthly (see

www.eia.doe.gov). Oil and gas operators, refiners, storage, and distribution

companies are all required to submit information to the government weekly.

Falsified information is punishable by a civil fine and lots of embarrassment. This is

why we prefer the EIA weekly reports to those published by the API, whose survey is

less thorough (participation is voluntary). Though not perfect owing to timing issues

(i.e., shipments of crude from very large vessels are not on a regular schedule, so one

week may contain more deliveries than the one before or after), we believe the EIA

data provide a reasonable picture of supply, demand, and inventories over time. We

believe that, in many cases, it is reasonable to extrapolate U.S. inventory trends,gleaned from EIA reports, to the rest of the world. After all, oil is a worldwide-

traded commodity. If oil is in oversupply (demonstrated by large builds in EIA-

reported stocks week after week), it is unlikely that inventories are building only in

the U.S. and not everywhere else, too.

We believe that it is more important to spot trends in fundamentals, using source data

as a tool, rather than relying on specific forecasts. An extensive list of industry data

sources is presented in Section 4.

Changes in oil inventories around the world are an indicator of supply/demand

balance. In an oversupplied market, worldwide inventories build. Rising inventoriesare usually accompanied by falling prices, and vise versa.

Exhibit 8 below illustrates the historical relationship between oil inventories in the

U.S., the world’s largest energy consumer, and oil prices. In the chart, the right-hand

axis showing oil inventories is reversed to show a positive relationship (and to

display the strong correlation between oil prices and inventories — an r-square of

0.87 between 1995 and 2004). Low inventories typically translate into high oil

prices, and rising inventories usually accompany declining prices. Note that the

relationship broke down beginning in January 2004, when we believe non-

fundamental factors such as speculation over terrorist fears overshadowed

fundamentals. As seen in the chart, oil inventory levels throughout much of 2005-06were consistent with an oil price in the $10/bbl-$20/bbl range, versus the actual spot

price in the high $50s/bbl.

While terrorism fears and speculation played a role in this disconnect relative to

historical trend, we now believe that underlying fundamentals for light/sweet crude

oil were very tight, and this contributed to a surge in prices for this type of crude. In

2004, demand for refined products rose sharply in the Asia/Pacific region. To meet

this demand, idle refining capacity — capacity that had been built in the 1990s in

anticipation of this demand — was called into service. However, the refining

WORLDWIDE CRUDE

OIL INVENTORYLEVELS



capacity was outdated, in that it required light/sweet crude oil as feedstock. Prices

for light/sweet crude oil such as WTI began to rise. To stave off the increase in crude

oil prices, OPEC, the world swing producer, increased production. However, the

incremental production from OPEC was lower-quality crude, for which there was no

added demand. Incremental supplies of low-quality crude filled worldwide

inventories. These factors all contributed to the trends that began in 2004 — rising

WTI prices, increasing worldwide oil inventories, and all-time wide light/heavy

spreads.

Exhibit 8. Relationship Between Oil Inventories and Oil Prices

10

20

30

40

50

60

70

80

J a n - 9 5

M a y

- 9 5

A u g

- 9 5

D e c

- 9 5

A p r - 9 6

J u l - 9 6

N o v

- 9 6

M a r - 9 7

J u n - 9 7

O c t - 9 7

F e b

- 9 8

M a y - 9 8

S e p

- 9 8

J a n - 9 9

A p r - 9 9

A u g

- 9 9

D e c

- 9 9

M a r - 0 0

J u l - 0 0

N o v

- 0 0

M a r - 0 1

J u n - 0 1

O c t - 0 1

F e b

- 0 2

M a y

- 0 2

S e p

- 0 2

J a n - 0 3

A p r - 0 3

A u g

- 0 3

D e c

- 0 3

M a r - 0 4

J u l - 0 4

N o v - 0 4

F e b - 0 5

J u n - 0 5

O c t - 0 5

J a n - 0 6

M a y - 0 6

S e p

- 0 6

W T I S p o t P r i c e s ( $ / b b l )

175,000

200,000

225,000

250,000

275,000

300,000

325,000

350,000

C r u d e O i l I n v e n t o r i e s ( 0 0 0 s b b l s )

WTI Spot Oil Prices Crude Oil Inventories

Since January 2004, the

correlation between crude oil

prices and inventory levels has

broken down.

Source: Energy Information Administration; Platts.

Non-OPEC production comes from publicly traded oil companies (such as the

integrated oils in our coverage universe), from national oil companies (NOCs) of

non-OPEC nations, such as Pemex, the national oil company of Mexico, and,

particularly in the U.S., from privately held independent E&P companies.

SUPPLY: NON-OPEC

PRODUCTION




Exhibit 9. Non-OPEC Production

0

10

20

30

40

50

60

1 9 8 8

1 9 8 9

1 9 9 0

1 9 9 1

1 9 9 2

1 9 9 3

1 9 9 4

1 9 9 5

1 9 9 6

1 9 9 7

1 9 9 8

1 9 9 9

2 0 0 0

2 0 0 1

2 0 0 2

2 0 0 3

2 0 0 4

2 0 0 5

2 0 0 6

M i l l i o n b

/ d

Non-OPEC production

~2% per year

Source: International Energy Agency.

Supply from non-OPEC producers has increased steadily. Since 1988, we estimate

oil production from non-OPEC sources to have risen by an average of 2% per year.

The Organization of the Petroleum Exporting Countries, or OPEC, was formed in

1960. Made up of 12 member nations (in the early days, membership was 13 —

Ecuador and Gabon dropped out, and Angola was added in 2007), the organization

was first formed to provide a large unified voice on oil industry issues. The group

evolved into a cartel in 1973. This was about the same time that production in the

U.S., which until then was the world’s largest oil producer, began to decline.

Exhibit 10. OPEC Member Nations

Country Membership history

Iran September 1960 Founder Member

Iraq September 1960 Founder Member

Kuwait September 1960 Founder Member

Saudi Arabia September 1960 Founder Member

Venezuela September 1960 Founder Member

Qatar Member since December 1961

Libya Member since December 1962

Indonesia Member since December 1962

United Arab Emirates Member since November 1967

Algeria Member since July 1969Nigeria Member since July 1971

Angola Member since January 2007

Ecuador Joined November 1973; left OPEC in 1992

Gabon Joined December 1973; left OPEC in 1996

Source: OPEC.

OPEC



As the U.S. became a net importer, OPEC realized its dominant position in world oil

supplies and its ability to influence oil prices. In October 1973, OPEC initiated an

embargo (to protest U.S. and other Western nations’ support of Israel during the Yom

Kippur War), and in a matter of weeks, world oil prices tripled. Gasoline rationing

occurred in the United States. The embargo was lifted in 1974, but the industrialized

world became acutely aware of its dependence on oil from the Middle East.

Until the early 1970s, oil operations outside the U.S. were conducted on a concession basis, giving oil companies the right to explore for, own, and produce oil in oil-rich

regions such as the Middle East. But, beginning in about 1971, a movement among

oil exporting nations for sovereignty over their natural resources evolved. Countries

such as Libya, Algeria, Iraq, Saudi Arabia, and Venezuela increased their

governments’ participation in their countries’ oil operations, with a gradual

movement toward complete nationalization. This unraveled relationships between

oil-exporting nations and oil companies, and further increased OPEC’s influence in

the marketplace.

Since 1973, other price shocks have occurred. Oil prices reached their highest level

ever, in real terms, in 1979, as the Iranian Revolution ravaged many of Iran’s producing fields, disrupted supplies, and caused a tightening of oil supplies. Oil

prices held up owing to an eight-year war between Iraq and Iran, starting in 1982,

which led to frequent production outages in those two countries. In fact, to this day,

oil production in Iraq and Iran has not reached pre-1978-79 levels. Oil prices surged

again in 1990, when Iraq invaded Kuwait in an attempt to control its oil fields.

Coalition forces led by the U.S. ended the Iraqi occupation, and oil prices fell.

Although OPEC has struggled to maintain its market share (Exhibit 11), it is still a

powerful influence in world oil markets. OPEC nations are estimated to contain two-

thirds of the world proven reserves. The organization generally meets at its

headquarters in Vienna, Austria, twice a year, although it has met more frequently inthe past year. At these meetings, among other things, the organization sets

production quotas for member nations, which it believes will achieve targeted price

levels.

Exhibit 11. OPEC Market Share

5

10

15

20

25

30

35

1 9 8 8

1 9 8 9

1 9 9 0

1 9 9 1

1 9 9 2

1 9 9 3

1 9 9 4

1 9 9 5

1 9 9 6

1 9 9 7

1 9 9 8

1 9 9 9

2 0 0 0

2 0 0 1

2 0 0 2

2 0 0 3

2 0 0 4

2 0 0 5

2 0 0 6

2 0 0 7 E

M i l l i o n B a

r r e l s p e r D a y

20%

25%

30%

35%

40%

45%

50%

55%

% o f W o r l d P r o d u c t i o n

OPEC Crude Production % of World Production

Source: International Energy Agency.




While most OPEC oil ministers describe stable oil pricing as a desired goal, we

believe price stability would undermine the organization. In our view, what is best

for OPEC’s long reserve life producers is high price volatility. This is the only way

to obtain high revenues and maintain market share over the countries’ reserve lives.

In order to maintain a balance between these opposing objectives, we believe OPEC

deliberately causes price volatility that allows the pendulum to swing from satisfying

one objective to the other. High prices bring high revenues; however, they also work

to reduce market share. On the other hand, OPEC has been seen raising productionin a low-price environment, discouraging new investment by non-OPEC producers,

thereby increasing market share.

Market share is critical to OPEC, given the countries’ dependency on this one

commodity for revenue and the producers’ long oil reserve lives. If market share is

pegged, oil prices will fluctuate more. Increased oil price volatility creates

uncertainty for planners and works to slow drilling activity. Just as importantly, high

price volatility will slow development of alternative and nonconventional energy

such as gas-to-liquids conversion (GTL), oil sands, and oil shale. Over the next 30

years, GTL has the potential to displace a large portion of oil’s share of the world’s

energy market. Furthermore, there are more reserves of tar sands and oil shale inCanada and the U.S. than there is conventional oil in Saudi Arabia. This is

threatening to large oil exporters like Saudi Arabia, given its 100-plus years of oil

reserves. In addition to slowing energy development, high price volatility can result

in an average oil price that allows Saudi Arabia to realize revenues above those

necessary to balance the country’s budget.

In the recent past, OPEC has viewed itself as the swing producer, with a self-

appointed task of altering production to balance world oil supply and demand. For

instance, in 2000, the organization set a “price band” to monitor and respond to

changes in world prices. The price band was based on a basket of seven crudes.

According to the price band mechanism, production adjustments would result if OPEC basket prices rose above $28/bbl for 20 consecutive trading days, or below

$22/bbl for ten consecutive trading days. The price band proved to be more symbolic

than real, since member countries often cheated on quotas and prices frequently

moved below and above the band, accompanied by lip service, but little action. The

OPEC basket price has traded above $28/bbl since December 2003 without triggering

the price band mechanism. At its January 2005 meeting, OPEC temporarily

suspended the price band mechanism, deeming it unrealistic given volatility in the

market. Since then, OPEC actions appear to support a price that is well above the

historical band.

While OPEC appears diligent about setting production quotas in response to marketconditions, members consistently produce more than their allocation (see Exhibit 12).

For this reason, in terms of influencing oil prices, OPEC’s production policy has been

somewhat secondary to its actual production. Members cheat on production quotas,

particularly when prices are falling, as lower production means lower revenue for the

country. For instance, in January 2001, oil prices fell from $36/bbl to $28/bbl in a

six-week period, a signal that the markets were oversupplied. The OPEC-10 (OPEC-

10 production excludes Iraq, to which recent quotas do not apply) cut its production



quota by 1.5 million barrels per day (b/d) in February 2001, and by another million

b/d in April 2001. While production was cut by 1.3 million b/d in February, through

August 2001, it had reduced production by only 430,000 b/d more. As one might

imagine, OPEC members tend to be more responsive to increases in production

quotas than they are to decreases.

Exhibit 12. OPEC-10 Production vs. Quotas

2000021000

22000

23000

24000

25000

26000

27000

28000

29000

M a y - 9

8

N o v - 9

8

M a y - 9

9

N o v - 9

9

M a y - 0

0

N o v - 0

0

M a y - 0

1

N o v - 0

1

M a y - 0

2

N o v - 0

2

M a y - 0

3

N o v - 0

3

M a y - 0

4

N o v - 0

4

M a y - 0 5

N o v - 0 5

M a y - 0

6

N o v - 0

6

T h o u s a n d s b / d

Quotas Production

Average production above quota: 824,000 b/d

Source: Platts.

Until recently, capacity utilization was not a factor that influenced oil prices, as

supplies were more than ample to meet worldwide demand with an adequate cushion

for further demand growth. Remember, in the past, OPEC has had to withhold

substantial volumes of oil from the market to keep oil prices above high teens/low$20s per barrel. It seems that times have changed. Demand growth in 2004 was

extraordinary, estimated at 4.0%, fueled by economic expansion in China, India, and

the United States. In addition, post-9/11 terrorism, the increased possibility of a

supply disruption, and unstable civil and political situations in some producing areas

have raised concerns about another oil shock.

Capacity utilization is difficult to measure. This is part and parcel of the “bad” data

problem that was discussed earlier. By definition, non-OPEC producers have no

spare capacity, since OPEC is the swing producer. OPEC has spare capacity, but it is

impossible to know what a country can produce. There is no official documentation,

and oil ministers seem to give inconsistent estimates of capacity. Reserves in nationssuch as Saudi Arabia are plentiful and inexpensive to develop ($2/bbl-$5/bbl), but

even the Saudis have given different reports of production capacity in their own

country. We have raised our estimates of OPEC capacity several times in the past

two years as member nations’ production climbed above our capacity estimates (see

Exhibit 13).

CAPACITY

UTILIZATION




While it is generally agreed that worldwide oil production capacity needs to increase,

from precisely what level is a little vague. Spare capacity is determined in part by

how much OPEC is currently producing. In 2004, OPEC began to raise production,

causing concerns about shrinking spare capacity at a time when it was feared that

terrorist activity could disrupt significant amounts of supply anywhere in the world.

OPEC’s rising production, in this respect, had a bullish effect on prices. As of

December 2006, we estimate OPEC’s spare capacity in excess of three million b/d,

higher than 2004 and 2005, when spare capacity shrunk to below two million b/d, butstill below the estimated 2002 level of approximately five million b/d. However,

OPEC nations have boosted development activity, and spare capacity appears to be

on the rise once again.

Exhibit 13. Estimated OPEC Spare Production Capacity(b/d in thousands)

Dec-06 Capacity Dec-06 Production Algeria 1,400 1350Indonesia 1,150 860Iran 3,900 3850Iraq 3,000 1900

Kuwait 2,400 2460Libya 1,700 1700Nigeria 2,500 2230Qatar 800 800

Saudi Arabia 11,000 8790United Arab Emirates 2,600 2500Venezuela 2,800 2460Total OPEC 33,250 28,900

Estimated spare capacity 4,350 Less: shut in capacity in Iraq, Venezuela, Nigeria (1,250)

Spare Capacity 3,100

Source: Platts; Bear, Stearns & Co. Inc. estimates.

Strategic reserves are nations’ emergency oil stockpiles. Many countries have talked

about building strategic reserves in the past three to four years, spurred on by fears of

supply shortages owing to terrorist activity or political turmoil in producing

countries.

In the U.S., after the September 11, 2001, terrorist attacks, President George W. Bush

pledged to fill the Strategic Petroleum Reserve (SPR) to its maximum of 700 million

barrels as an insurance policy in the event of another oil shock. Germany, Japan,

South Korea, and Taiwan also have strategic reserves. China and India, two of the

fastest-growing nations in terms of oil demand, have also taken steps to establish areserve.

The SPR in the U.S. was created in the aftermath of the oil embargo of 1973-74. On

September 11, 2001, the reserve contained approximately 544 million barrels of oil.

Since then, the U.S. government has filled the SPR at an average 850,000 barrels of

oil per week, or approximately 121,400 b/d.

STRATEGIC R ESERVES



Oil for the U.S. SPR is stored at four sites, in salt caverns on the coast of Louisiana

and Texas. The government takes the oil in place of royalty payments oil companies

would otherwise make to produce on federal land. However, imported crude is also

purchased, so that the reserve comprises a variety of crude blends. In the past, the

DOE has released small amounts of oil from the reserve in response to temporary

supply disruptions, as it did after Hurricanes Ivan, Katrina, and Rita knocked out

production at some oil production platforms in the Gulf of Mexico. The U.S. imports

approximately ten million barrels of oil per day, so at capacity of 700 million barrels,the reserve would provide 70 days, or less than two-and-a-half months, of crude

imports. However, in all likelihood, even under extreme circumstances, it would be

unlikely that all of the imported supply to the U.S. would be disrupted. A significant

disruption of two million b/d of production at a facility outside the U.S. would likely

reduce availability of oil imports to the U.S. by 500,000 b/d (the U.S. consumes

approximately one-fourth of global oil production). In such a case, the SPR would

cover the shortfall for more than three-and-a-half years.

The program was criticized, in part due to the cost, as prices rose to the high-$50s/bbl

in 2005 from the $22/bbl-$23/bbl range in September 2001. Building the SPR was

viewed as bullish for oil prices. A recent proposal by the Bush Administration todouble the capacity of the U.S. reserve by 2027 is controversial. Although the oil

being added to the reserve is not consumed, it does take oil off the market that would

otherwise be consumed, causing supplies of oil for consumption to tighten, and

apparent demand to appear artificially high.

Exhibit 14. U.S. Strategic Petroleum Reserve Inventory

500,000

550,000

600,000

650,000

700,000

1 2 / 2 9 / 1 9 9 5

1 2 / 2 9 / 1 9 9 6

1 2 / 2 9 / 1 9 9 7

1 2 / 2 9 / 1 9 9 8

1 2 / 2 9 / 1 9 9 9

1 2 / 2 9 / 2 0 0 0

1 2 / 2 9 / 2 0 0 1

1 2 / 2 9 / 2 0 0 2

1 2 / 2 9 / 2 0 0 3

1 2 / 2 9 / 2 0 0 4

1 2 / 2 9 / 2 0 0 5

1 2 / 2 9 / 2 0 0 6

0 0 0 ' s B a r r e l s

U.S. SPR Stocks

Authorized capacity

Source: Energy Information Administration.

We believe the current perception of tight world supply/demand balance has been

exacerbated by the building of reserves around the world.




In industrialized nations, demand growth has been closely correlated with GDP

growth. Oil demand in OECD countries accounts for approximately 60% of

worldwide demand, but recently, non-OECD GDP growth has been the principal

driver of global oil demand growth. In the past 16 years, world oil demand has risen

at an average annual rate of 2.4%. Annual growth has averaged 1.2% and 2.1% in

OECD and non-OECD countries, respectively. In the past five years ending 2006,

non-OECD oil demand growth has accelerated to an average of 3.3%, while OECD

growth has slowed to 0.7%.

WORLDWIDE OIL

DEMAND



Exhibit 15. Year-over-Year GDP Growth vs. Oil Demand Growth

OECD Non-OECD

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

P

e

r c

e

n

t

OECD Real GDP OECD Oil Demand Growth

-2.0

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

P

e

r c

e

n

t

Estimated Non-OECD GDP Growth Non-OECD Oil Demand Growth

Source: Energy Information Administration; International Energy Agency; Bear, Stearns & Co. Inc. estimates.

Future global oil demand growth forecasts are mostly determined by regional

macroeconomic trends. It is easier to think of regional oil demand in terms of

demand for refined products, the end-use for crude oil. For instance, a healthy

economy in an industrialized nation may lead to robust manufacturing activity. This

typically stimulates demand for on-road diesel fuel (used by the trucking industry), or other transportation fuels used for shipping products. In addition, a healthy economy

usually stimulates leisure and business travel, supporting demand for gasoline and jet

fuel. Economic growth in many less-mature nations is, in many cases, supported by

economic health in industrialized nations, although GDP growth in these regions can

be volatile.

In mature economies, such as in the U.S., oil demand may also be influenced by

absolute levels of oil prices, as high oil prices are typically passed on to consumers

through higher prices for gasoline, petrochemicals used in manufacturing, distillates

used to heat homes and in industrial applications, and air travel, among other things.

Therefore, demand may be curtailed as consumers and businesses feel the pinch of high transportation and materials costs.

An additional factor influencing demand is a country’s taxation. In most countries,

consumption of gasoline and diesel fuel is highly taxed. In Europe, where

transportation fuels are heavily taxed, demand is less sensitive to changes in product

prices than in countries where there is a smaller tax component in the price, such as

the United States.

Currency fluctuations can also affect demand for crude oil, although it is difficult to

quantify the impact. Economists have differing views on the topic, in part because

swings in currency valuations are commonly accompanied by a variety of other macroeconomic conditions. In general, we believe the impact of currency

fluctuations on worldwide demand to be insignificant relative to the impact of a

change in the absolute price of crude oil. For example, the dollar’s weakness is often

cited as one of the reasons why oil prices strengthened in 2004. There are two

aspects for oil that stem from currency movements, given that oil is priced in dollars:

1) the impact on demand for petroleum products outside the U.S., and 2) the

influence on OPEC supply policy.




A weak dollar can lead to relatively lower petroleum prices outside the U.S., and,

therefore, stimulate higher demand. But this did not happen in 2004. Prices in

Europe in local currency did not increase as much as they did in the U.S. during the

past year, but they did rise, owing to the sharp increase in dollar-denominated oil

prices, higher excise taxes, and higher refining margins. According to the IEA, from

February 2004 through January 2005, end-user gasoline and diesel prices rose an

average of 3.1% and 4.6%, respectively, in France, Germany, Italy, Spain, and the

United Kingdom. In comparison, gasoline and diesel prices in the U.S. increased10.1% and 23%, respectively. End-user prices rose more in Japan, up 17.1% for

gasoline and up 14.8% for diesel. We believe dollar weakness may have resulted in a

less depressive effect on petroleum demand in Europe, but it does not appear to have

bolstered demand.

The second aspect of a weak dollar is that in order to preserve its purchasing power

as the dollar falls, OPEC needs to raise oil prices. This can be accomplished by

cutting oil production. Yet, instead, throughout 2004, OPEC did the exact opposite.

It increased oil production. However, OPEC cited the weak dollar as a reason to

support higher oil prices above the band of $22/bbl-$28/bbl that it had previously

advocated.

In the end, in 2004 and 2005, the effect on supply and demand for oil from dollar

weakness was not apparent, other than it contributed to the bullish psychology in the

oil markets.

Over time, we believe sustained periods of high or low prices will affect demand in

any region. In mature economies such as the U.S. and Europe, sustained high prices

often lead to conservation measures, including shifts by consumers in the type of

vehicle that they buy. We believe a structural shift in auto purchases is occurring in

the U.S., with consumers moving away from gas-guzzling sports utility vehicles

(SUVs) toward more fuel-efficient cars and hybrids. History suggests that once theshift gets under way, it takes time to reverse, even if gasoline prices fall. In emerging

economies, high energy prices strain fragile fiscal regimes and discourage new

investment.

Non-OECD countries’ oil demand growth patterns are difficult to predict.

Historically, swings in demand have less impact on global demand due to the smaller

scale. But, looking forward, growth in demand in Asia/Pacific regions will play a

larger role in the future in the worldwide supply/demand balance. China’s oil

demand demonstrates unpredictability, and the rising influence of non-OECD

growth. Average demand in China for the past five years ending in 2006 has been

approximately 6.1 million b/d, about one-third of U.S. demand of 20.8 million b/d,and about 7% of worldwide demand. Five years ago, the rolling five-year average

demand in China was just 4.3 million b/d, or less than one-quarter of U.S. demand,

and 5% of worldwide demand. Today, a 10% increase in Chinese demand would

boost worldwide demand by approximately three-quarters of a percentage point.

Historically, oil demand growth in China, estimated at approximately 6%-7%, has

been about three times the worldwide average. The pace has accelerated recently,

but, as seen in Exhibit 16, demand growth in China is erratic. Aberrations in



reporting often lead to indications of very strong demand, followed by a collapse in

demand. Some would argue that extraordinary growth in emerging economies such

as China is not sustainable year after year, as rapid industrial growth usually bumps

up against existing infrastructure. However, recent growth trends have raised

concerns about the market’s ability to serve the increasing needs of non-OECD

nations.

Exhibit 16. China Oil Demand Growth

0

4

19.2

0

6.45

9.098.33

5.13

6.98

2.17

5.74

11.07

15.3

4.89

1.5

6.17.52

5

8.69

4.544.76

0

5

10

15

20

25

1 9 8 6

1 9 8 7

1 9 8 8

1 9 8 9

1 9 9 0

1 9 9 1

1 9 9 2

1 9 9 3

1 9 9 4

1 9 9 5

1 9 9 6

1 9 9 7

1 9 9 8

1 9 9 9

2 0 0 0

2 0 0 1

2 0 0 2

2 0 0 3

2 0 0 4

2 0 0 5

2 0 0 6

P e r c e n t

yoy growth

Average = 6.5%

Source: International Energy Agency; Bear, Stearns & Co. Inc. estimates.

Directional trends in oil prices usually boil down to the supply/demand balance.

Oversupplied markets tend to increase inventories and pressure prices, and vice

versa. Earlier, we discussed the market players on the supply front, and we explained

how and why OPEC is the swing producer. When we put our assumptions for supplyagainst our demand outlook, as shown in our supply/demand model below, we start

to get a picture of how of the balance might look in the near future.

Most oil analysts’ supply/demand models attempt to determine what OPEC should

produce. We forecast world oil demand, non-OPEC supply, and then adjust

inventories upward or downward to a normal level. The volume that remains is

referred to as the “call” on OPEC — i.e., the amount that the swing producer should

produce to balance supply, demand, and inventories.

We begin with demand assumptions, using Bear Stearns’ regional GDP forecasts, and

examining macro indicators that may affect demand, as well as the region’s history of oil consumption to GDP. From this, we formulate projections of future demand

growth. Next, we forecast non-OPEC supply, based on our research and public

information on developments around the world. The difference between our global

demand estimate and non-OPEC supply is referred to as the call on OPEC oil, or,

how much oil OPEC (the swing producer) must produce in order to balance the

market. Comparing this figure with current OPEC production, we then estimate

whether OPEC will be able to balance the market. To the extent that OPEC will or

will not be able to balance the market, inventories will rise or fall.

A WALK THROUGH

OUR WORLDWIDE OIL

SUPPLY/DEMAND

MODEL




For instance, in the example model shown in Exhibit 17, we compare the call on

OPEC oil of 27.7 million barrels in 2005 to current OPEC production of 30.0 million

b/d (as of April 2005). We note that OPEC must cut production by 2.3 million b/d in

order to balance the market. Given the magnitude of the oversupply, and OPEC’s

propensity to produce above quotas, we conclude that inventories are likely to rise,

and that oil prices will experience downward pressure. We have talked about non-

fundamental factors that have influenced oil prices. However, we believe that, over

time, prices will stabilize at levels indicated by the fundamentals.

Exhibit 17. World Oil Supply and Demand Model (b/d in millions)

2003 2006

Year 1Q 2Q 3Q 4Q Year 1Q 2Q 3Q 4Q Year Year Demand

OECDNorth America 24.6 25.0 24.9 25.2 25.5 25.2 25.2 25.2 25.5 25.8 25.4 25.7Europe 15.5 15.8 15.4 15.7 16.1 15.8 15.8 15.5 15.9 16.2 15.9 16.1Pacific 8.8 9.4 8.0 8.3 8.9 8.6 9.4 8.1 8.2 9.0 8.7 8.8

Total OECD 48.9 50.2 48.3 49.2 50.5 49.5 50.4 48.8 49.6 51.0 49.9 50.6Non-OECD 27.4 28.8 29.2 29.0 29.8 29.2 29.5 30.2 30.2 30.5 30.1 31.0

Demand Outside FSU 76.3 79.0 77.5 78.2 80.3 78.7 79.9 79.0 79.8 81.5 80.1 81.6

Supply

OECD(1)

21.6 21.8 21.5 20.7 21.1 21.3 21.4 21.4 21.3 21.5 21.4 21.6FSU Net Exports 6.7 7.3 7.4 7.7 7.6 7.5 7.7 7.9 8.2 8.3 8.0 8.4China 3.4 3.4 3.5 3.5 3.4 3.5 3.6 3.5 3.5 3.5 3.5 3.5Other Non-OECD 11.9 12.1 12.2 12.4 12.6 12.3 12.6 12.8 12.9 13.0 12.8 13.5Processing Gains 1.8 1.9 1.8 1.8 1.9 1.9 1.9 1.9 1.9 1.9 1.9 2.0

Total Non-OPEC 45.5 46.5 46.4 46.1 46.6 46.4 47.2 47.5 47.8 48.2 47.7 49.1

Call on OPEC Oil (2) 26.8 27.9 28.1 29.2 29.6 28.7 27.8 27.0 27.7 28.2 27.7 27.7

OPEC NGL 3.9 4.3 4.3 4.3 4.4 4.3 4.7 4.7 4.7 4.7 4.7 4.8

Total OPEC 30.7 32.2 32.4 33.5 34.0 33.0 32.5 31.7 32.4 32.9 32.4 32.5

Total Production 76.1 78.7 78.8 79.6 80.6 79.4 79.7 79.2 80.2 81.1 80.1 81.6

Inventory Build (Draw) (0.2) (0.3) 1.3 1.4 0.3 0.7 (0.2) 0.2 0.4 (0.4) 0.0 0.0

——————— 2004 ——————— ——————— 2005 ———————

(1) OECD production includes NGLs and nonconventional. (2) Includes condensates.

Notes: Historical OPEC production is actual. Projected OPEC production is derived from our estimates of demand andnon-OPEC production. Projected OPEC production is the same as the projected call on OPEC. Numbers maynot add due to rounding.

Source: International Energy Agency; Bear, Stearns & Co. Inc. estimates.

It is important to note that disruptions in oil supply are routine. Each year, the

industry experiences labor strikes, mechanical problems, foul weather, civil unrest,

war, and government policy shifts. Recently, outages in the normal course of

business have drawn increased attention from traders, given terrorist fears and

perceived tightness in the supply and demand balance.

As discussed earlier, terrorist fears played a role in the market’s view on supply,

which helped drive an unusually rapid increase in oil prices in 2004. Likewise, civilunrest in oil-producing countries such as Nigeria and Venezuela disrupted supply

through periodic labor strikes in 2004 and 2005. Production in Iraq has yet to

recover from insurgent attacks following the allied invasion in March 2003. Russia

could potentially be the largest exporter of oil in the world, as the government works

to ramp up its oil exporting business. However, recently, the Russian government

has reversed some earlier actions that were aimed at stimulating drilling and foreign

investment. Limitations on foreign investment have been proposed, and contracts

have been abrogated. In addition, export taxes have been increased significantly.

These actions could slow down the rate of supply expansion.

GEOPOLITICAL

DEVELOPMENTS



For the intermediate term, we believe geopolitical factors will continue to play a role

in the influencing oil prices. When oil prices are high, governments and civil groups

have a keener interest in domestic oil production activities, and social issues such as

wealth distribution. This perpetuates a hot geopolitical climate, and helps to support

the premium that has been built into oil prices to reflect the uncertainty of reliable

and consistent supply.




Investing in the Integrated Oils

Important points for investors in integrated oils:

Integrated oils’ earnings are sensitive to changes in oil and gas prices. Hedging

activity may alter a company’s earnings near term.

Oil is a commodity, with prices historically averaging $20/bbl-$25/bbl. Oil

prices have moved above and below this range, but $20/bbl-$25/bbl had been the

conventional thinking for mid-cycle prices. Given the surge in prices in 2004, to

well above these levels, and the factors behind that surge, a new view of a mid-

cycle price is evolving. We believe there is intermediate-term support for oil

prices in an average range of $45/bbl-$55/bbl.

Two key operating measures help to gauge the health of the upstream business:

reserve replacement ratio and finding and development costs.

Growth strategy: Is the company an acquirer or an explorer?

Historical mid-cycle valuation for the integrated oils:

EV/EBITDA P/E P/CF

International Oils: 5.5x-7.5x 14.9x-20.9x 8.2x-11.4x

Domestics Oils: 4.5x-6.5x 13.3x-19.7x 4.2x-6.3x

International oils include large-cap multinationals such as BP, Chevron, Eni,

Exxon Mobil, Repsol, Royal Dutch Shell, and TOTAL. Domestic oils include

Hess, ConocoPhillips, Marathon Oil, Murphy Oil, and Occidental Petroleum.

Company valuation analysis can be found in the third section of this report.

At the end of this section, under the headline, “Pointers and Rules of Thumb,” we

have provided tips on calculating what oil price is reflected in the stocks, and

other helpful exercises.

All oil companies’ earnings have a measurable sensitivity to changes in oil and gas

prices. Typically, we measure changes in oil prices using WTI, and in the Natural

Gas Week composite spot wellhead prices for gas. Oil companies’ actual oil and gas

price realizations will vary from these proxies, depending on production profiles and

quality of the crude production slate.

We measure oil companies’ operating leverage in terms of earnings per share. Wecalculate a company’s operating leverage to a $1.00/bbl change in oil prices by

multiplying the total number of barrels of oil produced in a year by one minus the tax

rate, and dividing the product result by the number of shares outstanding. Likewise,

sensitivity to a $0.10/mcf change in gas prices is the amount of gas produced in the

U.S. per year, multiplied by 0.10, times one minus the tax rate, divided by the shares

outstanding. We find it best to look at operating leverage as a percentage of

projected earnings when ranking companies’ price sensitivity.

SENSITIVITY TO

CHANGES IN OIL AND

GAS PRICES



Leverage to oil/gas prices in EPS:

To a $1.00/bbl change in oil price = (daily oil production x 365 x $1) x (1 - tax rate)

Shares outstanding

To a $0.10/mcf change in gas price = (daily U.S. gas production x 365 x $0.10) x (1 - tax rate)

Shares outstanding

We use U.S. gas production to calculate sensitivity to natural gas prices given thehigh volumetric concentration in the U.S. for several of the companies that we cover.

Although U.S. gas prices are influenced by oil prices, the market is somewhat

contained given transportation limitations (this is slowly changing with the growth of

liquid natural gas [LNG] supplies). International gas production is sold

predominantly into local markets, where market prices usually are tied to oil prices

with a time lag.

Exhibit 18 below shows the impact on EPS of a $1.00/bbl change in oil prices for the

major oils.

Exhibit 18. Oil Company Earnings Leverage to Changes in Oil Prices(1)

2007EOperating

EPS

2007E Net

Crude OilProduction

(mm bbls)

$ Change in2007E EPS

from $1/BblChange in Oil

Price

% Change in2007E EPS

from $1/BblChange in Oil

Price

Murphy Oil $3.80 39 $0.12 3.3%Occidental Petroleum 3.80 175 0.12 3.3%Hess Corp. 5.75 97 0.18 3.2%BP 6.60 972 0.18 2.7%Chevron 7.35 696 0.18 2.5%TOTAL S.A. 7.05 609 0.15 2.1%

Royal Dutch Shell 6.85 787 0.13 1.9%Exxon Mobil 6.05 1025 0.11 1.9%Marathon Oil 10.00 89 0.15 1.5%ConocoPhillips 8.45 356 0.11 1.3%

Weighted Average 2.1%

(1) Does not account for potential impact on refining, marketing, and chemical earnings.

Source: Company reports; Bear, Stearns & Co. Inc. estimates.

Exhibit 19 shows the impact on earnings per share of a $0.10/mcf change in U.S.

natural gas prices for the major oils.




Exhibit 19. Oil Company Earnings Leverage to Changes in Gas Prices

$ Change in % Change in

2007E 2007E Net U.S. 2007E EPS from 2007E EPS from

Operating Natural Gas $0.10/mcf Change $0.10/mcf Change

EPS Production (bcf) in Gas Price in Gas Price

Marathon Oil 10.00 331 0.06 0.6%ConocoPhillips 8.45 906 0.04 0.4%

Occidental 3.80 217 0.02 0.4%BP 6.60 881 0.02 0.3%Murphy Oil 3.80 23 0.01 0.2%Chevron 7.35 675 0.01 0.2%Hess Corp. 5.75 42 0.01 0.1%Royal Dutch Shell 6.85 456 0.01 0.1%Exxon Mobil 6.05 602 0.01 0.1%TOTAL S.A. 7.05 237 0.01 0.1%

Weighted Average 0.2% Source: Company reports; Bear, Stearns & Co. Inc. estimates.

Historically, oil prices have experienced cyclicality in response to oversupply or

undersupply, and to changes in demand. These cycles may last for two or so years,

but in the past, prices have gravitated back to the mean level — around $23/bbl —

after periods of volatility, as the supply and demand adjusts and responds to market

conditions. We believe the cyclicality in oil price movements will persist, though we

believe the mid-cycle level is above the historical average in the intermediate term,

and a mid-cycle price has yet to be determined. A higher mid-cycle price is

supported by higher costs for the marginal barrel, OPEC action to support higher

prices, proportionally stronger demand out of non-OECD nations, and a more active

geopolitical climate.

Exhibit 20. WTI Spot 36-Month Moving Average Oil Prices 1983-2004

0

10

20

30

40

50

60

70

80

90

F r e q u e n c y

<16 16-18 18-20 20-22 22-24 24-26 26-28 28-30 >30 Source: BP; Platts.

OIL

IS A

COMMODITY



Prior to 2004, periods when oil prices rise above $30/bbl (in nominal terms) had been

highly unusual. As Exhibit 20 shows, oil prices have spent little time above $30/bbl

(using a three-year moving average) during the past 20 years.

Oil exploration, development, and production is a long-term undertaking. Oil

companies must make some long-term pricing assumptions to determine the

economic feasibility of development projects. Most have used a planning price of

$20/bbl-$25/bbl for WTI in the past, but those assumptions have been raised in lightof recent development in the oil market. New assumptions range from $35/bbl to

$50/bbl.

Two widely followed operating performance measures in the industry are reserve

replacement and finding and development costs. Reserve replacement is an annual

measure, expressed as a ratio of how much of the oil and gas that was produced by

the company was replaced with new reserves. A ratio above 100% indicates growth

in reserves. F&D costs, expressed in dollars per barrel of oil equivalent ($/boe),

measure the cost of newly booked reserves. Each spring, Bear Stearns publishes a

comprehensive report on industry trends as indicated by these metrics, and company-

by-company rankings and commentary (see our annual publication, Reserve Replacement and Finding Costs: Trends in the Oil Industry).

A company with a well-managed upstream program is one that consistently replaces

more than 100% of its production at a reasonable cost (until recently, industry finding

and development costs, on average, have been in the $6.00/bbl-$7.00/bbl range).

Poor reserve replacement, or high F&D costs, may be a sign of a weak exploration

program that will hurt the company competitively through low or no production

growth, and/or substandard returns.

Timing issues can lead to erratic annual performance. For this reason, it is important

to look at a company’s reserve replacement and F&D costs over a multiyear period.We believe a five-year time frame or longer is appropriate.

How a company books its reserves warrants some discussion, given the attention

drawn to the topic following a disclosure by Royal Dutch Shell in 2004 that it

removed more than 20% of its reserves from its books due to overaggressive

bookings in the past seven years. There are three categories of reserves: proved,

probable, and possible. The distinction of reserve categories is important in oil and

gas accounting. Only proved reserves are reflected on oil companies’ balance sheets.

Proved reserves, which we discuss below, are those believed, with “reasonable

certainty,” to be recoverable in the future. Probable and possible reserves, or,

broadly speaking, “unproved” reserves, are less certain than proved reserves.

A high percentage of probable reserves are usually ultimately booked as proved.

Oftentimes, development plans for the probable reserves have not reached a level of

maturity that would allow a company to call them proved. Most companies do not

provide estimates of probable reserves (some Canadian companies do). This is

unfortunate, as these assets clearly have value that is unrecognized in the companies’

financial statements. In our valuation work, we attempt to estimate probable reserves

based on our research work and company publications. Possible reserves are less

certain than probable reserves, and may require different economic conditions in

order to be categorized as proved.

TWO K EY OPERATING

MEASURES: R ESERVE

R EPLACEMENT AND

FINDING AND

DEVELOPMENT COSTS




Proved reserves are usually just a small part of a company’s true assets. For instance,

Exxon Mobil, which had approximately 21.6 billion boe of proved reserves as of

year-end 2005, says that its proved reserves represent just one-quarter of its total

resource base.

In the U.S., the Securities and Exchange Commission (SEC) is the regulatory agency

that issues guidance on when reserves may be booked. Reserves are reported

annually in the company’s 10-K. Booked reserves refer to proved reserves, or reserves that, per guidance from the SEC, the company has discovered and is

“reasonably certain” will be developed and produced. The phrase, “reasonably

certain” is somewhat ambiguous, and opens the process to subjectivity. The SEC’s

guidelines to determine reasonable certainty include production and well test data,

core analysis, and well log data, but often test results are subject to interpretation by

geologists and engineers, which is sometimes correct, and sometimes not. Generally,

our observation has been that an oil company will book oil and gas reserves at

approximately the time that funding for the development has been approved by the

board of directors, although, technically, this is not a required criteria. A

conservative company will typically not book the entire resource estimate initially,

but only the portion that it knows it can produce. As additional data on the field arelearned, the company will revise its estimates upward. For natural gas reserves

outside of North America, reserves may only be booked after a sales contract for the

produced gas has been signed.

The SEC requires companies to classify proved reserves into two subcategories:

“proved developed reserves” (PDs) and “proved undeveloped reserves” (PUDs).

When a company makes a discovery that it is reasonably certain that it will develop,

the reserves will be booked initially as PUDs. As the field is developed, the reserves

are moved to the PD category. The SEC requires companies to disclose both

categories of reserves. A large proportion of PUDs to total reserves could be an

indication that the company books reserves aggressively. We also view a history of negative revisions as a red flag. A low ratio could be an indication of a weak

exploration program. A small development portfolio bodes poorly for future

production growth, unless the company makes an acquisition. Most large integrated

oil companies have a reputation for conservative booking practices. In 2005, the

integrated oils’ ratio of PUDs to total reserves was 39%.



Exhibit 21. 2005 Proved Undeveloped Reserves as a Percentage of Total

0%

10%

20%

30%

40%

50%

60%

O X Y

C V X

C O P

X O M

M R O

M U R

H E S

R D S A

B P

T O T

P e r c e n t

PUD Reserves/Total Reserves Source: Company reports.

Calculating Reserve Replacement

Oil companies often announce reserve replacement performance for the prior year in

a press release. This “headline” number may differ from the number that we will

derive below, because companies include new reserves from all sources, including

acquisitions. In our calculation, we exclude the impact of purchases and sales, to

focus solely on the company’s operational performance.

Most often, the reserves table is found near the end of the 10-K, in a section providing supplementary data on operations. There are two reserve tables, one for oil

and one for gas. The tables usually contain seven lines for each year as follows:

Beginning Reserve Balance. The top line shows the reserve level at the end of

the prior year. This includes both proved developed and proved undeveloped

reserves.

The four lines that follow show reserve additions for the year by category:

1. Revisions. From time to time, reserves at a field have already been booked,

but new data have caused the company to revise its view on how much oil or

gas can be produced from the field. These revisions can be upward or

downward. Given the integrated oils’ conservative booking practices, we

usually see a positive revision. At most companies, internal and external

auditors review reserves at regular intervals to determine whether a revision

is appropriate.

2. Improved Recovery. Reserves booked in this category are at a producing

field, and, through application of technology or an enhanced recovery

technique, more reserves are deemed recoverable.




3. Purchases/Sales. These are the changes in reserves levels attributable to

purchases and sales of assets during the year (sometimes purchases and sales

are stated on separate lines). We do not consider these reserves as part of the

organic progress of the company, and therefore we exclude them from our

calculation of reserve replacement.

4. Extensions and Discoveries. These are reserves that are booked from a new

discovery, satellite well, or from a well drilled on the boundary of a field thatextends the perimeter of the field.

Production. This is the total amount of oil or gas produced by the company

during the year.

Ending Reserve Balance. The company’s reserves at the end of the year, equal

to the sum of the six lines above it.

Reserve replacement calculation:

To calculate oil and natural gas reserve replacement for the company, add the linesfrom each of the two tables. To convert gas, which is usually stated in billions of

cubic feet, to barrels of oil equivalent, we divide by six.

Reserve Replacement = Revisions + Improved Recovery + Extensions and Discoveries

Production

Calculating Finding and Development Costs

Finding and development costs measure the unit cost of newly added reserves. As

with reserve replacement, we exclude the cost of acquisitions (proved property

acquisitions, described below), so as to ascertain the pure operating performance.

Costs are disclosed in a table in the 10-K entitled, “Costs Incurred,” or “Costs

Incurred for Property Acquisition, Exploration, and Development,” usually located

near the reserves tables.

The table contains four lines for each year: unproved property acquisitions, proved

property acquisitions, exploration, and development. Proved property acquisitions

are purchases of producing properties, which we do not include in our analysis.

However, acquisition of unproved properties is included in our cost analysis. These

are costs associated with acquisition of mineral rights, lease bonuses, real estate

broker fees, etc., on properties for future exploration. The costs are capitalized asincurred, and for a company using successful efforts accounting, the company may

take an impairment allowance if no oil or gas is found on the property. Exploration

costs include those costs that were incurred on exploration, including G&G costs,

whether they were expensed (for a company using successful efforts accounting) or

capitalized. Development costs, which are capitalized, include all costs associated

with development drilling, or building and installing production, gathering, or storage

facilities associated with future production.



Finding and development cost calculation:

F&D costs = Cost of : Purchase of unproved properties + Exploration costs + Development costs

Reserves from: Revisions + Improved Recovery + Extensions and Discoveries

The Value-Added Ratio

The value-added ratio (VAR) is a measure of the value creation of a company’sexploration and development program. Over time, it can be used as a proxy for

return on investment. Reserve replacement figures measure the growth or depletion

of a company’s reserve base, but they do not recognize the economic value of the

reserves added. The VAR measures the effectiveness of a company’s capital

spending by distinguishing between reserves of greater and lesser value. The ratio,

therefore, can be used to identify companies that discover and develop more

profitable oil and natural gas reserves.

We calculate VAR by dividing the discounted present value created in a year (before

acquisitions) by the investment made to generate that value. The present value data

are compiled from the “Statement of Changes in Standard Measure of Discounted

Future Net Cash Flows” provided in each company’s 10-K. This statement is based

on a year-end oil price, and applies a discount rate of 10%. Therefore, a VAR of 1.0,

would indicate that expenditures in the given year achieved an overall rate of return

of 10%.

Value-added ratio calculation:

Value-added ratio = Change in Standardized Measure of DiscountedFuture Net Cash Flows from Proved Reserves (Excluding Acquisitions)

Cost of Purchase of Unproved Property+ Exploration Costs+ Development Costs

For example, in the last ten years, we estimate Murphy Oil’s value-added ratio at1.53. This implies a 15.3% return on investment, based on an average oil price of

$25.60/bbl for WTI (the average year-end price over the last ten years). Murphy’s

VAR is consistent with the industry average. BP, Chevron, and Exxon Mobil have

the highest VAR ratios, at an average of 1.8-2.0 over the last ten years.

Most oil companies maintain asset management programs, whereby maturing fields

are sold off, providing capital for reinvestment in the business. Many will also

acquire producing properties, usually in areas where the company has existing

operations — a core area that would provide synergistic benefits. Often, companies

engage in asset swaps as part of their portfolio management program. This, for most

of the large integrated oils, is in addition to the exploration program, which is

designed to add new reserves through the drill bit.

By our observation, a company will look to acquire producing assets under three

circumstances: 1) the company has a hole in its development pipeline (often because

it has not discovered enough oil or gas) that it needs to fill with an acquisition to

maintain production growth; 2) the company does not have an exploration focus, but

has instead elected to grow through acquisition; or 3) an opportunity presents itself,

perhaps in a core or desirable area, which would enhance the company’s existing

portfolio.

COMPANY STRATEGY:

ACQUIRER OR

EXPLORER ?




We touched on the first reason why companies might be seeking an acquisition in our

discussion of reserve replacement. A company whose reserves have been depleted

by production (reserve replacement less than 100%) over a multiyear period may

look to make an acquisition to replace those reserves, in order to maintain or grow

production. The second reason is more characteristic of a smaller independent E&P

company than of a large integrated oil company. Exploration is capital-intensive and

risky, so some companies elect to emphasize acquisition of reserves rather than drill.

Most integrated oils have large exploration programs, with the scope, financial depth,and expertise to explore for oil and gas. A company that is dependent upon

acquisitions for future growth may be disadvantaged when oil and gas prices are

high, as acquisition costs would likely be higher than industry F&D costs. An

acquirer must be disciplined in order to achieve the same returns as an efficient

explorer.

We are often asked what oil price is implied in an oil stock’s current price. There are

two ways of answering this question. The first would be to determine the near-term

oil price reflected in stock prices by looking at what oil price is reflected in consensus

estimates. The second answer is what is the implied long-term oil price reflected in a

stock’s current price. Arriving at this answer is beyond the scope of this introductory primer — it requires some discounted cash flow (DCF) analysis, and making some

assumptions on an oil company’s long-term cash flow sensitivity to changes in oil

prices. However, we bring it up because we believe that it is applicable when oil

prices are well above or below mid-cycle for valuation purposes, to identify

acquisition candidates, or for evaluating a merger or acquisition.

What Oil Price Is Reflected in an Individual Company’s ConsensusEarnings Estimate?

We can approximate the oil price reflected in consensus earnings estimates using the

company’s sensitivity to a $1.00/bbl change in the price of oil, and our earnings

estimate based on an oil price assumption of $50/bbl.

For example, what oil price is reflected in Exxon Mobil’s stock price? We estimate

that every $1.00/bbl change in the price of oil changes Exxon Mobil’s earnings by

$0.11 per share (see the methodology for this calculation on page 37). Our earnings

estimate for Exxon Mobil in 2008, based on a $50/bbl oil price assumption, is $4.90

per share. Consensus is $6.00 per share. The difference is $1.10 per share, implying

a difference of $10.00/bbl in the oil price assumption from our estimate based on

$50/bbl. Therefore, consensus estimates reflect an oil price of approximately

$60.00/bbl in 2008 (this exercise does not take into account differences in other

assumptions, such as natural gas prices and refining and chemical margins).

Exxon Mobil’s sensitivity to a $1.00/bbl change in oil price = $0.11 per share

Our earnings estimate: $4.90 per share; our oil price assumption: $50/bbl

Consensus earnings estimate: $6.00 per share

Implied oil price = (($6.00-$4.90) / 0.11) + $50/bbl = $60.00/bbl

POINTERS AND R ULES

OF THUMB



What Is a Stock’s Upside/Downside if Actual Oil Prices Differ fromConsensus?

What is Exxon Mobil’s stock price upside if oil prices average $70/bbl next year?

Following on from the previous example, the implied consensus oil price assumption

for Exxon Mobil is $60.00/bbl next year. First, we would derive an earnings estimate

based on an oil price of $70/bbl. The difference of $10.00/bbl in the oil price

assumption implies additional earnings upside of $1.10 per share. Adding this to

consensus earnings of $6.00 implies earnings of $7.10 per share. At $75, ExxonMobil currently trades at 12.5x consensus earnings (or substitute a historical average

P/E multiple, if appropriate, as P/E multiples generally do not remain constant),

which, using the same multiple on upside earnings, implies a stock price of $90.

Exxon Mobil’s sensitivity to a $1.00/bbl change in oil price = $0.11 per share

Projected change in oil price from consensus: $70.00 - $60.00 = $10.00/bbl

Estimated earnings impact of oil price change = $0.11 x 10.00 = $1.10 per share

New estimated consensus earnings estimate: $6.00 + $1.10 = $7.10 per share

Forward P/E based on old consensus = $76 / $6.00 = 12.7x

Implied upside price: 12.7 x $7.10 = $90.00 per share




Section 2




Independent Refiners

An independent refiner is engaged exclusively in refining crude oil into lighter

petroleum products such as gasoline, diesel fuel, heating oil, and jet fuel, and in the

marketing of these products. Some independent refiners operate retail outlets, which

may include a merchandising component through convenience stores. Others, known

as “pure-play” refiners, have no retail operations, selling refined products into

wholesale or bulk markets. Independents operate 39 of the 132 refineries in the U.S.,

accounting for 5.3 million b/d, or 31% of domestic refining capacity.

The publicly-traded independent refining sector has evolved only in the past 15-20

years. Prior to that, refining was predominantly part of the integrated oil companies’

operations. But refining has long been a low-margin business, and as fuel specs,

particularly in the U.S., have grown more rigid, the integrated oils have been

downsizing their refining operations in favor of the more lucrative upstream. This is

how independent refiners came to be. The group of publicly-traded independent

refiners consists of Alon USA, Delek, Frontier Oil, Holly Corporation, Giant

Industries, Sunoco Inc., Tesoro Corporation, Valero Energy Corporation, and

Western Refining. Together, they comprise 31% of U.S. refining capacity (seeExhibit 22). These companies have emerged through acquisition, IPOs of privately

owned businesses, and restructuring. Though a relatively young group of companies,

the industry has already seen consolidation. Valero, which owns 17 refineries

serving the U.S. market, operated only a single unit up until 1997. Valero acquired

fellow independent refiner, Premcor, in 2005. Tosco, once the largest U.S.

independent refiner, was purchased by Phillips Pete in 2001. Sunoco, formerly Sun

Company, was an integrated oil company up until 1988, when it spun off its E&P

business to focus on its downstream business. The integrated oil companies continue

to own the largest portion of U.S. refining capacity (approximately 47%), and

privately owned refineries make up the balance of the U.S. refining system.

Exhibit 22. Independent Refining IndustryCompany Stock Symbol Price Market Cap (in millions) No. of Refineries Refining Capacity (in b/d)

Alon Refining ALJ $26 $ 3,016 1 70,000 Delek DK 17 850 1 21,000 Frontier Oil FTO 30 3,300 2 151,000 Holly Corporation HOC 56 3,136 3 90,900

Giant Industries GI 75 1,050 3 96,200 Sunoco Inc. SUN 65 7,995 5 900,000 Valero VLO 59 35,636 17 3,300,000

Tesoro TSO 89 5,963 6 (1) 560,000

Western Refining WNR 28 1,904 1 (2) 117,000

Total: $ 62,850 39 5,306,100

Note: Stock prices are as of 2/22/07.(1) Does not include proposed acquisition of She ll’s 100,000 b/d Wilmington, California, refinery.(2) Western Refining’s proposed merger with Giant Industries is scheduled to close during the first quarter of 2007.

Source: FactSet Research Systems Inc.; U.S. Energy Information Administration.

The refinery process begins with a barrel of crude oil — the raw material input into a

refinery. With the help of heat, pressure, and chemicals, crude oil molecules are

cracked and rearranged to form lighter products — predominantly gasoline, diesel

fuel, heating oil, and jet fuel. We will discuss this process in this section. But first,

some basic U.S. refining industry facts might help.

THE “DOWNSTREAM”

INDUSTRY

THE R EFINING

PROCESS



The U.S is the largest refined product consumer in the world, at approximately

20.5 million b/d. Of this, nearly half of the demand is for gasoline.

Transportation fuels comprise the vast majority of U.S. demand, though demand

for heating fuels boosts overall refined product demand in the winter months.

Total U.S. refining capacity is 17.4 million b/d. The U.S. is reliant upon imports

to meet daily refined product demand. A large portion of the imports are from

Western Europe.

Refining is a low-margin business, with ROCEs generally in the 9%-12% range

at mid-cycle. The main driver of profitability is the refining margin, which is

the difference in price between the crude feedstock and the refined products

produced. Refining margins are cyclical, typical of a manufacturing business. In

2004-06, high refining margins boosted returns to well above the norm.

U.S. refineries are among the most sophisticated and efficient in the world.

Approximately one-half of the refining capacity in the U.S. is located on the

Gulf Coast. An extensive pipeline system helps transport product to the

Midwest and the Northeast. The West Coast and the Rocky Mountain regionare isolated, with local refineries serving local market needs.

No new refineries have been built in the U.S. since the 1976. New builds are

costly and the permitting process is daunting. Environmental concerns have

spawned a “not in my backyard” mentality. However, refiners have effectively

added new capacity through expansion and de-bottlenecking projects. These are

far less costly in terms of dollars per daily barrel of refining capacity, so refiners

have no real incentive to build a refinery from the ground up.

Environmental regulations in the U.S., which were achieved through tighter fuel

specs, were disruptive to supplies in 2004-06, and helped drive refined product prices to very high levels. This contributed to unusually high refining margins

and profitability throughout this period.

The are three primary phases of the process, which are described below.

Step No. 1: Separation

The input to refineries primarily is crude oil. The first step typically is a distillation

process to separate molecules by size. Each range of molecule size is specific to a

particular refined product (see Exhibit 23). For instance, the lightest molecules may

be gases such as butane and propane. The heaviest molecules, or residual, may be

used for asphalt production or bunker fuel. The most valuable refined petroleum

products are “middle of the barrel” products — e.g., gasoline, diesel fuel, jet fuel, and

heating oil.




Exhibit 23. Distillation Tower

Source: U.S. Energy Information Administration.

Step No. 2: Conversion

During the conversion process, molecules are further split, or “cracked,” through the

use of heat, chemicals, and pressure to transform streams from the separation process

into finished product. Cracking units include the fluid catalytic cracker (FCC),

hydrocracker, and cokers. Alkylation units and reformers also alter molecule sizes.

All of these units have specialized functions that convert certain-type molecules into

gasoline and middle distillates. A refinery, depending on its level of complexity, is

typically configured with one or more of these units.

Step No. 3: Treatment Finally, streams from the processing units are purified and blended according to

customer specifications and government standards. For instance, in gasoline, octane

levels are adjusted, and performance additives may be blended in to create different

brands or grades of gasoline. Typical units for the treatment process include

hydrotreaters, desulfurization units, and isomerization units.

Exhibit 24 lists the principal refined products that are derived from a barrel of oil for

an average U.S. refinery. Each product has its own supply and demand fundamentals

that sets its price. Gasoline comprises approximately 46% of the barrel, and is

typically one of the highest-valued products. Refineries with sophisticated

conversion units have the flexibility, when the economics warrant, to boost production of high-valued products, such as gasoline or distillate, and to lower the

yield of low-valued products.

R EFINED PRODUCTS



Exhibit 24. What a Barrel of Crude Oil Makes(1)

Product Gallons per Barrel

Gasoline 19.5s a e ue o

(includes both home heating oil and diesel fuel) 9.2

Kerosene-type jet fuel 4.1Redisual fuel oil

(heavy oils used as fuels in industry,marine transportation and for

electric power genration) 2.3

Liquefied refinery gasses 1.9Still Gas 1.9

Coke 1.8

Asphalt and road oil 1.3

Petrochemical feedstocks 1.2Lubrincants 0.5

Kerosene 0.2

Other 0.3

(1) Figures based on 1995 average yields for U.S. refineries. One barrel contains 42 gallons of crude oil. The total volume of

products made is 2.2 gallons greater than the original 42 gallons of crude oil. This represents “processing gain.”Source: American Petroleum Institute.




Drivers of Refiners’ Financial Performance

We believe the following items are the most important drivers of refiners’ financial

performance:

Refining Margins. Refining margins are the most influential factor; all refiners’

earnings are highly leveraged to changes in refining margins.

Refinery Complexity. Plants that are more sophisticated, with capabilities to

process cheaper feedstocks, are typically more profitable.

Light/Heavy Spreads. Wide price differentials between light, sweet crudes and

heavy, sour crudes benefit refiners with complex refining capacity.

Operating Costs. The low-cost operator has a competitive advantage.

Plant Reliability. Unplanned downtime can have a meaningfully adverse affect

on profitability.

Financing and Overhead Costs. Efficiency and financial flexibility are crucial

due to the volatile nature of the business.

The refining margin is the difference between the price for refined products

manufactured (e.g., gasoline and diesel fuel) and the cost of the feedstock (crude oil).

Refining margins are calculated in terms of $/bbl.

In our modeling work, we calculate a proxy “3-2-1 crack spread” to approximate the

gross profit margin for a refinery. A commonly used term, 3-2-1 refers to the

proportion of gasoline and heating oil produced — i.e., for three parts of oil, two

parts are converted into gasoline, and one part into heating oil. For a 42-gallon barrelof oil, the 3-2-1 implies that a refiner produces 28 gallons of gasoline and 14 gallons

of heating oil. For some refineries, it might be more appropriate to use a 4-3-1

spread (three parts gasoline, one part heating oil), or a 6-3-2-1 spread (three parts

gasoline, two parts heating oil, one part residual fuel). The 3-2-1 is the most

commonly used configuration for calculation of a proxy margin, using any selection

of spot prices for crude and refined product quoted on Bloomberg, Reuters, or Platts

(see Appendix for tickers and data resources). A 3-2-1 proxy refining margin

calculation would look like this:

Oil price = $40/bbl

Gasoline spot price = $1.27/gal

Heating oil spot price = $1.05/gal

Refining Margin =

([$1.27 x 28 gallons]+[$1.05 x 14 gallons]) - $40/bbl

= $10.26/bbl

R EFINING MARGINS



Leverage to Refining Margins

Refiners’ earnings are highly sensitive to changes in refining margins. We calculate

a company’s leverage to a $1.00/bbl change in the refining margin by taking the total

number of barrels refined in a year, multiplying it by one minus the tax rate, and

dividing it by the number of shares outstanding.

Earnings can swing widely, depending on refining margins. For the integrated oils,

the overall leverage is diluted by the large upstream operations, which serve as a

natural hedge. For the independent refiners, the exposure is far greater. For instance,

the capacity of the average-size refinery in the U.S. is 105,000 b/d, or 38.3 million

barrels per year. A $1.00/bbl change in refining margins affects the pretax operating

profit of the average refinery by $38.3 million per year. Most independent refiners

have more than 105,000 b/d of refining capacity, and lately, movements in refining

margins have been far greater than $1.00/bbl.

Exhibit 25 below shows the impact on earnings per share of a $1.00/bbl change in

refining margins for the independent refiners and major oils under our coverage.

Exhibit 25. Oil Company Earnings Leverage to Changes in Refining MarginsEstimate $ Change in 2008E

2008E 2008E Refining EPS per $1/Barrel Change % Change

Operating EPS Runs (Bbls/share) in Refining Margins in 2008E EPS

Sunoco $5.10 2.9 $1.91 37.5%Tesoro Corp. 4.75 2.9 1.76 37.1Valero Energy Corp. 4.50 2.0 1.36 30.1Western Refining 1.65 0.7 0.43 25.8Frontier Oil Corp. 1.85 0.6 0.38 20.3Marathon Oil 8.50 1.1 0.68 8.0Royal Dutch Shell 5.60 0.5 0.29 5.2Murphy Oil 4.45 0.4 0.22 4.9Exxon Mobil 4.90 0.4 0.23 4.6Hess Corporation 5.35 0.3 0.22 4.1ConocoPhilips 7.40 0.5 0.30 4.1

TOTAL S.A. 5.95 0.4 0.23 3.9BP 5.35 0.3 0.18 3.4Chevron 6.60 0.4 0.19 2.9

Weighted Average 5.2%


Regional Proxy Refining Margins

The nation is divided into refining centers by Petroleum Administration for Defense

Districts (PADDs) (see Exhibit 26). PADDs were created during World War II to

facilitate oil allocation.




Exhibit 26. Petroleum Administration for Defense Districts


Each PADD has characteristics that are unique to the markets they serve. For this

reason, refining margins may also vary by PADD. Therefore, proxy margins are

typically calculated by region in order to assess the environment and best estimate of refiners’ profitability.

Below, we summarize key characteristics by PADD.

PADD 1 (East Coast). Approximately 10% of the nation’s refining capacity is

located in PADD 1, although the region accounts for a higher proportion of

product demand. We estimate that 35%-40% of the nation’s gasoline is

consumed in PADD 1, and that 85%-90% of heating oil is used in New England

and the Mid-Atlantic region. PADD 1 is well connected to the Gulf Coast by

pipeline. Also, the East Coast is the primary destination of exports from Europe,

and a popular destination from Asia.

PADD 2 (Midwest). The Midwest region is home to approximately 20% of the

nation’s total refining capacity. The region is product short, and reliant upon the

Gulf Coast to make up the shortfall, particularly for gasoline. However, recently,

cities and states in the Midwest have designated specific standards for gasoline in

certain markets in the Midwest. Known as “boutique fuels,” this has created a

challenge for suppliers outside of these regions. As a result, supply has tightened

in the last two to three years, and product prices have become more volatile.

PADD 3 (Gulf Coast). The largest and most competitive refining center, this

region accounts for almost one-half of the nation’s refining capacity. Refineries

on the Gulf Coast are larger than the nationwide average, and most are

sophisticated. The Gulf Coast is a destination for refined product exports from

Asia and Europe. Thanks to an extensive pipeline system, Gulf Coast refineries

can supply most markets east of the Rockies.

PADD 5 (West Coast). Almost 20% of the nation’s refining capacity is located

on the West Coast, the majority of which is in California. The West Coast is

known as an isolated market for several reasons. First, it was not connected to

any other refining area in the U.S. by pipeline until recently. In late 2004, the



Longhorn pipeline was completed, which transports fuel from the Gulf Coast to

the Southwestern United States. This pipeline should shift supply manufactured

in the Southwestern U.S. to Southern California; however, the full impact of this

pipeline remains to be seen. Second, stringent standards for gasoline in

California, set forth by the California Air Resources Board (CARB), make it

more difficult and costly to manufacture gasoline for California, and fuels from

other parts of the country cannot be used there. As a result, gasoline in California

typically commands a higher price and refiners there enjoy higher margins thanother areas of the country. While the market is self-sufficient, the supply/demand

balance is quite delicate. Unplanned refinery outages can cause large swings in

product prices.

PADD 4 (Rocky Mountains). This area accounts for only 3% of the country’s

refining capacity. The refineries here are small, at an average of 35,000 b/d, and

serve local markets. Benchmark margins are harder to find for these markets

given their small size and isolation. In general, refining margins here are above

the nationwide average, and somewhat less volatile.

All Refineries Are Not Alike

In the U.S., there are approximately 132 operating refineries. Product yields from

these plants can vary significantly, depending on their configuration, and

“complexity.” More complex refineries are typically able to produce higher yields of

gasoline and middle distillate than simple refineries. In addition, complex refineries

can process cheaper, lower grades of crude oil, which can enhance the plants’

margins. Units needed to produce higher yields of gasoline or process cheaper

grades of crude oil include hydrocrackers and cokers, and can cost $10,000-$20,000

per barrel of daily refining capacity. However, upgrading projects can pay off

quickly, depending on refined product price spreads and light/heavy price

differentials on crude oil. Refineries in the U.S. are among the world’s most

complex, particularly those on the Gulf Coast and on the West Coast, where refinershave access to a variety of low-quality crudes.

The industry uses two measures to rate the complexity of a refinery, with a higher

number indicating higher complexity.

Nelson Complexity Rating. The Nelson Complexity Rating (NCR) is a measure

of secondary conversion capacity in comparison to the primary distillation

capacity of any refinery. It is an indicator of not only the investment intensity or

cost index of the refinery, but also the value-added potential of a refinery. The

index was developed by Wilbur L. Nelson in 1960 to originally quantify the

relative costs and throughput of the components that constitute the refinery. Mr. Nelson assigned a factor of one to the primary distillation unit. All other units

are rated in terms of their costs relative to the primary distillation unit, also

known as the atmospheric distillation unit. The average NCR for refineries in the

U.S. is approximately 9.5.

R EFINERY

COMPLEXITY




Solomon Complexity. The Solomon Complexity rating was developed in a

proprietary survey produced by Solomon Associates, Inc. It is an industry

measure of a refinery’s ability to produce higher-value products from a lower-

value feedstock, with a higher rating indicating a greater capability to produce

such products from such feedstocks. The average Solomon Complexity rating of

a U.S. refinery is 14.0.

Realized Refining Margins and Refinery Configuration

Sophisticated refineries have the capability to process lower-quality crudes due to the

hardware configuration of the plant. Typically, these refiners can realize a higher

refining margin because of the discounted price of lower-quality crudes to light,

sweet crudes. Crude density is commonly measured by API gravity and classified as

light (API of 31 degrees or higher), medium (API between 22 and 31 degrees), or

heavy (API of 22 degrees or less). The higher the API number, the lighter the crude.

Sulfur content is also a characteristic of crude oil. The higher the sulfur content, the

more sour it is and the more processing is needed to meet regulatory specifications.

Generally, sulfur content that is less than 0.5% is considered sweet, and sulfur

content that is greater than 0.5% is considered sour. West Texas Intermediate is theU.S. industry benchmark crude oil — with an API gravity of 40 degrees and sulfur

content of 0.3%. Examples of lower-quality crude oils are illustrated in Exhibit 27.

Exhibit 27. Types of Lower-Quality Crude Oils

Name of Crude Oil API Gravity Sulfur Content Characteristics

Maya (Mexico) 22 degrees 3.30% Used by many Gulf Coast refiners

Arab Heavy(Saudi Arabia)

27 degrees 2.80% Used by many Gulf Coast andMidwest refiners

Canadian Bow River (Canada)

25.7 degrees 2.10% Used by many Midwest and RockyMountain refiners

West Texas Sour (U.S.) 33 degrees 1.60% Used by many Gulf Coast refiners

Source: Platts; Bloomberg.

Product yields also are affected by refinery configurations. The most efficient plants

produce roughly 75%-80% gasoline, gasoline blendstocks, and distillate products

(such as diesel fuel, heating oil, and jet fuel). Less-efficient plants produce a higher

quantity (more than 25%) of lower-valued by-products such as petrochemicals, lubes,

asphalts, petroleum coke, and residual fuel oil (typically used as industrial boiler

fuel).

Refining margins at complex refineries will be higher than the proxy margins for the

refining district, because most conventional spread calculations assume WTI, a light,

sweet crude, as the feedstock. The amount by which the margin is above the proxywill vary, depending on the light/heavy spread and refinery yield. In contrast,

margins at refineries with a sweet crude slate that produce mostly “middle of the

barrel” products will approximate the proxy margins. For example, Exhibit 28 shows

fourth-quarter 2004 results for two U.S. refineries owned by Premcor Inc. (now part

of Valero) in the United States. The Port Arthur, Texas, refinery has a coker,

allowing it to use heavy Maya crude as 80% of its crude feedstock slate. Lima is a

Midwestern refinery (Ohio), which processes primarily sweet crude. Our fourth-

quarter 2004 proxy margins for the Gulf Coast and Midwest were $5.51/bbl and

$4.73/bbl, respectively.

LIGHT/HEAVY

SPREADS AND

PRODUCT YIELDS



Exhibit 28. Operating Results at Valero Refineries (in millions b/d)

Port Arthur 4Q04 Lima 4Q04

Throughput (mb/d) 257.5 Throughput (mb/d) 147.9

Gross Margin ($/bbl) 15.28 Gross Margin ($/bbl) 5.02

Operating Expense ($ in millions) 96 Operating Expense ($ in millions) 38.3

Operating Expense ($/bbl) 4.05 Operating Expense ($/bbl) 2.81

Operating Profit ($ in millions) 265.98 Operating Profit ($ in millions) 30.01

Operating Profit ($/bbl) 11.23 Operating Profit ($/bbl) 2.21 Source: Valero company reports.

Exhibit 29 shows average spreads between light (WTI) and lower-quality crude oils.

Exhibit 29. Average Spreads Between WTI and Lower-Quality Crude Oils

WTI/WTS WTI/Arab Heavy WTI/ Lloydminster WTI/Maya WTI/Bow River

1996 1.23 3.98 0.43 4.80 3.90

1997 1.68 3.41 3.56 5.66 5.47

1998 1.55 3.49 3.50 5.68 4.74

1999 1.30 2.88 -0.95 4.78 3.51

2000 2.16 5.17 -3.96 7.49 7.06

2001 2.81 3.99 1.80 8.68 9.95

2002 1.38 2.69 3.25 5.21 6.06

2003 2.71 4.58 8.92 6.81 8.14

2004 3.93 9.96 13.83 11.33 12.83

2005 4.65 10.35 21.67 15.61 15.50

2006 5.14 9.25 22.41 14.82 12.00

Average 1996-2006 2.59 5.43 8.03 8.37 8.11

Source: Platts; Global Insights.

Heavy or sour crudes require more processing than light, sweet crude oil. Therefore,

operating costs at the more complex refineries can be high. We estimate most

complex refineries in the U.S. have operating costs that are $1.50/bbl above the

average sweet crude refinery. When light/heavy spreads are wide, complex refineries

may have a significant price advantage over sweet crude refiners. However, when

light/heavy spreads are narrow, the price advantage can be diminished, or mitigated

completely, by higher operating costs. Exhibit 30 shows the leverage to the heavy-

sour crude oil spread for the independent refiners.

Exhibit 30. Heavy-Sour Crude Oil Leverage

Heavy-Sour Crude as a Impact on EPS

Pecent of Total to $1/bbl Change in the % Change to 2007Feedstock Slate Light/Heavy-Sour Spread EPS Estimates

Frontier 69% $0.24 13.6%

Valero 55% $0.72 11.7%

Tesoro 11% $0.20 2.9%

Sunoco 9% $0.16 2.2%

Western 10% $0.04 2.4%

Heavy-Sour Crude Leverage





Operating costs vary by refinery. However, a high percentage of a refiner’s operating

costs are fixed. Energy costs represent the largest portion of operating costs at mid-

cycle conditions (see Exhibit 31). These costs are also the most variable, due to

swings in crude oil, electricity, and natural gas prices.

Exhibit 31. Components of Operating Costs

Energy 40%-50%

Employee Labor 35%-40%

Maintenance and Repair 10%-15%

Other 5%-10%

Source: Bear, Stearns & Co. Inc. estimates.

Because of the high ratio of fixed costs, the best way to minimize per-barrel

operating costs is to use the plant’s capacity efficiently and avoid unplanned

disruptions in operations. The independent refiners’ refinery utilization rate is near

100%.

Refineries run 24 hours a day, 365 days a year. Generally, refineries need to undergo

extensive plant-wide maintenance lasting for approximately 30 days once every four

years, although the work on particular units within the refinery may be staggered so

that parts of the plant are running at all times. Planned maintenance can be managed

to minimize revenue losses by building inventories and by refining around units that

are down. However, excessive plant maintenance or unplanned outages in a

refinery’s operations result in lost income. This can meaningfully impact a

company’s financial results, particularly smaller companies with relatively low

throughput levels. For example, a company with refining capacity of 200,000 b/d

might earn net income of $150 million at mid-cycle conditions. A 10,000 b/d (5%)

reduction in throughput would reduce this refiner’s net income by an estimated 6%.

As with most businesses, excessive financing and overhead costs can erode profitmargins and are more of a concern for smaller refining companies, which cannot

allocate these overhead costs across extensive refinery systems. For example, in

2004, the percentage of financing and overhead costs to operating profit ranged from

a high of 34% for Frontier Oil, a two-refinery company, to a low of 17% for Sunoco,

the second-largest independent refiner.

Given the strong refining margins for the industry in 2004-06, financing costs have

fallen dramatically as companies have paid down debt with free cash flow. In 2003,

financing and overhead costs for the group accounted for approximately 52% of

operating profits; however, they declined to 15.7% of operating profit in 2006. When

refining margins are low, high financing and overhead costs can cause refiners’earnings to fall below breakeven. Depending on the efficiency of the company and

the plants, earnings breakeven margins’ requirements will vary by company, with

low-cost operators faring better than less efficiently run companies.

OPERATING COSTS

PLANT R ELIABILITY

FINANCING AND

OVERHEAD COSTS



Tracking Industry Fundamentals

Refining is a cyclical and sometimes volatile business. Because refiners’ profitability

is so dependent upon refining margins, the key to investing in an independent

refining company is determining the direction, magnitude, and sustainability of

moves in margins.

The following factors influence refining margins:

crude and product inventory levels;

refinery utilization rate;

product imports;

refined product demand outlook;

feedstock costs and product prices;

light/heavy spreads; and

environmental regulation.

It is important to monitor inventory levels, refinery utilization, import levels, and

refined product demand in order to assess the health and status of the refining

industry (see Exhibit 32). Examining these data points in relationship to one another

may help to determine sustainable trends in refining margins.

Exhibit 32. Bullish/Bearish Indicators

Bullish Refining Indicators Bearish Refining Indicators

Low/Declining Inventories andHigh Refinery Utilization

High/Rising Inventories andLow Refinery Utilization

Average/Below-Average Imports High Imports

Wide Light/Heavy Spreads Narrow Light/Heavy Spreads

Gradually Declining Crude Prices Rising Crude Prices

Robust Worldwide Economies Sluggish Worldwide Economies

Strong U.S. GDP Falling U.S. GDP

Strong Refined Product Demand Weak Refined Product Demand

Source: Bear, Stearns & Co. Inc.

In general, product prices are inversely correlated to changes in inventory levels (see

Exhibit 33). Inventory levels are influenced by a variety of factors, including

demand, refinery utilization rates, and imports.

INTERPRETING DOE INVENTORY R EPORTS




Exhibit 33. Gasoline Prices Versus Gasoline Inventories

30.00

80.00

130.00

180.00

230.00

1 / 6 / 1 9 9 5

8 / 1 8 / 1 9 9 5

3 / 2 9 / 1 9 9 6

1 1 / 8 / 1 9 9 6

6 / 2 0 / 1 9 9 7

1 / 3 0 / 1 9 9 8

9 / 1 1 / 1 9 9 8

4 / 2 3 / 1 9 9 9

1 2 / 3 / 1 9 9 9

7 / 1 4 / 2 0 0 0

2 / 2 3 / 2 0 0 1

1 0 / 5 / 2 0 0 1

5 / 1 7 / 2 0 0 2

1 2 / 2 7 / 2 0 0 2

8 / 8 / 2 0 0 3

3 / 1 9 / 2 0 0 4

1 0 / 2 9 / 2 0 0 4

6 / 1 0 / 2 0 0 5

1 / 2 0 / 2 0 0 6

9 / 1 / 2 0 0 6

G a s o l i n e

P r i c e ( c e n t s g a l )

180,000

190,000

200,000

210,000

220,000

230,000

240,000

G a s o l i n e I n v e n t o r i e s ( 0 0 0 s b b l s )

Gasoline Price Gasoline Inventories

Source: Platts; Global Insights; U.S. Energy Information Administration.

U.S. data on crude and product inventories are the most accurate and timely in the

world. Figures are reported on a weekly basis (Wednesdays at 10:30 a.m., EasternTime) by both the Department of Energy and the American Petroleum Institute.

Traders and industry analysts watch the data, as changes in inventories can be a

leading indicator of longer-term trends. Bear Stearns’ analysis also includes a section

that excludes movements in PADD 5, because the district is an isolated region where

one extra shipment or fewer shipments from Alaska can cause large fluctuations in

the inventories. We classify inventory builds and draws for crude oil or refined

products in Exhibit 34.

Exhibit 34. Classification of Movements in Inventory Levels

Amount of Build/Draw Classification

Builds of five million barrels or greater Bearish

Builds of less than five million barrels but greater than one million Moderately Bearish

Builds or draws of less than one million barrels Neutral

Draws of less than five million barrels but greater than one million Moderately Bullish

Draws of five million barrels or greater Bullish


Inventory levels are a good indicator of how supply and demand match up (see

Exhibit 35). There tends to be a strong negative correlation between refining margins

and inventory levels. When inventories are low, refining margins typically are high.

When inventories are high, refining margins are often depressed (see Exhibit 36).

However, during the period from 2005 to 2006, this relationship broke down. During

this time, there were both high inventory levels and, counterintuitively, high refining

margins. We believe higher refining margins were largely driven by nonrecurring

supply-side events, including the effects of Hurricanes Katrina and Rita, which shut

in approximately 10% of U.S. refining capacity for a prolonged period, as well as the

introduction of more stringent fuel regulations, both of which contributed to

abnormally high product prices, during this time period.



Exhibit 35. Average Inventory Levels by Year

207200 198

219210

198205 209 203 204 208 210

132119117116128

118108

136137

119105

125

0

50

100

150

200

250

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

I n v e n t o r i e s

( m i l l i o n s b b l s )

Gasoline Distillate


Exhibit 36. Refining Margins Versus Gasoline Inventory Levels

$1.50

$6.50

$11.50

$16.50

$21.50

1995 1996 1997 1998 1999 1999 2000 2001 2002 2003 2004 2005 2006

U S G u l f C o a s t 3 - 2 - 1 ( $ / b b l )

155

175

195

215

235

G a s o l i n e I n v e n t o r i e s ( m i l l i o n b b l s )

USGC 3-2-1 Gasoline Inventory

Source: Platts; Global Insights; U.S. Energy Information Administration.

Typical Inventory Levels Vary by Season

Gasoline inventories usually are at their highest in the spring ― the beginning of the

driving season — and deplete throughout the year into the following January.

Distillate inventories typically reach their highest levels of the year in the fall, as the

heating season gets under way, and fall from late January through April (see Exhibit

37).




Exhibit 37. Gasoline and Distillate Inventories

Gasoline Inventories

185

195

205

215

225

235

Mar Jun Sep Dec

M i l l i o n

B a r r e l s

10-Year Range

10-Year Av erage 2006

Distillate Inventories

80

90

100

110

120

130

140

150

160

Mar Jun Sep Dec

M i l l i o n B a r r e l s

10-Year Range

10-Year Av erage 2006


Days’ Supply of Inventory

It is helpful to look at inventory levels in relation to demand. Days’ supply gives a

measure of how many days of inventory are available given current or projected

demand. This is calculated by taking the amount of inventories of a particular

product and dividing it by the daily demand for that product. Exhibit 38 shows

inventories on a days’ supply basis for gasoline and distillate.



Exhibit 38. Gasoline and Distillate Inventories on a Days’ Supply Basis

20

22

24

26

28

Jan. Feb. Mar. Apr. May Jun. Jul . A ug. S ep. Oc t. N ov. D ec .

D a y s o f S u p p l y o f G a s o l i n e

2003 2004 2005 2006

20

22

24

26

28

30

32

34

36

38

Jan . Feb . Mar . Apr . May Jun . Jul . Aug .Sep. Oct . Nov .Dec.

D a y s o f S u p p l y o f D i s t i l l a t e

2003 2004 2005 2006


Refinery utilization is refinery throughput (barrel of oil input into the distillation unit)

expressed as a percentage of the nation’s operable refining capacity (utilization =

throughput divided by 17.4 million b/d of operable refining capacity for the U.S.,

according to the U.S. Energy Information Administration). Typically, the industry

runs at a utilization rate of 90%-95%, depending on the season (see Exhibit 39). The

highest run rates are seen during the spring and summer, when gasoline demand is

strongest.

An unplanned refinery outage or planned maintenance work decreases the refinery

utilization rate because the DOE and API do not adjust available capacity for

maintenance downtime. So, for example, in September 2005, when Hurricanes

Katrina and Rita hit the Gulf Coast and reduced refinery operations, utilization rates

temporarily plummeted. Another situation that may cause refinery utilization rates to

decline is voluntarily run cuts when refining margins are weak. Likewise, strong

refining margins usually prompt higher utilization rates.

Refinery utilization rates are an important indicator of the health of the industry.Low refining margins coupled with low refinery utilization rates is a signal that

supplies are plentiful, relative to demand. High utilization rates typically mean high

margins. If fundamental industry conditions are supportive, margins can be sustained

for several months, until the supply response balances the market.

R EFINERY

UTILIZATION




Exhibit 39. U.S. Refinery Utilization

70

75

80

85

90

95

100

M a r J u

n S e

p t D e

c

% O p e r a t e d

10-Year Range2006 10-Year Average2007

2005 Hurricanes:


Contrary to popular belief, utilization in the U.S. has not changed much despite rising

demand and refinery closures (see Exhibit 40). One would expect utilization to be at

historical high levels, but utilization has dropped off since the late 1990s. This islargely because of capacity creep and rising imports. The term “capacity creep”

refers to capacity expansions through de-bottlenecking investments that effectively

create additional refining capacity from the same physical structure. While difficult

to measure, because investments may be small and unpublicized, we estimate that

capacity creep averages approximately 1%-2% of total domestic capacity annually.

As a result, despite a lack of new refineries and refinery closures over the last ten

years that shut down approximately 700,000 b/d of capacity, overall domestic

refining capacity has grown at an average rate of 0.7% per year through capacity

creep and expansion projects.

An increasing supply of imports have also kept utilization rates below their peak in1998 (see Exhibit 43 on page 67). Since 1995, gasoline imports in the U.S. have

more than tripled, to approximately one million b/d. Today, gasoline imports account

for an estimated 10% of U.S. gasoline supplies versus 4% in 1995.

Exhibit 40. U.S. Refinery Utilization by Year

88.0

89.0

90.0

91.092.0

93.0

94.0

95.0

96.0

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

% O

p e

r a t e d

U.S. Refinery Utilization




The spread between light/heavy crude oil prices also can affect utilization. Typically,

when light/heavy crude oil differentials widen, the spread between gasoline and

residual fuel prices widens as well. Complex refiners usually run their units at as

close to full as they can, given superior product yield and margins. Simple refineries

represent marginal supply in the industry. These less-sophisticated refineries produce

a higher proportion of “bottom,” or residual, fuels. These by-products are often sold

at a loss. When light/heavy spreads are wide, losses on residual fuel production are

steeper, prompting the simple refineries to reduce runs. When light/heavy spreadsnarrow, the loss on residual fuel sales usually declines, eventually by enough to

restore profitability on the entire refined barrel for unsophisticated refiners.

Occasionally, residual fuel prices are higher than crude oil feedstock costs. As

profitability improves for the simple refinery, runs are increased. This can lead to a

confusing picture — industry utilization may increase sharply as light/heavy spreads

narrow and crack spreads fall. It can look like the industry is increasing supply the

more margins weaken. Such was the case in 1998. As oil prices plummeted

(light/heavy margins also fell), refinery utilization climbed, and crack spreads fell

sharply. By looking only at crack spreads (the industry barometer for profitability),

we can miss the key factor that changes marginal production — the spread between

residual and crude oil prices.

The refining business is increasingly becoming a global business. While no new

refineries have been built in the U.S. for more than 30 years, several large units have

been built around the world, primarily in Asia, representing several million barrels of

refining capacity. Exhibit 41 shows worldwide utilization rates. Although the trend

appears to show utilization rates increasing, approximately 15% excess capacity

exists.

Exhibit 41. Worldwide Refinery Utilization

81.0%

82.0%

83.0%

84.0%

85.0%

86.0%

87.0%

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

% O p e r a t e d

Worldwide Utilization

Source: BP Statistical Review of World Energy, June 2005; Purvin & Gertz; Oil & Gas Journal (for 2006).

No market is truly isolated when it comes to refined products. The unique CARB

gasoline formulations, required to be sold in California, are made in the Caribbean,

U.S. Gulf Coast, Europe, and Asia. Stronger product prices in any given part of the

world attract imports from other regions. Refiners in Europe and Asia will take

advantage of opportunities to sell refined products in the U.S. when the pricing is

attractive.

PRODUCT IMPORTS




Exhibit 42. Gasoline Imports and Import Margin

200

400

600

800

1000

1200

1400

1600

1800

9 / 1 3 / 1 9 9 6

1 / 3 1 / 1 9 9 7

6 / 2 0 / 1 9 9 7

1 1 / 7 / 1 9 9 7

3 / 2 7 / 1 9 9 8

8 / 1 4 / 1 9 9 8

1 / 1 / 1 9 9 9

5 / 2 1 / 1 9 9 9

1 0 / 8 / 1 9 9 9

2 / 2 5 / 2 0 0 0

7 / 1 4 / 2 0 0 0

1 2 / 1 / 2 0 0 0

4 / 2 0 / 2 0 0 1

9 / 7 / 2 0 0 1

1 / 2 5 / 2 0 0 2

6 / 1 4 / 2 0 0 2

1 1 / 1 / 2 0 0 2

3 / 2 1 / 2 0 0 3

8 / 8 / 2 0 0 3

1 2 / 2 6 / 2 0 0 3

5 / 1 4 / 2 0 0 4

1 0 / 1 / 2 0 0 4

2 / 1 8 / 2 0 0 5

7 / 8 / 2 0 0 5

1 1 / 2 5 / 2 0 0 5

4 / 1 4 / 2 0 0 6

9 / 1 / 2 0 0 6

W e e k l y I m p o r t s ( 0 0 0 b / d ) - 4 - W e e k L a g

(25)

(20)

(15)

(10)

(5)

0

5

10

15

20

25

I m p o r t M a r g i n ( c p g )

Gasoline Imports Import Margin


Recently, gasoline prices in the U.S. compared to other regions have been high.

Exhibit 42 above shows the import margin for gasoline to New York from Northwest

Europe. The import margin is the difference in pricing for gasoline in New York

Harbor and Rotterdam, adjusted for transportation costs. For most of the last several

years, the margin has been positive, providing incentive for refiners to send product

to the United States. Typically, imports rise when the margin is high. In addition,

European demand for transportation fuels has been shifting away from gasoline

toward diesel fuel due to the more desirable economics, freeing up supply of gasoline

for export. As Exhibit 43 shows, gasoline and distillate imports in the U.S. have been

rising.

Exhibit 43. Gasoline and Distillate Imports

0100

200

300

400

500

600

700

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

T h o u s a n d s b / d

Gasoline Imports Distillate Imports

Source: Global Insights; Platts; U.S. Energy Information Administration.



Demand for gasoline in the U.S. has grown at an average annual average rate of 1.5%

over the past 20 years. The range for the year-over-year rate of change in demand is

a high of 3.0% in 1986 to a low of negative 1.3% in 1990. Demand for gasoline is

influenced by a variety of factors, including the strength of the economy and gasoline

prices. Demographic trends and fuel efficiency initiatives also affect demand. In

2003 and 2004, a strong economy and the prevalence of SUVs boosted gasoline

demand. However, recent high prices appear to have dampened gasoline demand,

which is seasonal, peaking in July or August. January is typically the month in whichdemand is lowest (see Exhibit 44).

Swings in gasoline demand can have a meaningful effect on the supply/demand

balance for refined products. For instance, in the first half of 2004, demand rose by

2.4% year over year, but slowed to just 0.6% growth in the second half. In that time,

gasoline inventories went from being 600,000 barrels below the ten-year average at

the beginning of 2004 to being 12 million barrels above the ten-year average at the

end of the year.

Exhibit 44. U.S. Gasoline Demand by Month

7,000

7,500

8,000

8,500

9,000

9,500

10,000

J a n - 9 5

J a n - 9 6

J a n - 9 7

J a n - 9 8

J a n - 9 9

J a n - 0 0

J a n - 0 1

J a n - 0 2

J a n - 0 3

J a n - 0 4

J a n - 0 5

J a n - 0 6

D e m a n d ( 0 0 0 s b / d )


There is a correlation between gasoline demand and GDP growth, but the relationship

is circular (see Exhibit 45). A strong economy stimulates demand. In the last 20

years, each time real GDP grew by 4% or more, gasoline demand grew on average

2.0%, above the average annual growth rate of 1.5%. Strong demand can deplete

inventories and boost prices. Inventory levels were below average in both 2003 and

2004, resulting in high gasoline prices, often in excess of $2.00 per gallon. In turn,

high fuel prices dampen the economy by reducing consumers’ disposable income,

and increasing costs for businesses (see our discussion on price elasticity below).

GASOLINE DEMAND




Exhibit 45. U.S. GDP Versus Gasoline Demand

-3.0%-2.0%-1.0%0.0%1.0%2.0%

3.0%4.0%5.0%6.0%7.0%

1 9 8 1

1 9 8 3

1 9 8 5

1 9 8 7

1 9 8 9

1 9 9 1

1 9 9 3

1 9 9 5

1 9 9 7

1 9 9 9

2 0 0 1

2 0 0 3

2 0 0 5

P e r c e n t a g

e C h a n g e

Gasoline Demand Real GDP

Source: U.S. Bureau of Economic Analysis; U.S. Energy Information Administration.

Gasoline demand’s price elasticity is relatively low, except when prices reach highlevels. Exactly how high the levels must be to dampen demand came into question in

2006, when gasoline prices topped $3.00 per gallon. Historically, we have observed

that seasonally adjusted gasoline demand has fallen from the previous month 65% of

the time that prices rise above $1.60 per gallon (see Exhibit 46). However, since

September 2004, the market’s response to this level of gasoline price seems to have

changed. We believe consumers may become used to a higher price level after

experiencing it for several months. The price trigger for demand deterioration likely

has increased. Today, gasoline prices below $2.25 per gallon seem like a bargain.

The new trigger point may be higher than $2.25 per gallon. However, we believe

that at some price level, demand should soften as consumers alter their driving

patterns. Indeed, structural changes are under way in response to high gasoline prices

that may alter demand. For example, sales of SUVs in the U.S. have fallen while

hybrids and other fuel-efficient cars gain in popularity, and the use of alternative

fuels has increased.



Exhibit 46. Demand Elasticity Results

MonthlyRetail Priceper Gallon

Jun-00 $1.63 8497 0.2%Jul-00 1.55 8292 -2.4%

May-01 1.70 8526 -0.8%Jun-01 1.62 8368 -1.9%Feb-03 1.61 8947 -2.0%Mar-03 1.69 8760 -2.1%

Aug-03 1.62 8978 1.8%Sep-03 1.68 8992 0.2%Feb-04 1.65 9176 -2.6%Mar-04 1.74 9086 -1.0% Apr-04 1.80 9090 0.0%May-04 1.98 8988 -1.1%Jun-04 1.97 8885 -1.1%Jul-04 1.91 8867 -0.2%

Aug-04 1.88 8818 -0.6%Sep-04 1.87 9097 3.2%Oct-04 2.00 9075 -0.2%Nov-04 1.98 9136 0.7%Dec-04 1.84 9149 0.1%Jan-05 1.83 9524 4.1%Feb-05 1.91 9233 -3.1%Mar-05 2.08 9252 0.2% Apr-05 2.24 9154 -1.1%May-05 2.16 9067 -1.0%Jun-05 2.16 9034 -0.4%Jul-05 2.29 9062 0.3%

Aug-05 2.49 9015 -0.5%Sep-05 2.90 8964 -0.6%Oct-05 2.72 8986 0.2%Nov-05 2.26 9146 1.8%Dec-05 2.19 9176 0.3%Jan-06 2.32 9473 3.2%Feb-06 2.28 9274 -2.1%Mar-06 2.43 9297 0.2% Apr-06 2.74 9164 -1.4%May-06 2.91 9120 -0.5%Jun-06 2.89 9091 -0.3%Jul-06 2.98 9188 1.1%

Aug-06 2.95 9140 -0.5%Sep-06 2.56 9292 1.7%Oct-06 2.25 9259 -0.4%Dec-06 2.23 9331 0.8%

All Months When Retail Prices Were

Above $1.60 per Gallon

Seasonally Adjusted Demand

(Thousand b/d)

Percent Change in Demand

from Previous Month

Source: Global Insights; Platts; U.S. Energy Information Administration.

U.S. distillate demand has risen by an average of 2% over the last 20 years. Changes

in year-over-year demand have been more volatile than demand for gasoline,

primarily due to swings in weather-driven consumption of heating oil. The year-

over-year change in demand has ranged from a high of 4.9% in 1988 and 1996 to a

low of negative 4.3% in 1990.

Distillate demand, which represents consumption of heating oil and diesel fuel, is

driven by weather and the strength of the economy ― particularly the manufacturing

sector, which influences trucking activity (see Exhibit 47). While weather is

unpredictable, trucking activity can be measured by manufacturers’ shipments

measured by the U.S. Census Bureau, given that trucks haul approximately two-

thirds of tonnage carried by all modes of domestic freight transportation.

DISTILLATE DEMAND




Exhibit 47. Manufacturers’ Shipments Versus Distillate and Implied Diesel Demand

-4.5%

-2.5%

-0.5%

1.5%

3.5%

5.5%

7.5%

1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

P e r c e n t a g e

C h a n g e

Manufacturers' Shipments Distillate Demand Diesel

Source: Haver Analytics; U.S. Census Bureau.

On average, diesel fuel accounts for roughly two-thirds of annual distillate demand,

and consumption does not vary by season. Heating oil is the more volatile, seasonal

component of distillate. Typically, distillate demand peaks in January. The lowest-

demand period for distillate is during the summer months (see Exhibit 48).

Exhibit 48. Distillate Demand by Month

2,500

3,000

3,500

4,000

4,500

J a n - 9 5

J a n - 9 6

J a n - 9 7

J a n - 9 8

J a n - 9 9

J a n - 0 0

J a n - 0 1

J a n - 0 2

J a n - 0 3

J a n - 0 4

J a n - 0 5

J a n - 0 6

D e m a n d ( 0 0

0 ' s b b l s )


There is a misperception that refining margins move with oil prices. Crude feedstock

costs often influence product prices directionally. However, the relationship betweenoil prices and refining margins is less stable. In the past five years, the R-squared for

WTI spot crude oil prices and Gulf Coast refining margins is 0.49 (see Exhibit 49).

The driving factors for prices and margins are supply, demand, and inventory

movements for crude oil versus those for each refined product. Understanding what

may move oil prices is only one step in projecting refining margins.

CRUDE AND PRODUCT

PRICES VS. R EFININGMARGINS



Exhibit 49. Crude Oil Prices Versus Refining Margins

15

25

35

45

55

65

75

85

2000 2001 2002 2003 2004 2004 2005 2006

W T I S p o t P

r i c e ( $ / b b l )

2

7

12

17

22

27

G u l f C o a s t R e f i n i n g M a r g i n ( $ / b b l )

WTI Spot Price Gulf Coast Refining Margins

Source: Global Insights; Platts.

We find that the most important driver to changes in light/heavy spreads is OPEC production levels. The reason for this is that OPEC seeks to maximize the value of

its unit production. As the swing producer, when OPEC cuts production, it typically

reduces output of lower-value, poorer-quality crudes. Reduced supply of this oil

raises its price relative to light, sweet crude, thereby narrowing the spread. When

OPEC expands production, it puts the oil that it had taken off-line back onto the

market, thereby increasing the supply of heavy oil and widening the light/heavy

spread (see Exhibit 50).

Exhibit 50. Light/Heavy Spreads Versus OPEC Production

0

2

4

6

8

10

12

14

16

18

20

1 2

/ 1 / 1 9 9 8

3

/ 1 / 1 9 9 9

6

/ 1 / 1 9 9 9

9

/ 1 / 1 9 9 9

1 2

/ 1 / 1 9 9 9

3

/ 1 / 2 0 0 0

6

/ 1 / 2 0 0 0

9

/ 1 / 2 0 0 0

1 2

/ 1 / 2 0 0 0

3

/ 1 / 2 0 0 1

6

/ 1 / 2 0 0 1

9

/ 1 / 2 0 0 1

1 2

/ 1 / 2 0 0 1

3

/ 1 / 2 0 0 2

6

/ 1 / 2 0 0 2

9

/ 1 / 2 0 0 2

1 2

/ 1 / 2 0 0 2

3

/ 1 / 2 0 0 3

6

/ 1 / 2 0 0 3

9

/ 1 / 2 0 0 3

1 2

/ 1 / 2 0 0 3

3

/ 1 / 2 0 0 4

6

/ 1 / 2 0 0 4

9

/ 1 / 2 0 0 4

1 2

/ 1 / 2 0 0 4

3

/ 1 / 2 0 0 5

6

/ 1 / 2 0 0 5

9

/ 1 / 2 0 0 5

1 2

/ 1 / 2 0 0 5

3

/ 1 / 2 0 0 6

6

/ 1 / 2 0 0 6

9

/ 1 / 2 0 0 6

1 2

/ 1 / 2 0 0 6

$ / b b l

24,000

25,000

26,000

27,000

28,000

29,000

30,000

31,000

32,000

33,000

b / d i n t h o u s a n d s

OPEC Production WTI-Arab Heavy

Source: Global Insights; Platts.

FORECASTINGLIGHT/HEAVY

SPREADS




In 2004-06, new regulations associated with the Clean Air Act required refiners to

reduce sulfur content in gasoline to 30 parts per million (ppm), and in diesel fuel to

15 ppm (see Exhibit 51). We estimate the costs to refiners was approximately $1,000

per barrel of daily refining capacity. Small refineries, particularly in the Midwest and

Rocky Mountain states, where average sulfur content is higher than the national

average, were facing the highest unit costs for compliance. For this reason, many

were granted waivers that allow them to defer full compliance until 2010.

One challenge refiners have faced with ultra-low-sulfur diesel regulations (aside from

sulfur removal) is to accommodate downstream contamination and volume loss due

to reprocessing. According to the regulations, ultra-low-sulfur diesel can be no more

than 15 ppm at the time it is sold at the pump. To get to the pump, various refined

products travel through the same pipeline at different times. As a product runs

through a pipeline, it can pick up sulfur from other refined products that have passed

through the pipeline before it. As a result, the ultra-low-sulfur diesel that leaves the

refinery gate must be lower than 15 ppm (mostly 7 ppm-10 ppm) to offset any stray

sulfur that may be captured in the pipeline. Any amount of ultra-low-sulfur diesel

that is contaminated above 15 ppm will be sent back to the refinery for additional

processing.

Exhibit 51. Low Sulfur Requirements for Gasoline and Diesel by Year

300

120 9030 30

500 500 500

15 15

0

100

200

300

400

500

600

2003 2004 2005 2006 Beyond

S u l f u r C o n t e n t ( P P M )

Gasoline Diesel

Source: U.S. Environmental Protection Agency.

ENVIRONMENTAL

R EGULATIONS



Investing in Refining Stocks

Important points for investing in refining stocks:

Refining is a highly cyclical and sometimes volatile business. In our view,

refining is the most difficult sector in energy to forecast accurately. Refiners’

stock prices move with margins, and a good indicator of the direction in margins

is inventory levels.

There is no seasonality to refining stock prices.

Refinery acquisitions are part of most refiners’ growth strategy.

Historical valuation averages for the refiners: 5.5x-7.0x enterprise value to

EBITDA; 8.0x-14.0x P/E; and 4.5x-7.5x price to cash flow. Multiples tend to

compress at the top of a refining cycle and to expand at the trough. The company

valuation analysis can be found in Section 3 of this report.

At the end of this section, under the headline, “Pointers and Rules of Thumb,” wehave provided tips on modeling and other helpful exercises.

The earnings of independent refiners are highly sensitive to changes in refining

margins. We calculate that each $1.00/bbl change in the refining margin affects

earnings for the five independent refiners under our coverage (Frontier Oil, Sunoco

Inc., Tesoro Petroleum Corp., Valero, and Western Refining) by $1.17, or 25% of our

2008 estimates (see Exhibit 25 on page 54).

As a result of this high operating leverage, refining stocks generally outperform the

market when margins move above mid-cycle levels, and underperform when they

move below mid-cycle levels (see Exhibit 52). The exception to this would appear to be 2006, when average refining margins were above normal, but the performance of

the BSC Refining Index was below that of the S&P 500. In 2006, refining margins

were strongest in the first half of the year, and then came down sharply in the second

half of the year, causing the stock prices to fall sharply as well. As of midyear 2006,

the BSC Refining index was up 23.4%, compared to S&P 500 performance of 2%.

In a volatile margin environment such as 2006, trading in refining stocks is short-

term-oriented.

INVESTING IN

R EFINERS




Exhibit 52. Performance of the S&P 500, Bear Stearns Refining Index, and Refining Margins

-30.0%

-10.0%

10.0%

30.0%

50.0%

70.0%

90.0%

110.0%

130.0%

1 9 9 7

1 9 9 8

1 9 9 9

2 0 0 0

2 0 0 1

2 0 0 2

2 0 0 3

2 0 0 4

2 0 0 5

2 0 0 6

R a t e o f R e t u

r n

0

3

6

9

12

M a r g i n ( $ / b

b l )

SPX Bear Stearns Refining Index Nationwide Avg. Refining Margins

Source: Global Insights; Platts; Bloomberg; Bear, Stearns & Co. Inc. Refining Index.

Refining margins and refining stocks are cyclical and can be highly volatile.

However, the length of cycles are difficult to predict. As we have written in the

previous pages, a host of factors can influence the margin from supply and demand

for crude oil to supply and demand for each refined product. How these market

forces occur and interact makes forecasting refining margins difficult. While not

always 100% accurate, significant inventory draws and builds are good indicators of

a turn in the cycle (see Exhibit 53).

Exhibit 53. Gulf Coast Refining Margin and Nationwide Gasoline Inventories

190

195

200

205

210

215

220

225

230

1 9 8 5

1 9 8 6

1 9 8 7

1 9 8 8

1 9 8 9

1 9 9 0

1 9 9 1

1 9 9 2

1 9 9 3

1 9 9 4

1 9 9 5

1 9 9 6

1 9 9 7

1 9 9 8

1 9 9 9

2 0 0 0

2 0 0 1

2 0 0 2

2 0 0 3

2 0 0 4

2 0 0 5

2 0 0 6

G a s o l i n e I n v e n t o r i e s ( m i l l i o n b b l s )

2

3

4

5

6

7

8

9

10

11

G u l f C o a s t R e f i n i n g M a r g i n ( $ / b b l )

Gasoline Inventor ies Gulf Coast Refining Margins

Source: Platts; Global Insights; Energy Information Administration.



In the last two years, the industry has enjoyed a period of exceptionally high margins,

due to strong demand (particularly for distillates), refinery downtime in 2005, and

speculation about supply outages — driven, in part, by stringent environmental

regulations and high worldwide capacity utilization.

One common misconception is that refining stocks generally rise through the winter

and fall in the summer. We have found no consistent performance related to

seasonality. Exhibit 54 shows the quarterly performance of the Bear StearnsRefining Index relative to the S&P 500. The first and fourth quarters of every year,

often thought of as the time to own refining stocks, are reflected with white bars, and

the second and third quarters are reflected with black bars. If refining stocks

outperformed the S&P every winter, then there should be a pattern of white bars

being positive and black bars being negative or, at least, the white bars should

consistently outperform the black bars. We do not find such a seasonal pattern.

Instead, relative performance has been more consistent with the refining cycle,

outperforming on the up-cycle and underperforming on the down-cycle.

Exhibit 54. Relative Performance of Bear Stearns Refining Index to the S&P 500

-17.0%

-7.0%

3.0%

13.0%

23.0%

33.0%

J u

n - 9

5

O c

t - 9 5

F e b

- 9 6

J u

n - 9

6

O c

t - 9 6

F e b

- 9 7

J u

n - 9 7

O c

t - 9 7

F e b

- 9 8

J u

n - 9

8

O c

t - 9 8

F e b

- 9 9

J u

n - 9

9

O c

t - 9 9

F e b

- 0 0

J u

n - 0

0

O c

t - 0 0

F e b

- 0 1

J u

n - 0 1

O c

t - 0 1

F e b

- 0 2

J u

n - 0 2

O c

t - 0 2

F e b

- 0 3

J u

n - 0

3

O c

t - 0 3

F e b

- 0 4

J u

n - 0 4

O c

t - 0 4

F e b

- 0 5

J u

n - 0

5

O c

t - 0 5

F e b

- 0 6

J u

n - 0

6

O c

t - 0 6

P e r c e n t a g e C h a n g e

Black bars: Second and third quarters.

White bars: First and fourth quarters.

Source: Bloomberg; Bear, Stearns & Co. Inc. Refining Index.

That said, since the gasoline sulfur rules took effect in 2004, we have noted a sharp

uptick in refining margins in the second quarter, which has been accompanied by

outperformance by the refining stocks. The rigorous new specs make production of

summer-grade gasoline challenging to produce — so much so that it cannot be mixed

with winter-grade blend. In preparation for production of summer-grade gasoline,refiners rid their storage tanks of winter-grade fuel to rebuild with the summer-grade

blend. This causes inventories to decline to low levels in the spring, raising supply

concerns. Gasoline prices have risen sharply in the spring to reflect those concerns.

NO SEASONAL TRADE

IN R EFINING STOCKS




Refiners can grow in three ways: 1) build a new refinery, 2) acquire a new refinery,

and 3) expand or add new units to existing refineries.

The Garyville, Louisiana, refinery (255,000 b/d), built in 1976, was the last refinery

built in the United States. New refinery construction has not been undertaken owing

to years of poor margins and overcapacity, the high cost of building, long

construction lead times, and the difficulties in obtaining permits. Refiners also have

been reluctant to build new units because of concerns about obsolescence, given therapid changes in product specifications and the unpredictability of these changes. A

project to build a state-of-the-art, complex refinery in Arizona is under way. Plans

are for this 150,000 b/d refinery to process 100% heavy crude oil, and costs are

estimated at $2.6 billion ($17,300 per barrel of daily refining capacity). It is still in

the permitting phase, and major financing has not been obtained. Completion of this

refinery is scheduled for 2011. It remains to be seen whether this project will be

successful.

It has been cheaper to buy refineries than to build them. This was true even in 2004-

06, when transaction prices rose sharply to reflect exceptionally high refining

margins. Exhibit 55 shows refinery purchases over the last five years. Purchase price per barrel of daily refining capacity varies widely for each transaction for two

reasons. First, purchase prices for refineries, in general, have risen with robust

refining margins. Second, purchase prices reflect the sophistication of the plant.

Refineries that produce more gasoline or have heavy crude oil processing capabilities

are more valuable because they generate more profit. For example, West Coast

refineries are more profitable because they are configured so that they produce a

disproportionate amount of gasoline relative to refineries in the rest of the country.

R EFINERY

ACQUISITIONS ARE

PART OF MOST

R EFINERS’ GROWTH

STRATEGY



Exhibit 55. Recent Refinery Purchases

Date Acquirer Seller

Transaction

Value ($mm)

Refining

Capacity (b/d)

Implied Value

per Bbl of

Capacity

($/bbl)

2/1/2007 Petroplus BP: Coryton, UK $1,400 172,000 $8,140

1/30/2007 Tesoro Royal Dutch Shell: Wilmington, CA $1,900 100,000 $13,500

8/28/2006 Western Refining Giant Industries $1,400 98,700 $14,1848/1/2006 Lyondell Citgo $2,100 110,550 $18,99611/25/2005 ConocoPhillips Louis Dreyfus Energy: Wilhelmshaven, Germany $1,200 275,000 $4,364

9/12/2005 Royal Dutch Shell Government of Turkey $4,140 282,000 $14,6814/28/2005 Marathon Oil Ashland $3,748 360,240 $10,404

4/25/2005 Valero Premcor $8,000 790,000 $10,1272/4/2004 Valero El Paso: Aruba refinery $615 245,000 $2,5101/15/2004 Premcor Motiva Enterprises: Delaware City, DE $800 180,000 $4,444

6/27/2003 Valero Orion refining corp: LA $530 185,000 $2,8656/3/2003 Valero Norco: New Orleans, LA $705 155,000 $4,548

4/30/2003 Sunoco El Paso: Eagle Point, NJ $246 150,000 $1,6403/1/2003 Premcor William Cos: Memphis, TN $315 190,000 $1,6586/3/2002 Holly BP: Wood Cross, Utah $25 25,000 $1,000

2/12/2002 Giant BP: Yorktown, VA $128 62,000 $2,0652/5/2002 Tesoro Valero: Golden Eagle, CA $1,008 168,000 $6,000

6/2/2001 Tesoro BP: Mandan & Salt Lake $664 110,000 $6,036

6/1/2001 Valero El Paso: Corpus Christi, TX $294 115,000 $2,5575/1/2001 Valero UDS $6,100 850,000 $7,1767/31/2000 Tosco Irish National Petroleum $100 75,000 $1,333

6/23/2000 UDS Avon Refinery $800 130,000 $6,1546/22/2000 Tosco Alliance - Belle Chasse $660 250,000 $2,6406/1/2000 Tosco Wood River, IL. $420 295,000 $1,424

5/1/2000 Valero Benecia, CA $895 160,000 $5,59411/1/1999 Frontier El Dorado $170 110,000 $1,545

High $8,000 $18,996

Mean $1,444 $5,207Median $705 $4,364

Low $25 $1,000 Source: Company reports.

Refiners also look to grow organically through adding new units within the refinery

gate or by expanding existing facilities. They can increase overall throughput by

expanding crude units; they can produce higher-valued products such as gasoline by

adding hydrocrackers; or they can run lower-quality crudes by adding cokers or

hydrotreaters. Sometimes capacity can be increased simply by improving

efficiencies, such as replacing pipelines inside a refinery complex with larger-

diameter pipes. The cost of expansion varies widely depending on the refinery

configurations and what projects are undertaken. In general, capacity expansions, or

heavy conversion projects, can cost $10,000-$20,000 per barrel of daily refining

capacity.

In Modeling the Earnings for Independent Refiners, How Do You Derive

the Realized Margin Assumption from the Proxy Margin?

Refiners’ actual realized margins relative to proxy margins will vary depending on

the configuration and location of the refineries, changes in the product yield, changes

in the light/heavy spreads, transportations costs, and other logistical considerations.

In modeling a company’s earnings, the first thing to do is select the appropriate

proxy, which is determined by geographic location, product mix, and feedstock slate.

Product prices and feedstock costs can vary by region, so build a proxy based on

POINTERS AND R ULES

OF THUMB




prices in that refinery’s geographic region. Next, configure the proxy so that it

resembles the refinery’s product mix. A widely used proxy is the 3-2-1 crack, which

calculates a margin based on a refined product yield of two parts (67%) gasoline and

one part (33%) distillate. A less-sophisticated refinery on the Gulf Coast may only

produce one part (50% gasoline) and one part (50%) distillate. In this case, the

appropriate proxy would be the Gulf Coast 2-1-1 crack. The most widely used proxy

feedstock is WTI. By using WTI, you get a simple refining margin. If the refinery is

sophisticated, you can alter your margin assumption based on the price spread between WTI and the refinery’s feedstock slate. Few refineries process 100% of one

low-quality crude — a mix is brought in, either to optimize the plant’s hardware

and/or based on availability.

Based on the proxy margin, circumstances unique to the refinery can be taken into

account. For instance, if the refinery is down for maintenance, or if a unit goes

down, margin realizations will decline relative to the proxy. If the refinery is far

from a crude hub, additional transportation costs will need to be added. The proxy is

really just a starting point.

An approximate shortcut to all of these adjustments is to select the appropriate proxymargin and calculate the change in the proxy. Oftentimes, the change in the proxy

margin will correlate to changes in the refiner’s realized margins. For example, if the

Gulf Coast 3-2-1 increases by 10%, then a refinery’s realized margin that resembles a

3-2-1 product mix may increase roughly 10%. A Gulf Coast 3-2-1 is quoted on

Bloomberg (see the Appendix for the ticker symbol).

How to Model a Refinery

Basically, modeling a refinery is volume, margin, and costs. Most independent

refiners provide all the data. Below is a sample of a year of operations at Valero

Corp.

Using the 295,000 b/d Port Arthur refinery as an example, the key drivers of

profitability are refining throughput (measured in thousands of barrels per day), gross

refining margin (usually modeled in $/bbl), and operating expenses (cost of labor,

natural gas used to fire the plant, etc.). Operating expenses can be modeled on either

a per-barrel basis, or a gross basis. Both are provided for clarity in the example

below.



Assumptions:

Average annual throughput: 295,000 b/d.

Realized gross refining margin: $13.25/bbl (average for year)

Operating expenses: $4.10/bbl

Calculations:

Annual Gross Margin: (295,000 b/d x $13.25/bbl x 365 days) = $1.4 billion

Annual operating expenses: (295,000 x $4.10/bbl x 365 days) = $441.5 million

Operating Income (pretax): ($1.430 billion - $441.5 million) = $988.5 million

Refining margins tend to vary by season, and, consequently, earnings are typically

stronger during the summer months, when higher-valued gasoline is in the greatest

demand. For a full year, the model might look like the example below, which shows

actual refining margins realized by Valero in 2006, on the Gulf Coast.1 Note thatoperating costs include DD&A expense. Some refiners report cash operating costs

and DD&A expense separately.

Exhibit 56. Sample Operating Model

1Q 2Q 3Q 4Q Full Year

Throughput (000 b/d) 295 295 295 295 295

Gross refining margin / bbl $11.50 $16.00 $14.00 $11.60 $13.25

Operating expense ($ millions) 110.4 110.4 110.4 110.4 441.5

Operating cost per bbl $4.16 $4.11 $4.07 $4.07 $4.10

Operating income ($ millions) $195.0 $319.1 $269.6 $204.4 $988.1


What Refining Margin Is Reflected in an Individual Company’sConsensus Earnings Estimate?

We can approximate the refining margin reflected in consensus earnings using the

company’s sensitivity to a $1.00/bbl change in the refining margin, and our earnings

per share estimate based on our margin assumptions.

For example, what refining margin is reflected in Valero’s stock price? We estimate

that every $1.00/bbl change in the refining margin changes Valero’s earnings by

$1.36 per share (see methodology for this calculation on page 54). Our EPS estimate

for 2007, based on our estimate for a consolidated refining margin for the company

of $9.25/bbl, is $6.10 per share. Consensus is $7.17 per share. The difference is

$1.07 per share, implying a difference of $0.79/bbl in the refining margin assumption

1 Some numbers have been rounded.




Section 3




Valuation

Traditionally, investors value oil and independent refining stocks on “mid-cycle”

prices and refining margins. This approach makes sense, given the high volatility in

oil and gas prices and refining margins. In our opinion, there is no single valuation

measure that is right for oil and independent refining stocks. We see values being

determined by a series of factors, which take on increasing or decreasing importance

at various times. In theory, the market discounts each company’s expected cash

flows (DCF). Generally, we find that all valuation parameters are related to DCF.

For example, price to earnings (P/E) and price to cash flow (P/CF) are shortcuts to

approximate DCF values. Enterprise-value-to-EBITDA (EV/EBITDA) multiples,

which have become widely used in recent years, attempt to take into account balance

sheet strength or weakness by including debt as part of the valuation. Appraised

value estimates, another DCF exercise, attempts to mark assets and liabilities to

market. This can be useful in identifying potential takeover situations.

We believe history is a good guide for determining multiples that are applicable to

individual stocks, although market conditions may influence valuation parameters at

any given time. For instance, multiples are typically compressed in a highcommodity price environment, and vice versa. However, average multiples over a

ten-year period may be a good bellwether for mid-cycle. Alternatively, an investor

may look at years in which macro conditions were consistent with current conditions

for insight on valuation during periods of high or low commodity prices. Exhibit 57

below, which shows Exxon Mobil’s trading history, illustrates these points. Our

2007 and 2008 estimates are based on $60/bbl and $50/bbl for WTI, respectively.

Note that our projected trading range reflects multiples that are below the 12-year

average in 2007, but consistent with mid-cycle in 2008. In 2008, our price

projections reflect multiples that are consistent with a declining price environment.

Note the multiple expansion that occurred in 1998 and in 2001. Exxon Mobil fares

well in a falling price environment, in part, because it is viewed as one of the“quality” companies, a good investment in a declining commodity price environment.

We should note that historically, we have viewed mid-cycle as roughly $22/bbl for

WTI. Given the changes that have occurred in the industry in the past two years, we

believe that mid-cycle, at least for the intermediate term, is closer to $50/bbl. Hence,

our stock price projections are consistent with historical mid-cycle. Our projections,

however, are somewhat less certain as we do not have the history behind us.



Exhibit 57. Exxon Mobil Trading Range

Average STOCK PRICE DIV YLD

WTI ($/bbl) Year Low High EPS CFPS DIV EBITDA P/E Range P/CF Range EV/EBITDA Range

18.43 1995 15 22 1.28 2.79 0.75 3.27 11.8x 16.9x 5.4x 7.7x 5.2x 7.1x 3.5 5.0

22.14 1996 19 25 1.40 2.86 0.78 3.56 13.9x 18.1x 6.8x 8.9x 5.8x 7.5x 3.1 4.0

20.71 1997 24 34 1.62 3.07 0.82 3.81 14.9x 20.8x 7.9x 11.0x 6.7x 9.2x 2.4 3.4

14.48 1998 28 39 1.24 2.38 0.82 3.01 22.8x 31.2x 11.9x 16.2x 9.9x 13.3x 2.1 2.9

19.15 1999 32 44 1.19 2.16 0.84 2.96 27.0x 36.7x 14.9x 20.2x 11.6x 15.5x 1.9 2.6

30.36 2000 35 48 2.40 3.25 0.88 5.30 14.6x 19.9x 10.8x 14.7x 6.7x 9.1x 1.8 2.5

25.94 2001 35 46 2.25 3.55 0.91 4.71 15.6x 20.4x 9.9x 12.9x 7.5x 9.8x 2.0 2.6

26.02 2002 30 45 1.69 3.06 0.92 3.92 17.6x 26.4x 9.7x 14.6x 7.6x 11.4x 2.1 3.131.06 2003 32 41 2.55 4.31 0.98 5.59 12.4x 16.1x 7.3x 9.5x 5.6x 7.3x 2.4 3.1

41.25 2004 40 52 3.97 5.35 1.06 8.00 10.1x 13.1x 7.5x 9.7x 4.7x 6.3x 2.0 2.7

56.25 2005 49 66 5.36 7.03 1.14 10.74 9.2x 12.3x 7.0x 9.4x 4.3x 5.8x 1.7 2.3

66.03 2006 57 79 6.55 8.30 1.28 13.26 8.6x 12.1x 6.8x 9.5x 4.0x 5.7x 1.6 2.3

1995-2006 Average 13.8x 18.8x 8.3x 11.3x 6.2x 8.4x 2.3 % 3.1 %

Projected

60.00 2007E $64 $85 $6.05 $8.00 $1.37 $13.04 10.6 x 14.0 x 8.0 x 10.6 4.7 x 6.0 x 1.6 % 2.1 %

50.00 2008E $64 $85 $4.90 $6.95 $1.47 $10.85 13.1 x 17.3 x 9.2 x 12.2 5.6 x 7.5 x 1.7 % 2.3 %

Trading Range


Another issue with our method is that it requires estimation. Ultimately, this means

projecting oil and gas prices and refining margins, which has proved to be a difficult

call for all analysts. Hence, earnings and cash flow estimates often are inaccurate.For the large integrated oils, we find that dividend yields often put a floor on where a

stock will trade. Dividend yield analysis requires less speculation. However,

dividends are visible, real, and usually relatively secure (integrated oils rarely cut

dividends).

Another driving force for valuation is return on capital employed (ROCE), which

differentiates companies in terms of efficiency and investment discipline. If we can

identify companies with improving ROCE, then we might make a case for upward

revaluation of the share price through a higher P/E, P/CF, or EV/EBITDA multiple.

This is helpful in setting price expectations, based on multiples we would expect to

see. We calculate ROCE as follows:

ROCE = Net Income + After-Tax Interest

Shareholders’ Equity + Total Debt

A good example of this is TOTAL. Since 1995, the company’s return on average

capital employed has grown consistently. TOTAL has gone from being not so

competitive to a top-quartile performer. This was accomplished through value-

creating growth, both organic and through acquisitions. While the multiples have

expanded and contracted with the cycles, note the relative multiples to its closest

competitor, Chevron, shown in Exhibit 58. In the 1995-99 time period, Chevron

generated average returns that were more than 400 basis points above TOTAL’s. Inthe last three years, returns for the two companies have been consistent, at

approximately 25%. In 1995-99, TOTAL’s multiples reflected an average 7%

discount to Chevron’s. Over the past three years, TOTAL has traded at an average

8% premium to Chevron. TOTAL’s stock price rose 323% from December 1994

through December 2006. This compares to 154% for Chevron.




Exhibit 58. TOTAL and Chevron: ROCE and Trading Range

TOTAL ChevronYear ROACE

1995 17.0x 22.7x 6.2x 8.2x 4.7x 6.3x 5.3 %

1996 15.1x 20.2x 6.5x 8.7x 5.0x 6.7x 6.8

1997 14.6x 22.3x 7.0x 10.7x 5.6x 8.5x 8.8

1998 19.6x 28.2x 8.8x 12.6x 7.7x 10.8x 8.3

1999 19.6x 28.5x 9.3x 13.6x 6.5x 9.3x 14.1

2000 12.3x 16.3x 6.9x 9.2x 4.8x 6.4x 18.0

2001 11.9x 16.0x 7.5x 10.0x 5.0x 6.6x 17.0

2002 13.6x 18.7x 7.7x 10.6x 5.0x 6.8x 15.0

2003 9.3x 14.3x 5.7x 8.7x 3.9x 5.9x 19.8

2004 9.6x 12.0x 5.9x 7.4x 3.8x 4.7x 22.8

2005 8.2x 10.9x 5.3x 7.0x 3.4x 4.5x 24.9

2006 8.5x 10.7x 6.5x 8.1x 3.7x 4.6x 25.6

12.7x 17.5x 6.7x 9.2x 4.8x 6.5x 15.7 %

P/E Range P/CF Range EV/EBITDA Year P/E Range P/CF Range EV/EBITDA ROACE

1995 14.3x 17.7x 7.0x 8.7x 6.1x 7.3x 11.9 %

1996 12.6x 16.9x 6.3x 8.4x 5.2x 6.7x 14.6

1997 12.8x 18.4x 7.9x 11.4x 5.6x 7.8x 15.9

1998 22.9x 30.5x 9.8x 13.1x 9.6x 12.5x 10.3

1999 21.4x 33.4x 12.5x 19.5x 7.6x 11.3x 11.2

2000 8.6x 11.7x 5.8x 7.8x 4.0x 5.3x 22.8

2001 12.3x 15.5x 7.8x 9.7x 5.0x 6.1x 15.9

2002 15.7x 21.6x 7.4x 10.2x 6.2x 8.2x 10.5

2003 8.7x 12.4x 5.4x 7.7x 3.9x 5.4x 16.0

2004 7.5x 10.0x 6.2x 8.3x 3.6x 4.8x 23.0

2005 7.7x 10.0x 5.4x 7.0x 3.5x 4.6x 21.8

2006 6.9x 9.8x 4.9x 6.9x 2.9x 4.2x 30.6

11.8x 15.9x 6.7x 9.0x 5.1x 6.6x 17.6 %


The trick is to determine what valuation factor(s) is likely to affect each stock. It is

essential to examine the rationale for why a stock trades at a certain level, which

parameters will provide a downside cushion, and which may set a ceiling price. We

like to project stock price ranges, based on historical multiples, price to appraised

value (AV), and dividend yield, for all the companies that we cover. This leads to an

examination of factors that might create a bottom and a top for the stock. We

compare valuation statistics for each company against “look-alikes,” and make

adjustments, if necessary. Also, we compare historical stock volatility with our

projected ranges, and, if necessary, make further adjustments. Projecting stock price

ranges allows us to estimate risk/reward ratios.

The international integrated oils trade at premiums of 8%-86% versus the domestics,

and 42%-86% versus the refiners, based on historical P/E and P/CF multiples. We

believe the reasons for the higher valuations include operational efficiency, financial

strength, reputation, diversification, and liquidity. As a group, the internationals have

better reserve replacement and F&D cost records than the domestics. Importantly,

ROCE is consistently higher for the internationals than the domestics and refiners.

ROCE plays a major role in determining valuations, in our opinion.

THE SIZE FACTOR :

DOES IT MATTER ?



Exhibit 59. Multiple Ranges and ROCE

Ten-Year P/E and P/CF Ranges ROCE

——————— Ten - Year Ranges (1) ————————— P/E —— —— P/CF —— — EV/EBITDA —

Low High Low High Low High

International IntegratedBP (BP) 14.9x 20.8x 8.5x 11.8x 6.4x 8.7xChevron (CVX) 13.5 18.1 7.2 9.6 5.7 7.4Exxon Mobil (XOM) 15.4 21.2 8.7 11.9 6.9 9.3Royal Dutch Shell (RDS.A) 15.0 21.4 8.5 12.1 5.5 7.7

TOTAL S.A. (TOT) 14.2 19.8 7.0 9.8 5.2 7.3Average 14.6x 20.3x 8.0x 11.0x 5.9x 8.1x

Domestic IntegratedConocoPhillips (COP) 11.8x 16.5x 4.5x 6.4x 4.9x 6.2xHess Corporation (HES) 11.2 15.6 4.4 6.1 5.0 6.3Marathon Oil (MRO) 11.6 17.2 3.3 5.0 4.2 5.6Murphy Oil (MUR) 22.6 32.7 4.5 6.9 5.1 7.4

Occidental Petroleum (OXY) 9.9 14.7 4.6 7.1 4.9 6.4

Average 13.4x 19.3x 4.3x 6.3x 4.8x 6.4x

Ten-Year Average ROCE

International Integrated Oils 16.8%Domestic Integrated Oils 13.7%Independent Refiners 13.7%


We note, however, that size does not equate to good performance or returns. Take

super-major Royal Dutch/Shell, for instance, the third-largest company in our

coverage universe, whose F&D costs have recently ranked among the highest among

the major oils, and whose returns lag the group’s. Size did not help other companies

such as Texaco, Amoco, Gulf Oil, and Getty Oil, all of which where acquired bycompetitors, due in part to substandard operations and returns.

Independent refiners are valued similarly to the integrated oils. The only difference

that we have observed is that, due to the high sensitivity of refiners’ earnings to

changes in margins, there is a close correlation between changes in refining margins

and refiners’ stock prices. Given the cyclicality of the refining industry, we believe

that the best approach for investors is to use a trading strategy.

Exhibit 60. Correlation Between Refining Stock Prices and Refining Margins

0

2

4

6

8

10

1214

1 9 9 5

1 9 9 6

1 9 9 7

1 9 9 8

1 9 9 9

2 0 0 0

2 0 0 1

2 0 0 2

2 0 0 3

2 0 0 4

2 0 0 5

2 0 0 6

2 0 0 7

E

R e f i n i n g M a r g i n $ / b b l

0

0.5

1

1.5

2

2.5

3

3.54

R e l a t i v e P e r f o r m a n c e

Nationwide Refining MarginsBSC Refining Index Relative Performance to the S&P


VALUATION FOR

INDEPENDENT

R EFINERS




In valuing independent refiners, we prefer EV/EBITDA multiples over P/E or P/CF

multiples because EV/EBITDA takes into account balance sheet strength or

weakness by including debt as part of the valuation. Given that refineries are so

capital-intensive, independent refiners’ debt loads can vary and should be taken into

consideration. In addition, due to volatile and sometimes negative earnings and cash

flows from year to year for independent refiners, P/E and P/CF multiples are erratic,

and, as a result, it is difficult to rely on historical ranges.

Exhibit 61 below shows Valero’s trading history. Our 2008 earnings estimates are

based on approximately mid-cycle refining margins. As discussed earlier, generally,

in periods where refining margins are above mid-cycle, the multiples contract, and,

consequently, in periods where the margins are below mid-cycle, the multiples

expand. Note that in 2001 and in 2004-06, periods of robust refining margins,

multiples were below the ten-year average. In contrast, the very weak margins seen

in 1998 and 2002 caused multiples to expand to very high levels. Our 2007 projected

price ranges reflect multiples that are consistent with a declining refining margin

environment, and 2008 multiples look to be more consistent with the historical mid-

cycle, as our 2008 margin assumptions are approximately mid-cycle.

Exhibit 61. Historical Multiples for Valero Energy

PRICE DIV YLD

Year Low High EPS CFPS DIV EBITDA P/E Range P/CF Range EV/EBITDA ROCE Range

1995 8 10 0.45 1.75 0.26 3.55 17.9 22.6 4.6 5.8 5.3 6.0 4.8 2.6 3.2

1996 10 15 (0.30) 1.27 0.26 1.86 NM NM 8.0 11.9 10.0 12.6 1.4 1.7 2.6

1997 13 22 1.02 2.08 0.21 2.82 13.3 21.2 6.5 10.4 5.5 8.4 6.6 1.0 1.6

1998 9 18 0.56 1.88 0.16 2.18 15.7 32.6 4.7 9.7 7.0 9.3 4.8 0.9 1.8

1999 8 13 0.07 1.23 0.16 2.04 8.6 17.7 6.8 10.3 7.0 9.1 2.7 1.3 1.9

2000 9 19 2.80 4.30 0.16 6.51 3.4 6.9 2.2 4.5 2.7 4.2 17.0 0.8 1.7

2001 16 26 4.37 8.33 0.16 9.59 3.7 5.9 2.0 3.1 4.7 5.7 10.8 0.6 1.0

2002 12 25 0.42 2.18 0.20 4.02 28.8 59.6 5.5 11.3 7.3 10.5 4.6 0.8 1.7

2003 17 23 2.57 5.43 0.20 7.25 6.4 9.1 3.1 4.3 4.5 5.4 8.2 0.9 1.2

2004 23 48 6.66 9.99 0.27 13.20 3.5 7.2 2.3 4.8 2.6 4.4 18.2 0.6 1.2

2005 50 69 6.68 6.00 0.10 11.56 7.4 10.3 8.3 11.5 4.9 6.6 25.5 0.1 0.22006 48 69 8.31 11.00 0.10 15.05 5.8 8.3 4.4 6.3 3.6 5.0 25.2 0.1 0.2

1995-2006 Average: 8.1 x 14.2 x 4.9 x 7.8 x 5.0 x 6.9 x 10.8 % 0.9 % 1.5 %

2007E $45 $70 $6.10 $8.80 $0.12 $11.55 7.4 x 11.5 x 5.1 x 8.0 x 4.7 x 6.4 x 16.1 % 0.2 % 0.3 %2008E $38 $65 $4.50 $7.50 $0.12 $9.52 8.4 x 14.4 x 5.1 x 8.7 x 4.8 x 7.4 x 11.1 % 0.2 % 0.3 % Source: Company reports; Bear, Stearns & Co. Inc. estimates.

For the past ten years, valuation multiples for the independent refining companies

that we cover have been 8.0x-14.2x P/E, 4.4x-7.6x P/CF, and 5.3x-7.2x EV/EBITDA

(see Exhibit 62).



Exhibit 62. Historical Multiples by Company

Low High Low High Low High

Frontier Oil Corp (FTO) 8.3x 15.4x 5.2x 9.5x 5.2x 6.9x

Sunoco (SUN) 8.7x 13.6x 5.1x 8.3x 6.8x 9.3x

Tesoro Corp. (TSO) 6.7x 13.4x 2.5x 4.6x 4.0x 5.6x

Valero Energy Corp. (VLO) 8.4x 14.2x 4.9x 7.8x 5.0x 6.9x

Average 8.0x 14.2x 4.4x 7.6x 5.3x 7.2x

(1) Range represents averages of low multiples and high multiples in each year based on high and low stock price.

——————— Historical Ranges(1)

———————

— EV/EBITDA ——— P/CF ———— P/E ——

Source: Company reports; Bear, Stearns & Co. Inc. calculations.

As discussed earlier, ROCE analysis is a way to differentiate companies in terms of

efficiency and investment discipline. Because refineries are so capital-intensive,

return on capital employed has historically been relatively low. However, during the

past four years, abnormally high refining margins have allowed refiners to use

substantial cash flows to pay down debt, thereby increasing their ROCEs. Exhibit 63

shows historical ROCEs for the independent refiners.

Exhibit 63. Return on Capital Employed

FTO SUN TSO VLO WNR Average

2000 16.6% 19.1% 9.2% 17.0% NA 15.5%

2001 44.7% 16.3% 8.6% 10.8% NA 20.1%

2002 -0.4% 1.7% -0.2% 4.6% 35.0% 8.1%

2003 12.0% 13.9% 8.5% 8.2% 23.9% 13.3%

2004 21.3% 23.2% 17.2% 18.2% 24.5% 20.9%2005 49.7% 31.6% 24.4% 25.5% 45.5% 35.3%

2006 50.6% 28.1% 26.2% 25.2% 35.8% 33.2% Source: Company reports; Bear, Stearns & Co. Inc. calculations.




Section 4




Industry Resources

Platts Oilgram News (daily)

Telephone: 212-904-4100

Platts Oilgram Price (daily)

Telephone: 212-904-4100

Oil Daily (daily)

Telephone: 202-662-0700

Petroleum Intelligence Weekly (weekly)

Telephone: 202-662-0700

Natural Gas Week (weekly)

Telephone: 202-662-0700

Middle East Economics Survey (weekly)

Telephone: 357 2 266 54 31

Monthly Statistical Report — API (monthly)

Telephone: 202-682-8000

Monthly Energy Review — DOE (monthly)

Telephone: 202-586-8800

Oil & Gas Journal (monthly)

Telephone: 713-621-9720

Oil & Gas Investor (monthly)Telephone: 713-993-9325

Oil Market Report (IEA monthly)

Telephone: 33 (0) 1 40-576557

PUBLICATIONS



The Prize, by Daniel Yergin, Simon & Schuster, 1991

Our Industry, by British Petroleum Company, 1977

Fundamentals of Oil and Gas Accounting , by Rebecca Gallun, Charlotte

Wright, Linda Nichols, John Stevenson, PennWell, 2001

Hubbert’s Peak , by Kenneth Deffeyes, Princeton University Press, 2001

The Hydrogen Economy, by Jeremy Rifkin, Tarcher/Penguin, 2002

International Petroleum Encyclopedia, by Bob Rippee, PennWell, 2004

BOOKS




The following Web sites provide industry data:

www.eia.doe.gov — Department of Energy’s statistical site.

www.api.org — American Petroleum Institute’s site. Click on industry

statistics for industry data.

www.iea.org — International Energy Agency’s site.

www.opec.org — OPEC Web site.

www.mms.gov — Minerals Management Service (U.S. Dept. of Interior).

The following Web sites provide information relating to issues relevant to the U.S.

refining industry:

www.epa.gov — Environmental Protection Agency; Clean Air Act.

www.npra.org — National Petrochemicals and Refiners Association.

WEB SITES



We use pricing data from Platt’s to calculate proxy reefing margins. Bloomberg also

provides margins by region.

Below are ticker symbols for some of the most widely followed refining margins:

PADD 1 (East Coast): CRKS321Y (Index)

PADD 2 (Midwest): CRCK321M (Index)

PADD 3 (Gulf Coast): CRKS321W (Index)

PADD 5 (West Coast): CRKS431A (Index)

Asia-Dubai Crack Spread: CRKS321U (Index)

Northwest Europe-Dated Brent: CRKS211B (Index)

Crude Oil:

WTI spot: USCRWTIC (Commodity)

Dated Brent: EUCRBRDT (Commodity)

Bloomberg Energy Page:

NRG (Go)

BLOOMBERG TICKER

SYMBOLS




N/PET — Petroleum News

I/OPEC — OPEC News

I/MEAST — Middle East News

R/IR — Iran News

R/IZ — Iraq News

R/KU — Kuwait News

R/SA — Saudi Arabia News

R/TC — United Arab Emirates News

R/VE — Venezuela News

R EUTERS NEWS

SYMBOLS



Consensus oil and gas prices estimates are listed on First Call:

Oil (WTI spot): OIL.CP

Gas (Composite Spot Wellhead): NG.CP

Oil & Gas Journal Worldwide Construction Update (Annual)

Oil & Gas Journal Worldwide Refining Survey (Annual)

CONSENSUS OIL AND

GAS PRICE ESTIMATES

ON FIRST CALL

SURVEYS




Glossary of Terms

The following are terms contained in the Department of Energy’s glossary:

Alkylation: A refining process for chemically combining isobutane with olefin hydrocarbons (e.g.,

propylene, butylene) through the control of temperature and pressure in the presence of an acid catalyst,

usually sulfuric acid or hydrofluoric acid. The product, alkylate, an isoparaffin, has high-octane value and is

blended with motor and aviation gasoline to improve the antiknock value of the fuel.

API gravity: American Petroleum Institute measure of specific gravity of crude oil or condensate in degrees.

An arbitrary scale expressing the gravity or density of liquid petroleum products. The measuring scale is

calibrated in terms of degrees API; it is calculated as follows: Degrees API = (141.5 / sp.gr.60 deg.F/60

deg.F) - 131.5

Barrel: A unit of volume equal to 42 U.S. gallons.

Bitumen: A naturally occurring viscous mixture, mainly of hydrocarbons heavier than pentane, that may

contain sulfur compounds and that, in its naturally occurring viscous state, is not recoverable at a commercial

rate through a well.

BOE: The abbreviation for barrels of oil equivalent (used internationally).

Butane: A normally gaseous straight-chain or branch-chain hydrocarbon extracted from natural gas or

refinery gas streams.

Christmas Tree: The valves and fittings installed at the top of a gas or oil well to control and direct the flow

of well fluids.

Coking: Thermal refining processes used to produce fuel gas, gasoline blendstocks, distillates, and petroleum

coke from the heavier products of atmospheric and vacuum distillation.

Cubic Foot (cf), Natural Gas: The amount of natural gas contained at standard temperature and pressure (60

degrees Fahrenheit and 14.73 pounds standard per square inch) in a cube whose edges are one foot long.

Dealer Tank Wagon (DTW) Sales: Wholesale sales of gasoline priced on a delivered basis to a retail outlet.

Desulfurization: The removal of sulfur, as from molten metals, petroleum oil, or flue gases.

Development Costs: Costs incurred to obtain access to proved reserves and to provide facilities for

extracting, treating, gathering, and storing the oil and gas.

Development Drilling: Drilling done to determine more precisely the size, grade, and configuration of an ore

deposit subsequent to when the determination is made that the deposit can be commercially developed.

Development Well: A well drilled within the proved area of an oil or gas reservoir to the depth of a

stratigraphic horizon known to be productive.



Diesel Fuel: A fuel composed of distillates obtained in petroleum refining operation or blends of such

distillates with residual oil used in motor vehicles. The boiling point and specific gravity are higher for diesel

fuels than for gasoline.

Distillate Fuel Oil: A general classification for one of the petroleum fractions produced in conventional

distillation operations. It includes diesel fuels and fuel oils. Products known as No. 1, No. 2, and No. 4 diesel

fuel are used in on-highway diesel engines, such as those in trucks and automobiles, as well as off-highway

engines, such as those in railroad locomotives and agricultural machinery. Products known as No. 1, No. 2,and No. 4 fuel oils are used primarily for space heating and electric power generation.

Distillation Unit (Atmospheric): The primary distillation unit that processes crude oil (including mixtures of

other hydrocarbons) at approximately atmospheric conditions. It includes a pipe still for vaporizing the crude

oil and a fractionation tower for separating the vaporized hydrocarbon components in the crude oil into

fractions with different boiling ranges. This is done by continuously vaporizing and condensing the

components to separate higher boiling point material. The selected boiling ranges are set by the processing

scheme, the properties of the crude oil, and the product specifications.

DOE: Department of Energy.

Dry Hole: An exploratory or development well found to be incapable of producing either oil or gas in

sufficient quantities to justify completion as an oil or gas well.

EIA: The Energy Information Administration. An independent agency within the U.S. Department of Energy

that develops surveys, collects energy data, and analyzes and models energy issues. The Agency must meet

the requests of Congress, other elements within the Department of Energy, Federal Energy Regulatory

Commission, the Executive Branch, its own independent needs, and assist the general public, or other interest

groups, without taking a policy position.

Fluid Catalytic Cracking: The refining process of breaking down the larger, heavier, and more complex

hydrocarbon molecules into simpler and lighter molecules. Catalytic cracking is accomplished by the use of acatalytic agent and is an effective process for increasing the yield of gasoline from crude oil. Catalytic

cracking processes fresh feeds and recycled feeds.

Field: An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same

individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in

a field that are separated vertically by intervening impervious strata or laterally by local geologic barriers, or

by both.

Gasoline: A complex mixture of relatively volatile hydrocarbons with or without small quantities of

additives, blended to form a fuel suitable for use in spark-ignition engines. Motor gasoline, as defined in

ASTM Specification D 4814 or Federal Specification VV-G-1690C, is characterized as having a boiling rangeof 122-158 degrees Fahrenheit at the 10% recovery point to 365-374 degrees Fahrenheit at the 90% recovery

point. Motor gasoline includes conventional gasoline, all types of oxygenated gasoline, including gasohol,

and reformulated gasoline, but excludes aviation gasoline.

Geological and Geophysical (G&G) Costs: Costs incurred in making geological and geophysical studies,

including, but not limited to, costs incurred for salaries, equipment, obtaining rights of access, and supplies

for scouts, geologists, and geophysical crews.




Government-Owned Stocks: Oil stocks owned by the national government and held for national security. In

the U.S., these stocks are known as the Strategic Petroleum Reserve.

Jet Fuel: A refined petroleum product used in jet aircraft engines. It includes kerosene-type jet fuel and

naphtha-type jet fuel.

Heating Oil: A distillate fuel oil that has distillation temperatures of 400 degrees Fahrenheit at the 10%

recovery point and 640 degrees Fahrenheit at the 90% recovery point. It is used in atomizing-type burners for domestic heating, or for moderate capacity commercial/industrial burner units.

Hydrocracking: A refining process that uses hydrogen and catalysts with relatively low temperatures and

high pressures for converting middle boiling or residual material to high-octane gasoline, reformer charge

stock, jet fuel, and/or high-grade fuel oil. The process uses one or more catalysts, depending on product

output, and can handle high-sulfur feedstocks without prior desulfurization.

Hydrotreating: A refining process for treating petroleum fractions from atmospheric or vacuum distillation

units (e.g., naphthas, middle distillates, reformer feeds, residual fuel oil, and heavy gas oil) and other

petroleum (e.g., cat-cracked naphtha, coker naphtha, gas oil, etc.) in the presence of catalysts and substantial

quantities of hydrogen. Hydrotreating includes desulfurization, removal of substances (e.g., nitrogencompounds) that deactivate catalysts, conversion of olefins to paraffins to reduce gum formation in gasoline,

and other processes to upgrade the quality of the fractions.

Isomerization: A refining process that alters the fundamental arrangement of atoms in the molecule without

adding or removing anything from the original material. Used to convert normal butane into isobutane (C4),

an alkylation process feedstock, and normal pentane and hexane into isopentane (C5) and isohexane (C6),

high-octane gasoline components.

MTBE (Methyl Tertiary Butyl Ether): An ether intended for gasoline blending in oxygenated gasoline.

Naphthas: Refined or partly refined light distillates with an approximate boiling point range of 27-221degrees centigrade. Blended further or mixed with other materials, they make high-grade motor gasoline or jet

fuel. Also used as solvents, petrochemical feedstocks, or as raw materials for the production of town gas.

Octane: A flammable liquid hydrocarbon found in petroleum. Used as a standard to measure of the antiknock

properties of motor fuel.

Offshore: That geographic area that lies seaward of the coastline. In general, the coastline is the line of

ordinary low water along with that portion of the coast that is in direct contact with the open sea or the line

marking the seaward limit of inland water.

Oil: A mixture of hydrocarbons usually existing in the liquid state in natural underground pools or reservoirs.Gas is often found in association with oil.

Oil Reservoir: An underground pool of liquid consisting of hydrocarbons, sulfur, oxygen, and nitrogen

trapped within a geological formation and protected from evaporation by the overlying mineral strata.

Oil Well: A well completed for the production of crude oil from at least one oil zone or reservoir.



OPEC (Organization of Petroleum Exporting Countries): The acronym for the Organization of Petroleum

Exporting Countries that have organized for the purpose of negotiating with oil companies on matters of oil

production, prices, and future concession rights. Current members (as of the date of this publication) are

Algeria, Indonesia, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, the United Arab Emirates, and

Venezuela.

Permeability: The ease with which fluid flows through a porous medium.

Petrochemicals: Organic and inorganic compounds and mixtures that include but are not limited to organic

chemicals, cyclic intermediates, plastics and resins, synthetic fibers, elastomers, organic dyes, organic

pigments, detergents, surface active agents, carbon black, and ammonia.

Petroleum: A broadly defined class of liquid hydrocarbon mixtures. Included are crude oil, lease condensate,

unfinished oils, refined products obtained from the processing of crude oil, and natural gas plant liquids. Note

that volumes of finished petroleum products include non-hydrocarbon compounds, such as additives and

detergents, after they have been blended into the products.

Petroleum Administration for Defense District (PADD): A geographic aggregation of the 50 states and the

District of Columbia into five Districts, with PADD I further split into three sub-districts.

Production Costs: Costs incurred to operate and maintain wells and related equipment and facilities,

including depreciation and applicable operating costs of support equipment and facilities and other costs of

operating and maintaining those wells and related equipment and facilities.

Propane: A normally gaseous straight-chain hydrocarbon. It is a colorless paraffinic gas that boils at a

temperature of -43.67 degrees Fahrenheit. It is extracted from natural gas or refinery gas streams.

Refined Petroleum Products: Refined petroleum products include but are not limited to gasolines, kerosene,

distillates (including No. 2 fuel oil), liquefied petroleum gas, asphalt, lubricating oils, diesel fuels, and

residual fuels.

Refiner: A firm or the part of a firm that refines products or blends and substantially changes products, or

refines liquid hydrocarbons from oil and gas field gases, or recovers liquefied petroleum gases incident to

petroleum refining, and sells those products to resellers, retailers, reseller/retailers, or ultimate consumers.

“Refiner” includes any owner of products that contracts to have those products refined and then sells the

refined products to resellers, retailers, or ultimate consumers.

Refinery: An installation that manufactures finished petroleum products from crude oil, unfinished oils,

natural gas liquids, other hydrocarbons, and oxygenates.

Refinery Capacity Utilization: Ratio of the total amount of crude oil, unfinished oils, and natural gas plantliquids run through crude oil distillation units to the operable capacity of these units.

Reserve Additions: The estimated original, recoverable, salable, and new proved reserves credited to new

fields, new reservoirs, new gas purchase contracts, amendments to old gas purchase contracts, or purchase of

reserves in-place that occurred during the year and had not been previously reported.




Reserve Revisions: Changes to prior year-end proved reserves estimates, either positive or negative, resulting

from new information other than an increase in proved acreage (extension). Revisions include increases of

proved reserves associated with the installation of improved recovery techniques or equipment. They also

include correction of prior-year arithmetical or clerical errors and adjustments to prior year-end production

volumes to the extent that these alter reserves estimates.

Residual Fuel Oil: A general classification for the heavier oils, known as No. 5 and No. 6 fuel oils, that

remain after the distillate fuel oils and lighter hydrocarbons are distilled away in refinery operations. It is

used in steam-powered vessels in government service and inshore power plants. No. 6 fuel oil includes

Bunker C fuel oil and is used for the production of electric power, space heating, vessel bunkering, and

various industrial purposes.

Royalty: A contractual arrangement providing a mineral interest that gives the owner a right to a fractional

share of production, or proceeds therefrom, that does not contain rights and obligations of operating a mineral

property, and that is normally free and clear of exploration, developmental, and operating costs, except

production taxes.

Salt Dome: A domical arch (anticline) of sedimentary rock beneath the earth’s surface in which the layers

bend downward in opposite directions from the crest and that has a mass of rock salt as its core.

Spot Price: The price for a onetime open market transaction for immediate delivery of a specific quantity of

product at a specific location where the commodity is purchased “on the spot” at current market rates.

Strategic Petroleum Reserve (SPR): Petroleum stocks maintained by the federal government for use during

periods of major supply interruption.

Sulfur: A yellowish nonmetallic element, sometimes known as “brimstone.” It is present at various levels of

concentration in many fossil fuels whose combustion releases sulfur compounds that are considered harmful

to the environment. Some of the most commonly used fossil fuels are categorized according to their sulfur

content, with lower-sulfur fuels usually selling at a higher price. Note: No. 2 distillate fuel is currently

reported as having either a 0.05% or lower sulfur level for on-highway vehicle use or a greater than 0.05%

sulfur level for off-highway use, home heating oil, and commercial and industrial uses. Residual fuel,regardless of use, is classified as having either no more than 1% sulfur or greater than 1% sulfur. Coal is also

classified as being low-sulfur at concentrations of 1% or less or high-sulfur at concentrations greater than 1%.

Wax: A solid or semisolid material derived from petroleum distillates or residues by such treatments as

chilling, precipitating with a solvent, or de-oiling. It is a light-colored, more-or-less translucent crystalline

mass, slightly greasy to the touch, consisting of a mixture of solid hydrocarbons in which the paraffin series

predominates. Includes all marketable wax, whether crude scale or fully refined. The three grades included

are microcrystalline, crystalline-fully refined, and crystalline-other. The conversion factor is 280 pounds per

42 U.S. gallons per barrel.

Well: A hole drilled in the earth for the purpose of 1) finding or producing crude oil or natural gas; or 2)

producing services related to the production of crude oil or natural gas.

Wellhead: The point at which the crude (and/or natural gas) exits the ground. Following historical precedent,

the volume and price for crude oil production are labeled as “wellhead,” even though the cost and volume are

now generally measured at the lease boundary. In the context of domestic crude price data, the term

“wellhead” is the generic term used to reference the production site or lease property.

Working Interest: An interest in a mineral property that entitles the owner of that interest to all or a share of

the mineral production from the property, usually subject to a royalty.



Companies mentioned under coverage:

BP Plc (BP.LN-521p, BP-$62; Peer Perform)

Chevron Corp. (CVX-$71; Peer Perform)

ConocoPhillips (COP-$67; Peer Perform)

Exxon Mobil Corp. (XOM-$75; Outperform)

Frontier Oil Corporation (FTO-$30; Peer Perform)

Hess Corp. (HES-$55; Outperform)Marathon Oil Corp. (MRO-$92; Peer Perform)

Murphy Oil Corporation (MUR-$52; Outperform)

Occidental Petroleum (OXY-$48; Peer Perform)

Royal Dutch Shell PLC (RDSA.LN-1683p, RDSA-$67; Underperform)

Sunoco, Inc. (SUN-$65; Outperform)

Tesoro Corp. (TSO-$89; Outperform)

Total S.A. (TOTF.PA-€52, TOT-$69; Outperform)

Valero Energy Corp. (VLO-$59; Outperform)

Western Refining Inc (WNR-$28; Peer Perform)

Sector ratings — Integrated Oil: Market Weight

Independent Refiners: Market Weight



Addendum

Important Disclosures

For important disclosure information regarding the companies in this report, please contact your registered representative at 1-888-473-3819, or write to Sandra Pallante, Equity ResearchCompliance, Bear, Stearns & Co. Inc., 383 Madison Avenue, New York, NY 10179.

Ratings for Stocks (vs. analyst coverage)

Outperform (O) — Stock is projected to outperform analyst’s industry coverage universe over thenext 12 months.

Peer Perform (P) — Stock is projected to perform approximately in line with analyst’s industrycoverage universe over the next 12 months.

Underperform (U) — Stock is projected to underperform analyst’s industry coverage universe over the next 12 months.

Ratings for Sectors (vs. regional broader market index)

Market Overweight (MO) — Expect the industry to perform better than the primary market index

for the region (S&P 500 in the U.S.) over the next 12 months.Market Weight (MW) — Expect the industry to perform approximately in line with the primarymarket index for the region (S&P 500 in the U.S.) over the next 12 months.

Market Underweight (MU) — Expect the industry to underperform the primary market index for the region (S&P 500 in the U.S.) over the next 12 months.

Bear, Stearns & Co. ratings distribution as of December 31, 2006(% rated companies/% banking client in the last 12 months):Outperform (Buy): 41.0%/8.3%Peer Perform (Neutral): 49.5%/8.0%Underperform (Sell): 9.5%/0.0%

For individual coverage industry data, please contact your account executive or visitwww.bearstearns.com.



Addendum

Important Disclosures

Analyst Certification

The Research Analyst(s) who prepared the research report hereby certify that the views expressed

in this research report accurately reflect the analyst(s) personal views about the subject companiesand their securities. The Research Analyst(s) also certify that the Analyst(s) have not been, are not,and will not be receiving direct or indirect compensation for expressing the specificrecommendation(s) or view(s) in this report.

Nicole L. Decker

The costs and expenses of Equity Research, including the compensation of the analyst(s) that prepared this report, are paid out of the Firm’s total revenues, a portion of which is generatedthrough investment banking activities.

This report has been prepared in accordance with the Firm’s conflict management policies. Bear Stearns is unconditionally committed to the integrity, objectivity, and independence of its research.

Bear Stearns research analysts and personnel report to the Director of Research and are not subjectto the direct or indirect supervision or control of any other Firm department (or members of suchdepartment).

This publication and any recommendation contained herein speak only as of the date hereof and aresubject to change without notice. Bear Stearns and its affiliated companies and employees shallhave no obligation to update or amend any information or opinion contained herein, and thefrequency of subsequent publications, if any, remain in the discretion of the author and the Firm.



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