valuation of norsk hydro oil & energy - au...

MSc in Finance &

International Business Author: Bjørn Are Flemmen

Ole Jakob Valla Strandhagen

Academic Advisor: Tom Albæk Hansen

Valuation of Norsk Hydro Oil & Energy

Århus School of Business

September/2004

Preface

This paper was written as a part of the 2-year Master of Science in Finance and

International Business at Århus School of Business. Our aim has been to determine

the fair value of Hydro Oil and Energy, which is a part of the Norwegian

conglomerate Norsk Hydro ASA. This includes an assessment of which methods to

use in analysing and valuating an oil company.

Our research is based on numerous articles, books, websites and published reports by

investment agencies and the company itself. We have chosen to act as external

analysts with no access to internal data.

We are thankful to our super advisor Tom Albæk Hansen at Århus Business School

for his guidance and contribution to this paper. We also thank: Torbjørn Jacobsen, JP

Morgan and Ryan Pirnat for information and reading through our thesis.

Table of Contents

1. INTRODUCTION 5

1.1. PROBLEM STATEMENT 7 1.2. METHODS 8 1.3. LIMITATIONS 9 1.4. SCOPE AND STRUCTURE 10

2. PRESENTATION OF NORSK HYDRO ASA 1

2.1. HYDRO OIL AND ENERGY 2

3. SELECTION OF STRATEGIC ANALYSE FRAMEWORKS 4

3.1. STRATEGIC ANALYSIS 4 3.2. VALUE CONFIGURATION THEORY 8 3.3. VALUE SHOP 11 3.5. EVALUATION AND SELECTION OF STRATEGIC FRAMEWORKS 19

4. SELECTION OF VALUATION METHODS 21

4.1. PRESENTATION OF VALUATION METHODS 21 4.2. EVALUATION AND SELECTION OF VALUATION METHODS 27

5. STRATEGIC ANALYSIS 30

5.1. THE MACRO ENVIRONMENT 30 5.2. ANALYSIS OF THE PETROLEUM INDUSTRY 38 5.3. VALUE CONFIGURATION ANALYSIS 46

6. FINANCIAL ANALYSIS 52

6.1. PEER GROUP 52 6.2. PROFITABILITY RATIOS 52 6.3. LIQUIDITY RATIOS 53 6.4. SOLVENCY RATIOS 54 6.5. CONCLUSION 54

7. ESTIMATION OF OIL AND GAS PRICES 55

7.1. SURVEY OF THE MOST IMPORTANT OIL MARKET MODELS 56

7.2. OIL MARKET CONDITIONS 58 7.3. HISTORIC OIL PRICE DEVELOPMENT 61 7.4. WORLD OIL SUPPLY AND DEMAND FORECAST 63 7.5. ESTIMATION OF OIL PRICES 66 7.6. NATURAL GAS FORECAST 70 7.7. ESTIMATION OF NATURAL GAS PRICES 72

8. EXCHANGE RATE (NOK/USD) 74

8.1. ESTIMATION OF EXCHANGE RATE (NOK/USD) 74

9. VALUATION OF HYDRO 77

9.1. BUDGET PERIOD 77 9.2. FORECAST OF FUTURE REVENUES AND COSTS 78 9.3. FORECASTING OTHER SPREAD SHEET ASSUMPTIONS 94 9.4. ESTIMATION OF COST OF CAPITAL 99 9.5. DCF - VALUATION OF HYDRO 105 9.6. SENSITIVITY ANALYSIS 107 9.7 SCENARIO ANALYSIS 108 9.8. EV/EBITDA MULTIPLE VALUATION OF HYDRO OIL & ENERGY 110 9.9. EV/DACF MULTIPLE VALUATION OF HYDRO OIL & ENERGY 111 10. CONCLUSION 112

FIGURE LIST 115

TABLE LIST 116

REFERENCES 117

APPENDIX 125

1. Introduction

This paper is a part of the “Master of Science in Finance and International Business”

degree at Århus School of Business. Our aim is to perform a fair valuation of Norsk

Hydro Oil and Energy. Norsk Hydro Oil and Energy is one of three core business

segments in the Norwegian conglomerate Norsk Hydro ASA.

There are two main reasons why we find this company and the petroleum industry

especially interesting. Firstly, the petroleum industry is of great importance to the

Norwegian economy as Norway is one of the largest producers in this highly

profitable business. Secondly, there is an ongoing debate concerning whether or not

the two largest petroleum companies in Norway should operate together in the future.

In several articles presented by the two Norwegian daily financial newspapers Dagens

Næringsliv and Finansavisen, analysts are discussing whether or not Norsk Hydro Oil

and Energy should be merged with or acquired by Statoil ASA. First Security analyst

Hans-Erik Jacobsen, ranked as the best industrial analyst in Norway by Kapital1, is

going farthest suggesting a possible merge; “I believe this is something that will force

itself. Even if this is not desired, I believe you do not have any other options”.

In the following section, we have highlighted some of the main points in the debate:

Conglomerates are quite unpopular among investors, which relates to factors

as impenetrable, increased focus within branches and fear of managements’

capabilities having focus on several branches. Norsk Hydro ASA is a

conglomerate operating in different business segments and there is reason to

believe that each segment will be better off alone.

The merger- and acquisition wave have piled through the energy industry in

the past years. Statoil ASA and Norsk Hydro Oil and Energy are on their own

relative small players in the international market and are supposed to get

problems related to growth and level of cost in relation to their competitors. 1 Monthly financial magazine in Norway

Norsk Hydro ASA has significant growth ambitions within its two other

business areas and as the capital is limited, selling off or de-merging the

petroleum activities would provide favourable conditions for a more positive

development in the two remaining business areas.

The synergy effects between Statoil ASA and Norsk Hydro Oil and Energy are

significant because both companies are doing business within the same area

and are more or less extracting their oil and gas from the same locations.

The Norwegian government is the largest stockholder in both Statoil ASA and

Norsk Hydro ASA. From past experiences, the Norwegian government is

reluctant to approve mergers that result in huge lay offs of workers. This will

probably be one of the synergy effects in the case of a merge between Norsk

Hydro ASA and Statoil ASA.

Another important issue for the government is to maintain a high degree of

new investments and explorations on the Norwegian continental shelf (NCS).

By merging two of the main competitors, the competition would be less and

there is reason to believe that new investments and explorations will slow

down.

In order to supplement this debate, we have chosen to valuate Norsk Hydro Oil and

Energy (from now on referred as “Hydro”). The value of Hydro will be one of the

crucial elements in deciding the future of an eventual merge with or sale to Statoil

ASA.

1.1. Problem Statement

Motivated by the ongoing debate our object is “to determine a fair value of Norsk

Hydro Oil and Energy”. In order to process a fair valuation, the paper focuses on the

following four core areas:

1) Selection of strategic frameworks and valuation methods

2) The strategic analysis of the company and the petroleum industry

3) Prospecting future developments of important factors such as oil and gas

prices and exchange rate (NOK/USD)

4) Valuation of the company

The selection of strategic frameworks and valuation methods is of special importance

since the petroleum industry differs from other industries, due the fact that the

petroleum industry is a problem solving industry and that the petroleum is an

exhaustible natural resource. We have to answer the following questions:

Which methods are most suitable in analysing the fundamentals of the

company and the petroleum industry?

Which methods are most accurate and reliable in valuating a petroleum

company?

In the strategic and financial analysis, we try to answer the following questions:

What are the political, economical, sociological and technological factors

influencing the petroleum industry – and what will happen to these aspects in

the future?

What is Hydro’s competitive strengths and strategic position compared to its

competitors?

In what state is Hydro’s overall financial condition?

Oil and gas prices and the exchange rate (NOK/USD) are three external market

factors highly influencing Hydro’s profitability. In order to predict the future

developments of these factors, we have mainly relied on energy agencies and

professional analysts.

Finally, we answer the following question – what is the fair value of Norsk Hydro Oil

and Energy?

1.2. Methods

We have applied a whole range of different sources as annual reports, books, internet

cites, articles and other relevant information and prognosis from investments banks. In

connection to the chosen topic, important subjects are accounting-, financial-, law-,

organization-, statistic- and strategic theory. However, focus will embrace on

accounting-, financial- and strategic aspects.

Strategic analysis: In order to analyse the macro environment of the petroleum

industry, we have used the PEST method as conceptual framework, whereas

the “industry analysis” is based on Porter’s (1980) “Five-Forces” framework.

To analyse the internal competences within the firm, we have used the value

configuration theory developed by Stabell and Fjeldstad (1998). Furthermore,

the company’s strength, weaknesses, opportunities and threats are covered in a

SWOT analyse.

Financial analysis: The financial analyse is based on Norsk Hydro ASA’s

balance sheet and income statement from their annual reports from 2000 to

2003. We look at Hydro’s profitability, liquidity and solvency ratios. In our

assessment of Hydro’s financial condition, we compare their ratios against a

peer group.

Valuation analysis: In the valuation of Hydro we have employed the DCF-

approach and multiples, respectively the EV/EBITDA and EV/DACF

multiples. We have also conducted scenario and sensitivity analysis.

1.3. Limitations

Normally, aspects such as possible synergies, the negotiation process, motives behind

the eventual purchase, taxation advantages and so on affect the estimated value of

Hydro. However, in our case, we only look at Hydro from a stand-alone point of view,

which implies that such aspects are not considered.

We have acted as external analysts, with no access to internal data. Information after

22 January 2004 is not considered.

In order to perform a cash flow valuation of Hydro with reasonable accuracy, a full-

scale financial model of the company is constructed. We have less financially related

information than we would have preferred. However, we believe the assumptions

made are reasonable and that our results are not far from reality. The annual reports

are mainly based on concern level. We have therefore constructed a balance sheet and

income statement for Hydro based on certain assumptions2. The division is broken

down according to the company’s business plan. There are several minor business

operations that we could not model properly, due to the lack of adequate data.

However, considering the fact that most of Hydro’s operations are in offshore field

developments, we do not envisage significant valuation inaccuracies. The focus is on

the Exploration and Production segment.

It will be assumed that the readers have certain knowledge about fundamental analysis

and valuation methods, and for that reason, we do not present an in-depth presentation

of the most common frameworks.

2 See appendix 1

1.4. Scope and Structure

First, we present Norsk Hydro briefly. Secondly, we present the theoretical

framework used in the paper. We try to give a broad overview, but focuses on the

frameworks that are actually used. In the third part, we predict future oil and gas

prices and the development of the exchange rate (NOK/USD). Finally, we valuate the

company.

The content of each chapter is as follows:

Chapter Two: Brief presentation of Norsk Hydro ASA: The purpose of this chapter is

to introduce the Oil and Energy division within the conglomerate Norsk Hydro ASA.

The presentation is limited and only meant as an introduction to the company.

Chapter Three: Selection of strategic analyse frameworks: In this chapter, we briefly

survey the most used strategic analysing methods followed by a selection of which

methods to use. The focus is on the application of the value configuration theory,

since this method probably is most unfamiliar to the readers. In short, building on the

work of Stabell and Fjeldstad (1998) we contrast a view of the upstream oil industry

as a problem solving industry.

Chapter Four: Selection of valuation method: The goal of this section is to determine

the most appropriate method to valuate Hydro. As initial step, we present the most

appropriate valuation methods, followed by a discussion considering which of the

methods that suits our purpose best. The methods that are actually used are to some

extent explained through the valuation process itself.

Chapter Five: Strategic analysis: In this chapter, we analyse the petroleum industry

and Hydro’s position. The chapter is based on the literature review in chapter three.

Chapter Six: Estimation of oil and gas prices: First, we introduce the most employed

global oil market models followed by a discussion on their reliability in predicting the

future oil price. Secondly, we present the oil market and historical oil prices. Finally

we try to determine the future development of oil and gas markets as soundly as

possible.

Chapter Seven: Exchange Rate (NOK/USD): Brief analyse of the economic

conditions in Norway and USA, in order to predict the future movements of the

exchange rate.

Chapter Eight: Financial Analysis: Analyses the historic financial performance of

Hydro by looking at their profitability, liquidity and solvency ratios compared to a

peer group.

Chapter Nine: Valuation of Hydro: Translates the strategic perspective into financial

forecasts and valuates Hydro based on the discounted cash flow model, followed up

by sensitivity and scenario analysis. The chapter ends valuating Hydro by

EV/EBITDA and EV/DACF multiples.

Chapter Ten: Conclusion: Summarizes the paper and states our final thoughts

regarding the valuation.

2. Presentation of Norsk Hydro ASA

Norsk Hydro ASA has a long history and was established under Norwegian law as a

public company in 1905. The idea was to utilize Norway’s large hydroelectric energy

resources for the industrial production of nitrogen fertilizers. Until the 1950s this was

the company’s core area. The company acquired aluminium assets during that decade

and developed a substantial oil and gas business during the 1970s. Today the energy

produced, in the form of hydroelectric power, natural gas and petroleum, is the basis

for Norsk Hydro ASA’s growth and the largest earnings contributor. Hydro Oil and

Energy, the segment in focus, is together with Hydro Aluminium and Hydro Agri the

operating segments incorporated in Norsk Hydro ASA. We notice that Hydro Agri

will be spun off from the company through an IPO on March 25, 2004.

Figure 1: Norsk Hydro ASA's Business Areas (2002 Numbers)

Company total NOK 163 bn

NOK 33 bn

NOK 52 bn

NOK 65 bnAluminiumOil & EnergyAgri

Aluminium: The largest European aluminium company and among the top three worldwide

Oil & Energy: The second larges producer of oil and gas on the Norwegian Contitnental Shelf

Agri:The world's leading supplier of plant nutrients

2.1. Hydro Oil and Energy

Hydro Oil and Energy’s goal is to be a profitable participant in the upstream oil and

gas business and focus is on their core competencies; advanced drilling, reservoir

management, and the development of complex and technologically challenging

projects. Hydro has been one of the pioneers in developing the Norwegian petroleum

industry, right from the outset in the 1960s. Today Hydro, with its 3.500 employees,

is the second largest operator in Norway and one of the world leaders in deep water

exploration of oil and natural gas.

Hydro is also an integrated European energy company and a major player in the

Nordic and European energy market producing a significant volume of hydroelectric

power to retail customers. As a leading energy company, Hydro has committed itself

to the development of new sources and forms of energy such as wind power and

hydrogen. Hydro’s operating business is divided into two sub-segments, Exploration

and Production, and Energy and Oil Marketing.

2.1.1. Exploration and Production

The Exploration and Production sub-segment include oil and gas exploration, field

development and the operation of production and transportation facilities. Hydro’s

operations are based on the Norwegian continental shelf (NCS), with also production

in Angola, Canada, Russia and Libya, and exploration activities in the Gulf of Mexico,

Iran and Denmark. Hydro has a unique expertise in deep-water drilling, but is also

engaged in land base production and exploring drilling, where they are recognized for

the ability to recover the most oil possible from existing fields.

From 1998 to 2002, Hydro increased its total production of oil and gas by more than

75 percent, reflecting the organic growth at the NCS, the start-up of international

production activities, the acquisition of Saga Petroleum in 1999 and increased

interests in Norwegian fields formerly owned by the Norwegian State. In the

beginning of 2003 Hydro had interests in 105 licences on the NCS and operated 44

licenses covering 11 fields.

Hydro is also well established in the European gas market through a combination of

its long-term supply commitments to incumbent gas companies in Europe, supply to

its own gas consuming Hydro sites as well as through an emerging direct customer

portfolio on the European continent.

2.1.2. Energy and Oil Marketing

The Energy and Oil Marketing sub-segment is concentrating on exploiting the

commercial options in the oil, retail gas and power sector; the operating of Hydro’s

power stations and sales activities of refined petroleum products (gasoline, diesel, and

heating oil) to retail customers, electricity to retail customers in Scandinavia and the

Baltic countries, and managing Hydro’s seaborne transportation for crude oil and

other petroleum products. Hydro owns 100 percent of its oil marketing unit in Sweden

and 50 percent of Hydro Texaco, an oil marketing company with retail outlets in

Norway, Denmark and the Baltic countries. The combination of all commercial

activities for energy products and services in one business unit (Energy and Oil

Marketing) is leveraging the quality and contacts in each of the energy sectors.

3. Selection of Strategic Analyse Frameworks

The aim of this chapter is to describe the theoretical framework applied in the

strategic analysis of Hydro and the oil industry. The first section reviews a selection

of prior research on competitive strategy and competitive advantage in petroleum

exploration. Secondly, we thoroughly discuss the value configuration theory and the

use of value shop. At the end, we decide on which theoretical frameworks that suits

our purpose best.

3.1. Strategic Analysis

The main objective behind strategic analysis is to make inquires of the company’s

strategy together with its positioning in the industry in order to produce a

comprehensive and accurate forecast of the company’s future prospects and

performance.

In order to be successful a company must develop a competitive advantage which is

said to be the essence of company performance in competitive markets3. Competitive

advantage is achieved by the company’s ability to offer the same product at less cost

or establishing and maintaining an attractive and distinctive product offering while

achieving above average returns compared to its competitors. In order to create and

sustain such an advantage the company must develop a competitive strategy4.

Strategy has for many years engaged massive interest from academics, which has

resulted in abundance of literature and different models. Table 1 shows the most

common theoretical frameworks used in strategic analysis.

3 Stabell, C.B. and Sheehan, N. T. 2001, Competitive advantage in petroleum exploration, Oil & Gas Journal, 23 April, 99(17) 4 Ibid.

Table 1: Levels of Strategic Analysis

Levels Models

Macro PEST

The diamond framework of Porter

Industry

The “five-forces” of Porter

The S-C-P paradigm

SWOT

Area of Business/

Competitive Advantage

Porter’s value chain analyse

Analyses of resources and competences

Porter’s 3 generic strategies

Value configuration theory (new)

At the macro and industry levels the models are more or less suitable for all kinds of

industries. In the area of business/ competitive advantage, the competitive strategic

models are not as universal and primarily relevant to industries that are dominated by

a manufacturing logic. The literature especially focusing on competitive strategy for

petroleum exploration is limited. Sheehan and Stabell (2001) list the following

reasons as possible explanations:

Petroleum exploration is not a competition with other exploration outfits, but

rather a competition with Mother Nature. The effort is more cooperative than

competitive as exploration outcomes benefit others.

Strategy for petroleum exploration is simple. It is primarily an issue of good

people and good tools, and bit of luck.

The large exploration outfits, the outfits that usually catch the interest of

consultants and academics that publish work on competitive strategy, are not

independent firms or strategic business units, but are most often functions and

departments in large integrated firms.

Modern competitive strategy, and particularly the value chain framework of

Michael Porter have not been easy to apply to petroleum development and

exploration.

Porter (1980) argues that the profitability of a company is the function of the

attractiveness of the industry and the company’s ability to compete within the industry

itself. The competitive position of a company is further found by determining the

company’s basic unit of competitive advantage. Reve and Stokke (1994) further

suggest that the “micro-level” assessment is the competitive advantage of companies

described by the value creation logic, such as the value chain (see figure 2). The basic

idea, however, is that companies within an industry compete on delivering superior

value to customers and at the same time perform better on costs5.

Figure 2: The Value Chain Activity Template

Source: Stabell and Fjeldstad 1998

However, opposed to industries with a manufacturing logic, the upstream petroleum

industry is unique with respect to several critical areas (mentioned below). The

upstream petroleum industry is one of three streams within the petroleum industry

(see figure 3).

5 Porter, M.E. 1990. The Competitive Advantage of Nations. New York: Free Press.

Figure 3: The Three Streams within the Petroleum Industry

Upstream Midstream Downstream Explore Develop Produce Transport/Trade Refine Distribute Consume

Exploration units in petroleum companies cooperate as much as they compete

with each other and contrary to companies with a manufacturing logic there is

no competition in the output market. This is because the commodity is sold to

refineries at price, which is determined solely by market forces beyond the

firm’s control. The only manner exploration units compete is in the input

market, where they compete on winning the best people and projects.

Unlike most companies in the manufacturing industry, the generic commodity

that the upstream industry produces is only price sensitive to movements in the

market price and not sensitive to the need of consumers.

The product that the petroleum industry sells can only be produced in limited

quantities each year, which is opposed to manufacturing firms that in theory

can sell unlimited units. This is due to the fluid mechanics of the reservoir,

meaning it is not possible, nor efficient to drain a reservoir in one year.

As the reserves in the reservoir are finite, a firm will each year reduce its

inventory of saleable reserves, which is in contrast to manufacturing firms who

can, in theory, produce in perpetuity.

To summarize it can be said that exploration units plays the most essential role in the

petroleum industry and distinguish as the major difference opposed to industries with

a manufacturing logic. This is due to the role of the exploration unit, which is to

locate new reserves of petroleum and thereby replace the amounts sold to ensure their

long-term survival for a petroleum company, or in other words, successful problem

solving of finding hydrocarbons to ensure continued profitability.

This logic of value creation in problem solving industries (upstream petroleum

industry) is therefore different opposed to companies with a manufacturing logic.

According to Stabell and Fjeldstad (1998), the broader concept of the value

configuration theory is more appropriate to employ.

3.2. Value Configuration Theory

Value configuration theory focuses on firm-level competitive advantage. The basic

premise is that competitive advantage cannot be understood by looking at the firm as

a whole. Competitive advantage stems from the many discrete activities that a firm

performs in generating and delivering value6. Each of these activities can contribute to

a firm’s whole relative cost position and create a basis for differentiation.

The theory distinguishes between two main classes of activities in the firm. Primary

activities are directly involved in creating the value that is purchased by the buyer.

Support activities, on the other hand, are activities that impact value purchased only

through their impact on primary activities. Support activities support primary

activities and are potentially relevant for all types of firms.

According to value configuration theory there are three basic alternative ways that

firms create value. In addition to Porter’s initial formulation with the value chain,

value configuration theory proposes that there is the value shop and the value network.

Table 2 summarizes the key attributes of the three value configurations. Building on

Thompson’s (1967) concept of a technology, Stabell and Fjeldstad (1998) have

extended Porter’s (1985) activity-based view to include pure knowledge-shop and

value network. These activity-based frameworks are for firms that rely on an intensive

value creation technology and a mediating value creation technology. Stabell and

Fjeldstad (1998) suggest that the value chain is one of three generic value

configurations. They suggest therefore that Porter’s (1985) value chain framework is

6 Porter, M.E. 1985, Competitive Advantage. New York: Free Press.

relevant to manufacturing firms and less to firms that sell problem solving services

(consulting and engineering services) and that sell mediation services (financial,

transportation and communication services).

Table 2: Overview of Alternative Value Configurations

Value Chain Value Shop Value Network

Value creation

logic

Transformation of inputs

into goods

(Re) solving customers

problems Linking customers

Petroleum industry

example

Petroleum production

Oil refining

Drilling services

Engineering services

Consulting

Gas and oil

transportation

Oil and gas exchanges

Brokering

Primary

technology Long-linked Intensive Mediating

Key cost drivers Scale

Capacity utilization

Scale


Key value drivers Reputation Scale


Primary value

system relationship Interlinked chains Referred shops

Layered and interconnected

networks

Source: Stabell & Fjeldstad 1998

Value configuration theory provides a systematic basis for analysing and developing

competitive advantage7. A firm is broken down into value activities where costs and

value generated are allocated and estimated, either using the value chain (see figure 3)

for manufacturing firms, value network for mediators, or value shop for problem

solving firms (see figure 4). The results are used to identify the competitive strengths

and weaknesses of the firm.

Both midstream and downstream oil industry have several sets of operations, but the

logic of value creation is similar and can be analysed by using the well-known value-

7 Stabell, C.B. and Sheehan, N. T. 2001, Competitive advantage in petroleum exploration, Oil & Gas Journal, 23 April, 99(17)

chain8. The upstream oil industry process has also several set of operations (see figure

4), where the logic of value creation behind production can be analysed by using the

value-chain. However, the two other operations, exploration and development is better

analysed by the value-shop approach9. According to Porter (1985), we distinguish

between cost drivers and differentiation drivers. In the value shop approach, value

drivers such as healing the patient, winning the case, finding hydrocarbons etc. is

becoming more important than cost drivers10. Restated in petroleum exploration terms,

it takes about the same effort to make a large discovery as one that is barley

commercial11 . Value configuration theory therefore suggests that the competitive

strategy for exploration outfits should focus on differentiation drivers, which are

according to Stabell and Fjeldstad (1998) reputation. Their arguments are outlined in

more detail in the following presentation of the value shop as framework.

Figure 4: Value Creation Logic in Upstream Activities

Source: Stabell & Fjeldstad 1998; Reve and Stokke 1994

8 Porter, M.E. 1985, Competitive Advantage. New York: Free Press. 9 Stabell, C.B., and Fjeldstad, Ø. D. 1998, Configuration value for competitive advantage: On chains, shops and networks, Strategic Management Journal, 19(5) 10 Stabell, C.B. and Sheehan, N. T. 2001, Competitive advantage in petroleum exploration, Oil & Gas Journal, 23 April, 99(17) 11 Ibid.

3.3. Value Shop12

The value shop is a tool to evaluate the effectiveness of activities performed by a firm.

It is a model for firms that rely on intensive technology and create value by mobilising

resources to solve problems for clients, rather than transforming inputs into outputs

using a linear logic (see figure 5). The selection, combination and order of application

of resources and activities vary according to the problem at hand and the results of

earlier activities.

A problem is solved and hence, value created when the client is moved from an

existing state to a desired state of affairs. In the case of petroleum exploration, the

change is from knowing that hydrocarbons might exist, to finding and verifying

hydrocarbons. There is rarely one right solution to a problem, but the intensive

technology is directed to change the situation, to find the most optimal and desired

solution for the customers or clients.

Figure 5: The Value Shop

Source: Stabell & Fjeldstad 1998

12 This part builds extensively on the work of Stabell, C.B., and Fjeldstad, Ø. D. 1998, Configuration value for competitive advantage: On chains, shops and networks, Strategic Management Journal, 19(5), if nothing else is stated.

3.3.1. The Value Creation Logic of the Value Shop

The activities in the shop are not linear but circular and iterative and therefore result

in a high degree of sequential and reciprocal interdependence between activities. New

information about a problem might lead to new searches for information and

application of alternative implantations and, hence, new problem solving activities.

Information is prerequisite to solve problems and thus professionals often have a

standard information acquisition procedure to make sure that the problem has been

correctly framed. Furthermore, these types of standardisation of activities provides

both value and limits overall costs, as well as providing the basis for early anticipation

of succeeding activities.

The generic primary activity categories in a value shop are:

Problem finding and acquisition: Activities associated with the recording,

reviewing and formulating the problem to be solved and choosing the overall

approach to solving the problem.

Problem solving: Activities associated with generating and evaluating

alternative solutions.

Choice: Activities associated with choosing among alternative problem

solutions.

Execution: Activities associated with communicating, organizing and

implementing the solution chosen.

Control and evaluation: Activities associated with measuring and evaluating to

what extent that implementation has solved the initial problem statement.

In the context of primary activities, problem finding can often be problem acquisition.

Problem finding has much in common with marketing in the value chain, where it is a

primary activity category. Furthermore, it is one of the most important primary

activities in the value shop, because correct problem definition is the key to value

contribution of the value shop. The problem finding stage is a sensitive stage of the

process and is therefore a critical first step to effectively solving complex problems.

Client problem often involve more or less standardised solutions, but the value

creation process is configured to deal with unique cases. Less specialised personnel

can solve most of the problems, but the specialist must always be involved to some

degree.

Choice is of great importance when it comes to the point of value and it delineates the

interface between different specialists and is often a point of major discontinuity in

the problem solving cycle. Furthermore, they also postulate that choice also delineates

the interface between different specialists and a major discontinuity in the problem

solving cycle.

As with the value chain, the value shop has a corresponding set of support activities

that play an indirect role in creating value. The main difference is that in problem-

solving firms the support activities are usually co-performed along with the primary

activities, rather than being distinct functions that are physically separate from the

undertaking of the primary activities as in the value chain. Technology development is

often embedded in the primary activities and is often developed as a part of solving a

client’s problem. As this indicates, the support activities in the value shop are often

part of the primary activities and not distinct activities themselves.

The value shop is labour intensive and its success depends on high-quality

professionals. Thus human resource management becomes particularly important, in

regards to hiring and training professionals. The most qualified professionals want to

work with the best in their field, therefore reputation and other ways of attracting

extraordinary talent become paramount13. Since marketing is primarily “relationship-

management” involving referrals from customers and colleagues, the professionals

become the most important marketing resource. Shell, one of the large oil companies,

provides anecdotal evidence of reputation’s role in attracting good people in the

13 Quinn, J. B. 1996, Managing Professional Intellect Making the Most of the Best, Harvard Business Review p 71

petroleum industry. Shell noted that in the aftermath of incidents with the disposal of

Brent Spar and problems in Nigeria that their reputation may have decreased in

value14. Shell was worried this decline may place them at a disadvantage in attracting

professionals, noting that in the petroleum industry it is the people who choose

company, not the other way around15.

3.3.2. Cost and Value Drivers

Scale and capacity are often used to illustrate the concept of drivers. In manufacturing

(value chains) these are generally key drivers of cost: Unit costs drop with scale and

capacity utilization. In the value shop model, value is a more important issue, since

the clients or customers are looking for solutions to their relatively complex problems

and not for services that have low prices as their main attribute.

Porter (1985) postulates that reputation signals value. When success is demonstrated

this foster good reputation and hence, is an important marketing and sales tool for the

value shop. Stabell and Fjeldstad (1998) therefore propose that reputation is the key

differentiation driver in problem-solving firms due to its reinforcing impact.

Demanding clients and projects provide a basis for effective learning, and those

projects that have been successfully performed serve a basis for building relationships

and reputation. Success is affected by the value shop’s ability to recruit, retain and

develop high quality personnel

Learning in the value shop is an integral and explicit part of the problem solving cycle.

Evaluation and post implementation control is a means to improve the shop’s ability

to deal with more effectively with problem at hand; both through better problem

definition, better alternatives and better implementation. Scale gives limited

advantages for the value shop, as it related to the scale of client’s problems. However,

there are significant advantages of location for a value shop.

14 Steel, G. 1999, Strategic transformation at Royal Dutch Shell, In P. Senge, A. Kleiner, C. Roberts, R. Ross, G. Roth, B. Smith (eds). The Dance of Changes. Nicholas Brealy 15 Ask, A.O. 1998, Shell has good earnings and bad image. Dagens Næringsliv, 13 February

3.3.3. Value Creation in the Upstream Petroleum Industry

As explained above, the value shop model is more appropriate for problem-solving

industries emphasising on value maximisation as opposed to cost minimisation

emphasised in the value chain. Although unit costs are a relevant performance

measure to consider the complete life cycle of an oil field, it is less useful as a guide

to the economics of petroleum exploration and field development. In petroleum

exploration and field development, value created seldom correlated with finding costs:

finding a very large field costs approximately the same as finding a small field16. The

drivers of value behind the value shop are of importance in petroleum exploration and

field development17. E.g., reputation gives access to the best prospects and the best

professionals, which in turn maximises learning across projects and across disciplines.

Problem solving emphasises on effective information search and selection as opposed

to efficient information flow18. These attributes of the value creation process allow for

discussion on attractive positioning options for existing and new actors.

Figure 6: Value Shop Diagram for a Petroleum Explorer (A) and Field

Developer (B)

Source: Stabell and Fjeldstad 1998

16 Stabell, C.B., and Fjeldstad, Ø. D. 1998, Configuration value for competitive advantage: On chains, shops and networks, Strategic Management Journal, 19(5) 17 Ibid. 18 Ibid.

Stabell and Fjeldstad (1998) suggest three variants to the value shop concept. The first

is the diagnosis-focused shop, e.g. medical consultation, where treatment plans

directly follow the diagnosis. The second is the search focused shop e.g. petroleum

exploration, where the search for petroleum is finalized as soon as the existence of

commercial petroleum reserves is proven (see figure 6 (A)). Problem finding activity

in petroleum exploration is performed to identify an area with potential hydrocarbon

prospects. The problem-solving activity is performed to generate and evaluate

prospects in the area and the activity choice is performed to make a choice among

prospects considered, while the activity execution is performed to evaluate the results

from exploratory drilling19.

The final shop is the design focused shop, e.g. petroleum field development (see

figure 6 (B)), where initial problem finding is initiated by referrals and the problem

solving is the generation and evaluation of alternatives before choosing, which

alternative that should be used. In all three variations, the incorporation of the

problem object is not only a tool for reducing uncertainty, but also a means to increase

communication and cooperation between the firm (the oil company/ offshore service

company) and its clients (the asset owner/the oil company)20.

3.3.4. Value Configuration Theory Discussion

In a paper discussing the concept of competitive advantage in petroleum exploration,

Sheehan and Stabell (2001) follow up the value shop theory of Stabell and Fjeldstad

(1998). Based on their work they trace out three main categories of critical

differentiation drivers in petroleum exploration (see below), the authors strengthen

Stabell and Fjeldstad (1998) work that the critical differentiation driver is reputation

in value shop.

The most popular category was one that they labelled assets (leading edge

technology, a good portfolio of licenses, a creative culture and good

knowledge base).

19 Stabell, C.B., and Fjeldstad, Ø. D. 1998, Configuration value for competitive advantage: On chains, shops and networks, Strategic Management Journal, 19(5) 20 Ibid.

The second most popular factor was management support (predictable funding,

willingness to take risk, consistent strategy and focus and short time decision).

The third most frequent response was people (competent, knowledgeable and

motivated staff).

Furthermore, they argue that reputation is critical in value shops because of the basic

information asymmetries that are built into the relationship between the shop and its

clients. Clients consult a shop because the client believes that the shop knows how to

solve the client’s problem21. The client consults the shop because the shop knows

something that the client does not now22.

Given these properties, Sheehan and Stabell (2001) argue that reputation is a key

driver as it attracts the best projects and people to the problem-solving firms. The best

projects attract best professionals as the best professionals want to work on the best

projects, which successfully solve the best projects, thus creating a positive feedback

loop (figure 7). In short, success and reputation lead to the accumulation of the assets

and competences that ensure future success23.

21 Stabell, C.B. and Sheehan, N. T. 2001, Competitive advantage in petroleum exploration, Oil & Gas Journal, 23 April, 99(17) 22 Ibid. 23 Ibid.

Figure 7: The Positive Success Feedback Loop in Exploration

Source: Sheehan and Stabell 2001

Furthermore, the authors trace that there is a positive link between reputation and

success and that the most important result in terms of success is the discovery rate and

reserves per exploration well for the exploration shop. According to their result, this

holds even when controlling size of the unit. In other words, the link between

reputation and exploration success is not just capturing that the larger exploration

units are better known24. However, their findings cannot show statistically that high

reputation firms drives future exploration success.

Shank, Spiegel and Escher (1998) argue that the “normal” value chain analysis,

focussing only on a company’s value added, is starting far too late and ending far too

early in the value chain. In order to overcome these shortcomings, they have adapted

the value chain analyse into what they call “strategic value analysis” (SVA). The SVA

apply the value chain concept to the entire value delivery system of the oil industry,

evaluating each stage of the economic value creating process in the industry with

special focus on historical cost, transfer prices and accrual-based accounting.

According to the authors, the SVA analysis is better pointing out possible competitive

advantages, sources of profitability and areas of improvement in all stages of the

value chain than the traditional value chain concept. However as we see it, the 24 Stabell, C.B. and Sheehan, N. T. 2001, Competitive advantage in petroleum exploration, Oil & Gas Journal, 23 April, 99(17)

application of the SVA mainly focuses on the downstream part of the industry and

almost completely overlooks the upstream activities.

3.5. Evaluation and Selection of Strategic Frameworks

To valuate Hydro it is important to apply suitable theoretical concepts on the oil

industry in order to position Hydro’s strategy and its positioning in the petroleum

industry. In table 1, we listed the most significant theoretical frameworks that have

been used. Further, we conclude that both macro and industry level contain suitable

models that can be applied in analysing the petroleum industry. Among the different

methods mentioned in table 1, we have chosen to apply an extended version of the

PEST framework25. This framework is more or less a more detailed version of the

original PEST model and from now on referred as “PEST”.

To position Hydro in its business environment and determine their degree of

bargaining power in the oil industry, we use of Porter’s Five Forces framework. We

consider this model most appropriate to analyse Hydro, because it helps us map the

external environment and the major forces influencing the company and its

competitive position. Considering the focus of our analysis, we have only applied the

models to the petroleum industry.

Hydro Oil and Energy is by definition a fully integrated oil company. To analyse

Hydro and its competitive position in the petroleum industry, we apply the value

configuration theory. This is a radically new framework, but as thoroughly discussed,

this is the best tool analysing an oil company. As mentioned earlier, the exploration

unit is the most important unit within an oil company. The focus will therefore be on

the exploration and production segment rather than the energy and oil marketing

segment, where we apply the value shop framework.

25 Elling, O. E., Hansen, K.H., Sørensen, O. 1998, Strategisk regnskapsanalyse, Forlaget Thomsen

In addition, the SWOT model is applied to make a profile of Hydro’s strengths,

weaknesses, opportunities and threats within the oil industry.

4. Selection of Valuation Methods

As there are numbers of different valuation approaches, there are numbers of different

opinions on how to valuate a company. It can be discussed which models, cash flows,

assumptions about rates etc that are most proper, but none of the approaches can

calculate precisely the value of a company unless the market itself. However,

valuation plays a central role in the capital market and decisions are often based upon

the estimated price of a company.

The aim of this chapter is to decide the most appropriate method to use in the

valuation of Hydro. Firstly, we present and explain shortly the most used valuation

approaches and methods. We also give a more thoroughly description of real options.

Real options are not used in the valuation of Hydro, but are an evolving and very

promising field of research that may be useful in the valuation of oil companies in the

future. Following this, we discuss which of the methods that is most analytically

correct (accurate and reliable) to use in our case.

4.1. Presentation of Valuation Methods

The results may differ significantly depending on which valuation method that is used.

In this section, the most important and widely used pricing methods are explained and

compared.

4.1.1. Market Valuation Methods26

Market valuation methods, also called relative valuation methods, are based on price

multiples. The approach derives the value of a company by comparing it to the price

of comparable companies and looking at standardized variables such as earnings,

dividends, cash flows, sales revenue and net tangible assets (NTA). The most used

multiples (or ratios) are the price-earnings ratio (PE), price-to-NTA ratio, and price-

26 Palepu, Bernard, and Healey. 1997, Introduction to Business Analysis & Valuation, Second Edition, chapter 7

to-sales ratio where companies are compared with other companies that have similar

operating and financial characteristics, in most cases within the same line of industry.

The method thereby assumes that the pricing of other companies is applicable to the

company at hand.

4.1.2. Book Value Based Methods27

Based on accounting techniques the book value method values a company by its book

value. In short; assets subtracted by liabilities equals the equity, which is the “book

value” of the company. Two other approaches based on accounting techniques are the

liquidation and replacement methods. The liquidation value of a company is the

summarized value you would receive if you sold the various items of a company

separately. The replacement value of a company is the summarized value you would

have to pay if you were going to replace all the company’s assets to start a new

company with the same earning power.

4.1.3. Income Based Valuation Methods

Income based valuation methods and market value methods are the far most popular

approaches among investors and analysts. We have chosen to highlight the following

four income based models; discounted cash flow model, dividend capitalization model,

EVA model and the earnings-capitalization model.

Discounted cash flow (DCF) 28. Simplified, this approach reveals the value of a

company by discounting its expected future cash flows by the company’s risk-

adjusted rate of return (or estimated cost of capital). The model employs

detailed multiple year forecasts of the cash flow and the accuracy of the

valuation depends on the accuracy of these forecasts. Analysts and business

valuators etc. tend to use this model because it is more or less independent

from accounting rules and it captures all the elements that affect the value of a

27 Idem; chapter 7 28 Palepu, Bernard, and Healey. 1997, Introduction to Business Analysis & Valuation, Second Editon, chapter 6

company in a straightforward manner. The DCF approach will be further

described in the valuation process of Hydro.

Dividend discount model29. Investors of a company can expect two kinds of

cash flows; the payout of dividend during the ownership and the expected sales

price. In order to employ this method, factors such as expected dividend, cost

of equity and the equity of the company must be estimated.

Economic value added (EVA) 30 and residual income model (RI). Has been

developed as an alternative to the DCF model. In short, EVA is net operating

profit minus an appropriate charge for the opportunity cost of all capital

invested in a company. In other words, it is an estimate of the economic profit,

or the amount by which earnings exceed or are less than the required minimum

rate of return that shareholders and lenders could get by investing in other

companies of comparable risk. The residual income model is a variant of the

EVA model and derived from the dividend model. The difference is that the

EVA model value a company from the angle of both equity holders and

lenders, while the RI model only valuate from the angle of the equity owners.

In short, the RI approach values the book value of equity at the valuation date

and the present value of future residual income.

Earnings capitalization method. This approach determines the value of a

company based upon present value of estimated future earnings, discounted by

the cost of equity.

4.1.4. Real Options

We can differentiate between traditional and strategic valuation models. The

discounted cash flow model (DCF) is a typical traditional method, while the most

29 Miller, M. H. and Modigliani, F. 1961, Dividend policy, growth, and the valuation of shares, Journal of Business, No 4, pp. 411-433. 30 Stewart, G. B. III. 1991. The Quest for Value. New York, NY: Harper Business

common strategic model is real options31. Under traditional DCF analysis, expected

cash flows are used to valuate a company or an investment. Of course, any such

analysis can only be as good as the assumptions underlying the input numbers.

Sensitivity analysis and scenario analysis provide greater depth of understanding

while looking at the effects upon potential payoffs of changed key variables and

asking “what if” questions. Nevertheless, the DCF approaches are not able to fully

incorporate the value of flexibility.

Real options, on the other hand, places a value on management’s ability to react to

future events, and their ability to dynamically react to new information or changing

market conditions.

4.1.4.1. Description of Real Options

Real options theory is founded on the same principles as financial options: real

options, like financial options, give an owner the right, but not the obligation, to take

action. However, real options, unlike financial options, require ownership of real

tangible assets. Real options, like financial options, have five key components: value

of asset, exercise or strike price, volatility, and risk free rate.

The most important factor valuating an option is the volatility or the uncertainty factor.

There are different ways to find the volatility of an investment or company. One is to

use historical data of underlying assets. Another is to use the volatility of the stock

index and/or look at the option prices for the company. The underlying asset for real

options are the company’s cash flow. The cash flows are dependent on a range of

uncertainty factors like oil price and production quanta. We have to identify which

factors that influence the expected cash flow most and determine which stochastic

process that best describe the uncertainty of these factors. In the case of Hydro, oil

prices would be a crucial uncertainty factor. Because the oil price varies over time, it

is said that it follows a stochastic process. The Geometric Brownian Motion is the

stochastic process that is most frequently employed in the literature that addresses real

31 Amram, M and Kulatilaka N. 1999, Real Options: Managing Strategic Investment in an Uceratin World, Harvard Busniess School Press

options for commodities32. Another important issue would be to look at the option

price for Hydro or a benchmarked company and find the underlying assets’ stock

development.

There are many real options. Trigeorgis (1996) lists the most common ones as follows:

The option to defer or to wait when developing a natural resource or building a

plant

The time-to-build option (staged investment): At each stage the investment can

be re-evaluated and (possibly) abandoned or expanded.

The option to alter operating scale (expand, contract, shut down, or restart)

The option to abandon

The option to switch inputs or outputs

The growth option – an early investment in a project constitutes an option to

“get into the market” at a later date.

4.1.4.2. Real options and the oil industry

The oil industry is dealing with the following ingredients that are ideally suited for

real options; large capital investments, uncertain revenue stream, often long lead times

to achieve these certain cash flows, uncertainty in the amount of potential production,

numerous technical alternatives, political risk and market exposure.

Consequently, real options have a natural place in the oil industry management-

decision making process. Real options are able to capture the presence of uncertainty,

limited information and the existence of different, but valid, development scenarios.

32 Dixit, A. K. and Pindyck, R. S. 1994, Investment under Uncertainty, Princeton University Press, Princeton, N.J

The development of an oil field can be described as followed33:

Exploration and appraisal

Extent of investments needed in acquiring seismic data

Extent of contract partnership (risk sharing)

How many exploration wells should be done

Development

How many, where and in what order should the wells be drilled

Kind of platform

How many platforms, rigs should be needed

Work-over

How many injectors should be drilled

The size of the processing facility

Are there adjacent fields waiting to be developed?

Pipeline

Production

Are there any areas of the field that are un-swept?

Should we farm out (divest)

Existing production wells into injection wells

Extend the life of the field

Re-entering wells to improve performance

Decommissioning (abandonment)

Environmental cost of closing down etc.

4.1.4.3. Functionality of Real Options

As mentioned, option pricing methods are superior to traditional DCF approaches

because they explicitly capture the value of flexibility. However, one of the

difficulties inherent in the real-option technique is the computational difficulty.

Modelling and valuing real options is more difficult than valuing and modelling

33 www.schlumberger.com, Schlumberger on real options in oil and gas

standard cash flows. It may be that the bundles of assets and opportunities that

companies own cannot be practically valued as options.

As shown above, the process of extracting oil is made up by numbers of different

options. At every step there is an option, or a strategic choice to be made. Looking

at the company as a whole, the number of options would be tremendous. If we were

going to use real options, we would have to choose the most important options and

factors affecting these options. In our case, we do not have necessary information to

perform a sound real option analysis. We have been in contact with Hydro and

other companies in the oil industry, but because of confidentiality considerations,

the companies are not willing to release numbers related to historic investments.

Another shortcoming is, as mentioned earlier, that the real option theory is not fully

developed to valuate whole companies. However, in cases as within the petroleum

industry, with high amount of future flexibility, there is reason to believe that real

option techniques eventually will replace traditional DCF methods. Recently, there

has also been an increased attention from business valuators, whom believe that real

options analyses can lead to more realistic valuations than traditional methods. A

survey study of FTSE 100 companies, by Busby and Pitts (1998), found that whilst

few firms have formal procedures for evaluating real options, some have rules of

thumb for qualitatively assessing them.

4.2. Evaluation and Selection of Valuation Methods

Plenborg (2000) and Copeland & Keenan (1998) use a range of different criteria to

differentiate between the valuation models. In table 3, different valuation models are

evaluated in accordance to the most important criteria. The table does not give a

sophisticated picture of the different models, but altogether it summarises the major

differences.

Table 3: Evaluation of Valuation Methods

Precision in estimate

Risk adjusted

Multi- period

Functionality

Captures flexibility

Market valuation methods ( ) Book value methods Income based methods

Real options Source: Plenborg (2000) and Copeland and Keenan (1998)

The multiples (market value methods) are relatively unreliable. Kaplan and

Ruback (1995) conclude that estimates done by future income methods are far

more precise than outputs from multiples. Equally, Frankel and Lee (1996)

conclude that the EVA method (among income based methods) predicts the

variation in the stock market far better than the multiples. The major difficulty

using multiples is to find appropriate comparable businesses and indicators.

However, the multiples are often used because of their functionality; easy to

use and easy to understand. It is also possible to incorporate risk adjustments

by adding or discounting according to market factors, but these adjustments

does not hold theoretically.

As seen in the table, the book value methods are scoring lowest in this context.

The book value methods are functional and easy to understand, but they are

not theoretically reliable and useless for companies with more than tangible

assets34. Book value methods also depend on the accounting techniques used

and reliance on the financial statements. Accounting techniques differ across

countries, and statement data may be subjectively influenced by accountants or

management, as we have recently seen in companies such as Enron and

Worldcom.

As mentioned in the evaluation of multiples, known researches conclude that

income based methods are far more precise than multiple methods. In addition,

34 Hawawini, G.A. 2001, Finance for Executives: Managing for Value Creation, Second edition, South Western; College Pub

there is found a strong correlation between discounted cash flows and the

actual market value of companies35. As the table shows, income based methods

(in general) are accurate, risk adjusted, functional and may be employed for

multiple periods. Comparing the different models of income based valuation,

the finance literature has argued in favour of the DCF approach for business

valuation since it is not affected by accounting methods36.

The real option methods are, as seen in the table, able to incorporate flexibility

and risk and can be used for multi period valuations. Real options are also easy

to understand. Despite that real option theory is very promising, real option

theory is still not fully developed and cannot be used in the valuation of a large

company as Hydro. However, in the valuation of oil investments real option is

being more and more used.

Oil companies are primarily valuated by the use of multiples or income based

methods. Warburg Dillon Read (1999) argues that these kinds of analysis in general

are not able to reflect the real value of oil companies. “He stated the following reasons;

long lead times in exploration and production (pay-back), oil and gas price

sensitivities that create volatility in the short term income and different accounting

practices amongst companies”. However, as he states, “long term discounted cash

flow methods should be able to overcome these problems and most analysts agree that

the DCF method is most suitable for valuating oil companies”. Like the book value

method or other accounting based methods, DCF does not have problems with

unreliable accounting numbers.

Based on the discussion above, we have chosen to use the DCF approach in the

valuation of Hydro. We are also using multiples as a supplement to our DCF valuation.

35 Copeland, T., Koller, T. and Murrin, J. 2000, Valuation Measuring and Managing the Value of Companies, Third edition, McKinsey & Company Inc. 36 Copeland, T., Koller, T. and Murrin, J. 1990, Valuation Measuring and Managing the Value of Companies, Third edition, McKinsey & Company Inc.

5. Strategic Analysis

The aim of this chapter is to analyse Hydro and its business environment from a

strategic point of view. We start by analysing the macro environment of the petroleum

industry using PEST as conceptual framework. Secondly, we analyse the petroleum

industry in general using Porter’s Five Forces. In the third section, we analyse

Hydro’s exploration and production segment using value configuration theory, as well

as a brief analyse of their energy and oil marketing segment. The chapter ends with a

SWOT analyse.

5.1. The Macro Environment37

In order to assess the future development of the oil industry, it is important to

understand the macro environment of the industry. In this section, we analyse the

macro environment by using the PEST framework.

5.1.1. National and International Economy

The development of the international economy is a crucial factor for the oil industry,

since the demand for energy is largely driven by economic growth along with rising

population. Deprecation in the international economy decreases the demand for

energy and especially the demand for crude oil, since crude oil is heavily used in the

transportation sector and in the production to provide heat and power. Decrease in

demand of oil leads to lower oil and gas prices followed by decrease in the profits of

oil companies. Figure 8 shows the historical and expected distribution of oil from

1970 until 2020.

37 This part builds extensively on the work of Energy Information Administration (EIA)/International Energy Outlook reference case 2002 and 2003.

Figure 8: Distribution of Oil Consumption 1970 - 2020

Source: International Energy Outlook 2002

The industrialized countries’ demand after oil has stably increased through the 1980s

until present, while, during the same time horizon, developing countries have more

than doubled their consumption of oil. This is connected with the fact that

industrialized countries have been utilizing larger quantities of oil for a long time,

while developing countries have not. Worth to notice is that developing countries are

expected to have the most robust growth in natural gas demand by 3.9 percent per

year between 2001 and 2025, compared to an increase of 2.2 percent annually among

the industrialized countries.

Figure 9: World Natural Gas Consumption (left) and Natural Gas Consumption

in the developing world, 1970 - 2025


The main reason why the consumption of oil and gas has been growing fastest among

the developing countries is because they are expected to have the strongest growth in

GDP (see figure 10). In other words, the demand for oil and gas are affected by

regional differences in economic growth. World GDP is projected to be expanding by

an average of 3.1 percent per year towards 2025.

Figure 10: Growth Rates in GDP from 1993-2002 Distributed between

Developing Countries and the World

0,00

1,00

2,00

3,00

4,00

5,00

6,00

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Developing countries: UN classification World

Source: World Bank Indicators Database

Differences in growth and interest rates between countries are reflected through the

exchange rates. As oil prices are quoted and traded in USD, oil importers and

producers are heavily exposed to changes in the exchange rate between local

currencies and USD. Opposed to crude oil, gas prices are quoted and traded regionally.

5.1.2. Technology

The oil and gas industry is an extremely technology-based industry and technology is

one of the most crucial drivers. Exxon Mobil expresses the following on their web site;

“technology is our lifeblood”38. New technology innovations in the upstream process,

such as new methods of finding resources (exploration) and efficient production

38 www.exxonmobil.com

methods have made it possible to extract more and to improve the recovery of oil and

gas fields, as well as to revert to drilling sites that was considered exhausted. Due to

this, the profits of each field have increased significantly. The technological

improvement has been especially important to exploration and extraction of oil and

gas from ultra deep-water reservoirs, where the technical challenges have been most

difficult.

Technology is also an important driver in the midstream (undersea oil and gas

pipelines at significant water depth from offshore fields into land etc.) and

downstream process (refining process). To summarize; companies that are able to

locate the best fields for exploration, where to target their exploratory wells, and how

to interpret their results with great precision, at low cost, and in less time than its

competitors will have a superior competitive advantage.

Considering the examples above, it is reasonable to assume that technology will have

enormous impact on future development of the oil industry, due to reduced resources

of oil and gas and that new discoveries is a expected to be at extreme depths, where it

has not been profitable or technological possible to gain access before.

5.1.3. The Political System

Governments have significant influence on the actors in the oil industry, since they

are the owners of the assets and controlling the exploratory drilling by awarding

concession rights to oil companies. A concession right grant an exclusive right to

explore and produce petroleum within a specified geographical area at a given time

horizon. Oil companies have to pay large upfront amounts for concession including a

special tax on petroleum ventures. The governments are therefore able to control the

future world oil supplies. We have earlier mentioned OPEC, an alliance of some of

the largest oil producing countries in the world that control near 70 % of the world oil

resources (Saudi Arabia (25%), Iraq (11%), United Arab Emirates (9%), Iran (9%)

and Kuwait (9%))39. With falling production and resources in countries outside of the

39 BP Statistical Review of World Energy. June 2003.

Pacific Ocean, it is expected that OPEC will have even greater influence on the oil

market in the future.

Moreover, it is important to notice that governments charge the oil companies with a

special tax on petroleum, which constitutes a potential risk for oil companies if taxes

are changed in an unfavourable manner. Currently the marginal taxation rate for

petroleum activity on the NCS is 78 percent (corporate tax rate 28% + special tax on

petroleum ventures 50%). Compared to the rest of the world this is one of the highest

taxation rates on petroleum activity. However, it is an ongoing debate whether to

reduce the special tax on petroleum or not in order to stimulate the exploration

activity. As the political views are separated, we do not except the taxation rate to

change in the nearby future.

5.1.4. Environmental Issues

Environmental issues are playing a more and more important role for the oil industry,

which is said to be the most polluting industry in the world. It is no secret that the oil

industry has caused several scandals over the years including oil leakages from huge

oil tankers into the ocean and considerable pollution from oilrigs. During the last

decades it has become custom practise that the polluter pays for environmental

damages, which of course is a load for the industry. At some stage in the negotiation

for concessions rights, it is therefore normal to clarify aspects regarding how to clean

up the area. Further, the oil companies are imposed to deposit parts of the profit to

rehabilitating the licensed areas.

Back in 1997, large developed countries (excluding the US) agreed to a set of

standards for the environment by reducing CO2 gasses gradually through the Kyoto

Protocol40 , which will imply reduced consumption of oil in advantage for more

“greener energy”. Such restrictions will affect the oil industry in the long perspective

and the demand for oil may stagnate.

40 The Kyoto Protocol is currently not a legally binding agreement.

Stronger environmental restrictions will also entail heavy investments in advanced

technology to reduce pollution to a minimum and especially in exploration in

sensitive areas such as in the fish rich parts of the Norwegian Sea and Barents Sea.

5.1.5. Demographic Factors

Demography is important for the oil industry, as population growth increase the

demand for energy and thereby oil and gas. According to estimates by World

Development Indicators (2003)41, the average annual growth is expected to increase

by 1.5% from 2001 until 2015. Developing countries will experience the highest

growth both in population and economically. It is therefore reason to believe that

consumption of oil and gas will have a minor demographic shift. However,

transportation of oil and to some extent gas liquids is not considered as a problematic

issue.

5.1.6. Social and Culture Factors

As mentioned, demand for energy has increased gradually during the last decades.

However, the different sources of energy have also changed during this period. For

instance, the consumption of crude oil has fallen from about 50% in the 1970s to

about 40% presently compared to the total energy consumption (see figure 11).

According to IEA, it is expected that oil consumption will remain at the current level

towards 2025.

41 www.worldbank.org

Figure 11: World Energy Consumption by Energy Source


Social considerations and responsibility for the society have resulted in increased

focus on alternative energy sources (solar energy, natural gas, wind energy, etc) or

what we called “green” energy earlier, which may change the production mix of

energy in time. In other words, people in general tend to be more concerned about

environmental issues and value a healthy society. As new and more “environmental

friendly” energy sources develops, and the cost of these sources are reduced, there is

reason to believe that the production mix of energy would change in disfavour of oil.

According to Herrick (2001), renewable sources may account for 50% of the world’s

energy needs by 2050.

5.1.7. PEST Analysis

We have summarized our findings in the figure underneath.

Figure 12: Major Findings from the PEST Analysis

National andInternational Economy

- Largely driven by economic growth

- Exposed for changes inthe exchange rate

Petroleum IndustryTechnology- Extremely technology driven

The Political System-Governments have huge impact on the oil industry

- OPEC

Social and Culture Factors- Change in the energy mix

Demographic Factors-Minor demographic shift in consumption of oil and gas

Environmental Issues-Environment restrictions

threaten the industry

5.2. Analysis of the Petroleum Industry42

As mentioned in the introduction to Hydro, Hydro is divided into two business

segments; Exploration and Production (E&P) and Energy and Oil Marketing

(E&OM). Nearby 90 percent of the division’s operating income is derived from the

E&P segment. The E&OM segment, with exception of the power business segment, is

margin-based. The analysis will therefore focus on the E&P segment (petroleum

industry). The following section builds on Porter’s Five Forces Model (1980).

5.2.1. Strength of Suppliers

Incumbent firms in the petroleum industry have two different types of suppliers: those

who supply the industry of prospects and those who supplies supporting and related

industry.

5.2.2. Suppliers of Prospects

According to Stoneham (2000), suppliers have great impact shaping the petroleum

industry. Suppliers, in this context referred to as oil producing countries, have great

bargaining power since crude oil is a limited resource. The huge amount and the easy

accessibility of oil resources in the Middle East countries, gives them a particularly

strong bargaining power, since these resources are less risky and more popular among

oil producing companies (in this context referred to as the customers). In total, it is

about 60 oil producing countries in the world43.

5.2.3. Suppliers of Supporting and Related Industry

Beside the ownership of concession rights (prospects), there are numbers of

supporting industries. Crucial supporting industries are:

42 Cooke, M and Kinnersley, D. 2000, An Overview of the Global Oil Industry 2000, PriceWaterhouseCoopers, The Petroleum Group ABAS TICE Energy; Flemmen, Kapacinskas, Liusetas, Sklinda and Zaleski. 2001, Strategic Analysis of Norsk Hydro, Aarhus School of Business 43 BP Statistical Review of World Energy. June 2003.

Hardware industry

Software industry

Yards and offshore industry

Each of these industries has sub industries, as the petroleum industry is very

complicated and is relaying on many sub suppliers representing various industries. In

each of the mentioned industries, there are plenty of both small local companies and

large global players. This gives the oil companies a competitive advantage, because

suppliers do not represent a consolidated group, which could give them additional

bargaining power. There is, however, a noticeable process of integration, especially in

the drilling and completion equipment industry. An example can be the alliance

between Technip and Coflexip Stena Offshore 44 . There is little or no product

differentiation in exploration technology (e.g. 3D and 4D seismic mapping) reducing

the switching costs for the buyers which in turn reduces the power of the suppliers.

However, development solutions procured by upstream actors are usually unique for a

given project, introducing an element of “differentiation”. This could segment the

suppliers of development solutions introducing higher switching costs and more

bargaining power to suppliers.

5.2.4. Strength of Customers

We look at the strength of customers of oil and gas individually.

5.2.4.1. Oil

The oil price is determined globally according to the relationship between demand

and supply for oil. The willingness to pay is more or less the only bargaining power

the customers have. However, large consumers as USA, China and India that consume

respectively 25, 7 and 6.9 percent of the total world oil consumption, may be able to

execute some degree of bargaining power.

44 In France, the two leading companies Technip and Coflexip Stena Offshore have merged in order to close the gap with the American industry giants. Technip and Coflexip complement each other in the industry. Whereas Technip primarily builds refineries and gas liquefaction plants, Coflexip has concentrated on equipment for the extraction of oil and gas.

5.2.4.2. Natural Gas

Natural gas is traded more regionally than the crude oil, and the prices differ from

region to region. At this point, the only well developed markets for natural gas trade

and commerce is in the US and to some degree in the UK. In other markets, natural

gas deliveries are therefore mostly based on long-term contracts, due to the reasons

that there is no single market for natural gas trade and secondly that transportation of

gas needs extensive investments in pipelines etc. Long-term contracts are often linked

to the price of oil.

However, in the case of Hydro, Europe is the largest consumer of gas in the world and

the demand is increasing. We therefore conclude that the bargaining power of

consumers is not particularly strong in Europe.

5.2.5. Threat of New Entrants

Although the petroleum industry seems to be an attractive one, we conclude that the

threat of new entrants is rather low because of high entry barriers.

The industry is capital intensive. Oil and gas are state owned resources and

governments tend to choose operators that have the best reputation in order to

ensure that the production of oil and gas are done in the most efficient and

profitable way. Major and recognized players have, because of their financial

strength and reputation, a better chance of acquiring the most preferable

licenses. This makes a possible penetration of new entrants through the

“license acquisition/trading-process" extremely difficult.

Very high fixed entry costs. Most of the major oil companies are vertically

positioned in almost all downstream-, midstream- and upstream activities, and

in order to compete in an efficient way, it requires enormous investments. This

makes it almost impossible for new entrants to enter the petroleum industry.

Long-term contracts. As most of the world’s oil reserves has already been

discovered and are controlled by well-established oil companies, it is difficult

for potential entrants to gain access to oil reserves when entering the petroleum

industry.

Necessary know-how. All oil companies have more or less access to the same

technology. However, experienced oil companies have an advantage in

understanding and applying complex technology. A potential way to overcome

the lack of experience is by farming-in as partner in concessions or by merger

or acquisition with an existing oil company.

5.2.6. Barriers to Exit

The barriers to exit from the petroleum industry are considered low despite high fixed

costs. Relinquishment of concession rights for example are easily sold in an efficient

secondary market for trading licenses as competitors are always interested in gaining

access to reserves and to strengthen their portfolios. The petroleum industry can

therefore be, according to Porter’s profitable matrix, characterized as an industry with

high stable returns.

5.2.7. Threat of Substitutes45

Substitutes to crude oil are a function of the crude price; substitutes become important

only when crude prices are high. Substitutes are not a threat as far as availability of

conventional crude is concerned. With the current production ratio 46 and proved

reserves in the range of 1000 billion boe, it will be sufficient reserves of conventional

crude oil around the globe to last another 40 years47. In addition, the technology

improvements are likely to outpace rising depletion costs for at lest the next decade48.

45 IEA, 2002, International Energy Outlook 2003, The Energy Information Administration, USA 46 If the reserves remaining at the end of the year are divided by the production that year, the result is the length of the time that those remaining reserves would last if production were to continue at that level. 47 BP Statistical Review of World Energy. June 2003 48 Shell International, 2001. Energy needs, choices and possibilities. Scenarios to 2050, London.

As it appears from figure 11, crude oil has been and will be the primary energy source

over the next two decades.

Natural gas is expected to have a higher growth rate than crude oil, due to expectation

that natural gas will gain substantial market share in the industrial, residential and

commercial sectors. This switch in use of energy source is an outcome of that natural

gas contains lower carbon dioxide emission, which makes the gas prices competitive

due to substantial lower carbon dioxide taxes and the fact that it is more

environmental friendly than oil.

The world coal consumption is expected to face a slight drop in its share of total

energy consumption, primary because resources are mainly concentrated in a few

countries and will become increasingly complex and distant from markets. The costs

of exploiting and using (environmental regulation) coal are also affecting the

competitiveness. The consumption of coal is expected to grow in this region, because

of large occurrences of coal in India and China, where the labour is cheap and that this

industry is governmental owned, which create many jobs. This means that extraction

of coal will continue in China and India at full power, so long as the Kyoto Protocol is

not a legally binding agreement.

Renewable resources such as wind power and hydroelectricity are expected to slowly

increase their market share in the future. However, as long as the absence of

significant government policies aimed at reducing the impacts of carbon-emitting

energy sources on the environment, it will be difficult to extend the use of renewable

resources on a large scale. So long as these products still have relatively high

production costs, they will not be economically competitive to fossil fuels. In addition,

the performance or yields of some of these products are in some cases, not yet as good

as the performance of oil and gas, and widespread use of solar and wind will require

new forms for energy storage.

Nuclear energy expansion has stalled in OECD countries due to that nuclear energy is

a relatively expensive option for electricity generation compared to natural gas or coal,

particularly for nations with access to inexpensive sources of coal and natural gas. In

addition, there is strong public sentiment against nuclear power in many parts of the

world, based on concerns about plant safety, radioactive waste disposal, and the

proliferation of nuclear weapons. Nuclear power as a substitute product in the future

is therefore questionable. It is expected to be wiped out wholly or partly within the

next 50 years, if not technology advances could make a new generation of nuclear

supplies competitive.

We can conclude that substitute products do not represent a real threat at the time

being. However, as the intensive search for alternative energy resources continues,

more environmental friendly energy resources may constitute a threat in the long

perspective. According to Shell International (2001), hydrogen fuel cells are the

substitute to oil and gas that have most potential.

5.2.8. Competitiveness of the Petroleum Industry

The competitive environment in the petroleum industry can be described as having

few major and strong players and several small players with moderate power

worldwide. This is as result of enhanced rivalry among competitors, due to the

increased need to push for profitability, hence cut costs in all possible ways.

Moreover, hydrocarbons is a limited resource and gaining position as operator for as

many fields as possible is crucial, as new concession rights is based on oil companies

track record as field operator. This has forced major oil companies to turn to

acquisitions, mergers, and alliances as a constructive way of overcoming competitive

constraints.

Due to the recent nine mergers among the largest petroleum companies (during 1998-

2001) the concentration ratio H-index has raised from the 1997 level of 389 points to

583 points49. The improved efficiencies of the mega firms (Exxon Mobil, BP, Shell

and TotalFinaElf) have enabled them to operate close to breakeven oil prices as low

as USD 11-12 per barrel50. However, the mega firms do not have proprietary control

49 Weston, J. F., Johnsen, B. A., Juan A. S. 2001, Mergers and restructuring in the oil industry, Journal of Energy Finance and Development 4, 149-183 50 Ibid.

of technology or know-how51. Oil service companies make such knowledge available

to any industry participants.

The majors’ economy of scale advantage should normally indicate that they would

outperform the smaller companies, but since oil is a non-renewable resource, the

return that is associated with crude oil, the “Petroleum Rent”, is of vital importance52.

This return can be very high for certain producers, since the marginal cost for

producing crude oil varies a lot form region to region. The marginal cost in the North

Sea is around USD 10 per barrel, versus the same cost can range from USD 1.50 to

USD 5.50 per barrel of oil in the Middle East. In other words, the margin in the oil

industry is normally larger than in traditional industries, but at the same time, the risk

associated with their future cash flow is higher, as the oil price historically has been

very unstable.

51 Ibid. 52 Hannesson, R. 1998, Petroleum Economics: Issues and Strategies of Oil and Natural Gas Production, Westport, CT: Quorum Books

5.2.9. Five Forces Analysis

We have summarized our findings in the figure underneath.

Figure 13: Summary of the Five Forces Analysis

New Entrants- High entry costs

Entry unlikelyto happen

Petroleum Industry

Substitutes- No Substitutes

Customers-Homogenous products

and fixed world priceLow bargaining power

Suppliers- Exhaustible resource

Low bargaining power-Number of supporting

industriesHigh bargaining power

Competitiveness-Many companies

-Homogenous products-High reputation pressure

Rivalry high

5.3. Value Configuration Analysis

The intent of this chapter is to determine if Hydro has any competitive advantages. As

mentioned in chapter 3 the exploration and development unit plays the most essential

role in an oil company. The following analyse will therefore focus on their

competitive position in the upstream oil industry. We notice that the value shop model

only will be used as a framework of accepted wisdom, as much of the information

needed builds on internal data, which is difficult to get, even internal.

5.3.1. Allocation of Cost Drives in Exploration and Development Activity

A rough estimation of both the cost structure in the exploration and development

shops illustrates the fact that the execution activity is the most significant costs-

driver53, whereas the significant part of the value is delivered from the problem-

solving and choice activity where the decision to drill or field concept is made. In

other words the activity that makes the choice costs less, delivers most part of the

value.

5.3.2. Allocation of Value Drivers in Exploration Activity

The most important driver in exploration is the process of picking the right concession

to explore. Following the selection process, the wanted concession is secured through

an acquisition of a license. As mentioned in chapter 3, success is derived from the

value of exploration, where outstanding reputation in exploration improves the shop’s

ability to bid successfully for the most promising concession.

5.3.3. Determination of Hydro’s Position in Exploration

It is difficult to gauge the relative reputation/performance of Hydro as an individual

actor because of the complexity and the variable nature of the drilling business and

53 See appendix 2; These cost figures is based on the upstream oil industry on the NCS in the period 2002-2003 (Norway Statistics 2004), due to little information in the annual report to make the analyse. However, we believe these cost figures is illustrative for Hydro as most of their operations is located on the NCS as well as they are the second largest operator on the NCS.

non-availability of sufficient data. However, based on our estimation, the average

success rate in exploratory drilling for Hydro has been nearly 40% during the last five

years54. This is higher than the average success rate for the industry at NCS that has

been around 32 percent, which also is higher than both the UKCS and the US success

rate 55 . In connection to this, it should be noted that Hydro’s internationally

opportunity has shrunk substantially, due to exploration failures during the last two

years.

The most important to notice from our estimation, is that Hydro’s success rate has

improved significantly from 1998 until today. The improved success rate indicate first

of all greater value in solving the problem of finding commercial quantities of

hydrocarbons for their clients, but also the quality within Hydro’s shop due to their

ability to attract, train and retain the best professionals and development of new

detection techniques.

5.3.4. Allocation of Value Drivers in Development Activity

A key driver for the operator/developer of an oil field is picking right partners. This is

due to the large sums that are involved and that the operator who accomplish a well-

executed field development that performs as or better than expected will find its

reputation enhanced and could be rewarded with more operator titles56. In other words,

a crucial driver is the sharing and interrelationships between the operator and the

partners.

5.3.5. Determine Hydro’s Position in Development

It is difficult to determine Hydro’s position in development, beside to notice that

Hydro currently is the operator for eight fields and is the second largest operator on

the NCS. In addition, Hydro’s two latest projects Fram and Grane were below budget,

respectively 15 percent and NOK 1.5 billion, and that the Grane project was ready for

use three weeks ahead of schedule. This indicates good project organization, 54 See appendix 3 55 NPD. The Petroleum Resources on the Norwegian Continental Shelf, Norwegian Petroleum Directorate, 1997 February 56 Barry, R. 1993, The Management of International Oil Operations, PenWell Books

technological advances, and the ability to utilize resources efficiently. In connection

to this, it is important to mention that Hydro is the operator for the development of

Ormen Lange, which is one of the worlds most technological challenging gas projects.

To conclude, it seems like Hydro have enhanced some reputation in the market as an

operator and may have increased their reputation through their latest achievements.

Internationally, though, Hydro is currently only engaged as partner and not as

operator. However, it should be noted that Hydro is invited as partner (10 – 15 percent

share in the field) in a Russian prestige project as the first foreign oil company, due to

their experience with the Ormen Lange field. The Shtokman-field is the world largest

gas field and is supposed to produce as much 90 billion cubic meter each year.

5.3.6. Conclusion

As stated by the management, Hydro’s main platform for its competitive advantage

consists of experience built up over 30 years in the North Sea, as either an operator or

a partner. The company intends to strengthen its position outside the NCS and has for

several years transferred its expertise to challenges outside the NCS. Several

considerations should be noted in this respect.

From a technological point of view, Hydro is a highly innovative player on its market

segment. The company has unique experience and position stemming from its role in

developing the offshore oil industry on the NCS, which has one of the toughest

maritime climates in the world. Hydro is recognized for its ability to choose the right

technology for the particular challenge in question, either by using technology that

they have successfully used before, or by using new technology that has just left the

drawing board. Sustaining a high pace of innovation Hydro has managed to develop a

reputation in terms of technical expertise and has expertise in major development

projects, which seem to be a significant competitive advantage. This experience has

made Hydro an attractive partner in the development of demanding offshore projects

in the Gulf of Mexico, Canada and Angola, as well as maintaining their position as a

significant operator on the NCS. Measured as an equity producer Hydro is only

ranked as a medium sized company, however, looking at their size of operations

Hydro is the 14th largest operator in the world57. Moreover, if we just look at offshore,

Hydro holds the 5th place within their niche58.

5.3.7. Hydro Energy and Oil Marketing

In regard to the Hydro Energy and Oil Marketing unit, Hydro is the second largest

retailer of petroleum products in Scandinavia with roughly 16% market share,

additionally they have interesting positions in the Baltic countries. Hydro’s stations

are mainly based on a full-service concept, due the consumer-buying pattern where

people increasingly using petrol stations to purchase food and daily commodities.

They have also established several unmanned stations in order to cut costs as result of

the keen price competition in the Scandinavian market, which have brought earnings

down to more or less a break-even level. The keen price competition is also reflected

in the retail marketing business around the world. The downstream markets have

experienced worldwide margin erosion and major integrated oil companies are

consolidating their positions or exiting the industry.

Their hydroelectric power system with a combined capacity of 10.3TWh/y is the

second largest system in Norway, and the fifth largest in the NordPool system59, after

Vattenfall, Fortum, Statkraft and Sydkraft.

57 www.hydro.com 58 ibid. 59 NordPool is a power exchange including Denmark, Norway, Sweden, and Finland. These four countries have liberalised their power markets and through the joint exchange, they have established a joint power market.

5.4. SWOT

The following table underneath illustrates the strategic position of Hydro and is based

on the well-known SWOT analyse.

Table 4: SWOT Analysis of Hydro

Internal Strengths Internal Weaknesses

Technological know-how

Unique experience in offshore drilling

Well build reputation

Experienced workforce

Well positioned on the NCS

Valuable partner in demanding areas

Dependent on oil and gas prices

High marginal costs in the North Sea

Dependent on exchange rates

The portfolio is not extensively

diversified

Not an extensive international record and

financial ability for large investments

High costs associated with exploration

External Opportunities External Threats Economic boom

Gaining concession rights nationally and

internationally

Partner in demanding areas

Political (lower taxes)

Global recession, falling oil price and

weak USD

Few growth areas

North Sea a mature region

Political (higher taxes)

Substitutes

Environmental restrictions

The SWOT-analyse clearly emphasize Hydro’s strong position on the NCS, due to

their unique experience and technological know-how. Further investments in R&D

and innovative approaches to deep-water drilling are needed to maintain Hydro’s

competitive advantage and to further establish its position as an important player in a

fast changing environment. This is due to the following threats:

The competition for new reserves is fierce while few growth areas are

available. Growth areas include Russia, West Africa and Latin America. At the

other hand, many of the countries with the largest hydrocarbon reserves, such

as Saudi Arabia, Iraq, Kuwait, etc., are not accessible for western oil

companies at all.

All major international oil companies struggle with production growth and are

aiming to keep up their reserve replacement rate. As a result, Hydro will have

to compete fiercely for attractive concessions with the rest of the sector.

Hydro has a disadvantage not being among the largest oil companies. Super

majors, such as Shell etc, have a more extensive record of accomplishment and

the financial ability to make large investments, which make them attractive

partners to reserve holding countries. In addition, the investment portfolios of

the super majors are more diversified than the portfolios of smaller companies.

So on, the risk they add to their portfolio by acquiring an additional project is

smaller than in the case of Hydro. This means that the super majors enjoy a

lower marginal cost of capital that allows them to accept lower returns on new

projects and still create value for shareholders.

Going forward, we believe that Hydro is “stuck in the middle”, with limited strategic

options. The poor exploration success of the last two years means that its international

opportunity is smaller than initially believed. On the other hand, not expanding abroad

is not an attractive option given the long-term prospects on the NCS. Given the

limited international reserves available for western oil companies and Hydro’s weak

competitive position versus the super majors in competing for these reserves, we

believe the outlook for Hydro’s activities abroad is generally weak, though their

eventually partnership in Russia could indicate a turning point for Hydro at the

international shelves.

Further, fluctuations in exchange rates and in oil/gas prices will constitute a risk for

Hydro’s future performance, as well as political encroachments. With regard to

political encroachments Hydro’s operations are mainly concentrated in relatively

stable political areas. We believe therefore that this do not constitute a substantial risk

for Hydro.

6. Financial Analysis

Strategic analysis of Hydro cannot be conducted without having a sound and in-depth

understanding of the historical financial performance and visa versa. In our

assessment of Hydro’s financial condition, Hydro’s profitability, liquidity and

solvency ratio are considered and compared against a peer group.

6.1. Peer Group

An optimal peer group is difficult to find, however, we have chosen Statoil, Repsol

YPF and ENI S.P.A., as these are the most comparable companies in the European oil

sector in terms of size (i.e. reserves and production, see figure 26), as well as regarded

to group structure and the environment they operate in60.

6.2. Profitability Ratios

As seen from table 5, Hydro earned an operating profit of 18.4 cents on each

Norwegian coin invested in the business. An ROIC of 18.4% is excellent. This is

almost double of the historical 11% equity return of the S&P 500, and roughly

quadruples the risk-free rate of 4.52% available on a 10-year US Treasury. Given the

competitive forces in the oil industry and the fact that Hydro has performed well

above S&P 500 index the last four years, this confirms that Hydro is performing on

the competitive edge. Further, it also implies that the competitive advantage may be

sustainable for many years into the future.

However, as seen from appendix 4, ROIC developed negatively from 26.6% in 2000

to 16.7% in 2003. This is a caused by a drop in the EBITA margin from 39.6% to

35.3%, whereas the capital turnover has been relatively stable. In other words the

60 See appendix 26 (income statement and balance sheet)

costs have increased relatively more than its revenues. Explanations may be that

Hydro is having a harder time dealing with the competition or/and fluctuations in the

exchange rate and in commodity prices. However, compared to its peer group, Hydro

is clearly performing in the upper class, which could indicate that their concession

rights are entered on sensible terms under a competent management.

Table 5: Peer Group Comparison

Average (2000-2003) Hydro Statoil ENI SPA Repsol YPF

ROIC 18.4% 8.8% 14.0% 18.5%

EBITA-margin 35.0% 21.2% 19.6% 13.5%

Capital Turnover 1.16 1.41 1.12 1.35

Source: Company data, Reuters.com

6.3. Liquidity Ratios

Hydro’s current ratio in 2003 was 1.12 and 1.02 based on a four-year average

compared to 1.06 and 1.00 in the peer group, whereas the quick ratio was 0.87 and

0.93 compared to 0.93 and 0.86 in the peer group61. Hydro’s current ratio indicates

that Hydro has enough current assets to meet its short-term obligations, and as it can

be seen from appendix 4 Hydro’s ability to meet short-term obligations has improved

slightly between 2002 and 2003. Their quick ratio indicates that cash and cash

equivalents now available would cover only eighty-seven percent of expected year –

ahead liabilities, which at first glance might seem alarming as it shortfall below 100%.

However, the quick ratio is a stringent test that compares a year’s worth of obligations

with cash that, for all practical purposes, is already in the bank. Current ratios and

quick ratio is considered adequate when they respectively excess 2 and 1. According

to Johnston (1992), is it normal that both of the ratios are getting fairly below 1.2 for

the oil industry. We can conclude that Hydro’s liquidity is comparable with its peers

and has improved for the past few years, which indicate their condition is in the line

with oil industry.

61 See appendix 4

6.4. Solvency Ratios

Hydro’s current equity-to-total liabilities (ETL) ratio is 0.54, which is in line with its

peers, whereas their current total debt equity (D/E) ratio is 0.80, compared to the peer

group of 0.6462. As seen from appendix 4 has both the ETL and D/E ratio throughout

the period improved, which point out that Hydro has become more equipped to meet

future deficits and are not so vulnerable to meet possible future crisis.

6.5. Conclusion

Based on the calculations above it seems like Hydro’s overall financial condition is in

the line with its peers and developing in the right direction. Positive factors have been

increased hydrocarbon production and favourable commodity prices. Hydro is also

showing very good results on some of the analysed ratios, which supports our earlier

conclusions regarding competitive advantage.

62 See appendix 4

7. Estimation of Oil and Gas Prices

Oil and gas are Hydro’s core business products and the prices of these products are

crucial to Hydro’s operating results and profitability. In order to determine the value

of Hydro, it is necessary to understand these two markets and be able to give a sound

prediction of future oil and gas prices. This is not an easy task while prices for oil and

natural gas are subject to wide fluctuations in response to changes in general

economic conditions, changes in the supply and demand for oil and natural gas,

market uncertainty, and other factors that are beyond ours and Hydro’s control. These

factors include political conditions in oil producing regions, particularly the Middle

East as well as the ability of the members of the Organization of Petroleum Exporting

Countries (OPEC) to agree and maintain oil price and production controls.

The analysis in this chapter is mainly concentrating on the oil market, since the oil

market is more mature than the gas market and also traded globally. Moreover, both

markets are influenced by the same factors and the price of natural gas tends to follow

the price of oil63. We have further chosen to emphasize the understanding of these two

markets and rely on professional analysts in determining future oil and gas prices.

In the first section, we reveal the most employed global market models forecasting oil

prices and discuss their reliability. Secondly, we briefly discuss the fundamental

drivers affecting the oil prices and describe the historic development of world oil

prices. In the third part, we forecast the most important market factors; supply and

demand, and give an overview of the market uncertainties that may affect these

factors in the future. Fourthly, we determine future oil prices by using forecasts from

IEO200364. Finally, we present the gas market and forecast the future development of

the gas market including gas prices.

63 www.hydro.com 64 Our analysis is mainly inspired by the IEO2003, an analysis that forecasts energy supply, demand, and prices through 2025. The forecasts are categorized into three scenarios; reference case, high price and low price. IEO2003 is prepared by US government’s Energy Information Administration (EIA). For extensive information, see www.iea.gov.

7.1. Survey of the Most Important Oil Market Models65

A variety of studies have aimed to explain OPEC’s production behaviour in response

to changes in oil prices, production level and capacity changes, especially during

abnormal and transient periods, but also during normal times. The majority of these

studies deal with OPEC as a profit-maximizing cartel that seeks monopoly profit

(cartel models), while other studies argue the opposite (non-cartel models). According

to these studies the market is the main determinant behind fluctuations in the oil price

and can be explained by other factors than cartelization. Table 4 gives an overview of

some of the most used oil market models.

Table 6: Oil Market Models

Non-Cartel Models Authors Cartel Models Authors

Target Revenue Model Teece (1982) Monolithic Cartel Models Gilbert (1978)

Pindyck (1978)

Property Right Models Johany (1979, 80) Two-part Cartel Model Hnyilicza and Pindyck

(1978)

Competitive Model McAvoy (1982) Three-part Cartel Model Eckbo (1976)

Political Models Stevens (1992)

Moran (1982) Swing Producer Model Griffin and Teece (1982)

Among the variety of oil market models, there are also a variety of methodologies that

are applied. However, most of all existing models are rooted into two distinct

methodologies: inter-temporal optimization (IOM) and recursive simulation models

(RSM).

IOM describes a model of decision-making where actors attempt to maximize some

measure of wealth or utility over the entire future. In the IOM, one or more decision

maker has knowledge of all relevant circumstances (considering the entire future) and

65 Cremer, J. and Salehi-Isfahani, D. 1991, Models of the Oil Market, UK, Harwood Academic Publishers

seeks the single strategy for maximizing current and future benefits. This implies that

the chosen production path leads to the largest attainable value of their oil reserves.

The market structure and the selection of discount rate are the most essential factors in

IOM.

The RSM methodology report prices and supply-demand balances annually and focus

exclusively on world oil markets, where it act on information only about past and

current events. The annually supply-demand balance for crude oil is determined by

the global oil consumption minus the production from non-OPEC countries, whereas

OPEC covers the residual demand. OPEC’s productive capacity is generally

exogenous and the cartel sets the crude oil price based upon last period’s price and

rate of utilization of its capacity. In this way, oil prices, production and consumption

are determined recursively; market conditions in one year influence those in the

succeeding year. RSM do not take into consideration if the future calculated oil price

is desired from a producer’s perspective.

7.1.1. The Reliability of Oil Market Models

Simulation- and optimization models are unlike with regard to the price mechanism.

As described, simulation models employ OPEC’s capacity utilization, while

optimization models calculate an optimal price path.

From theoretical point of view, the optimization models are preferred, but there is no

indication that optimization models prognosticate the development in oil market better

than the simulation models. The main problem for optimization models is to

determine the correct discount factor, cartel policy and backstop technology. The

simulation models are, however, most popular among analysts. Even though they are

weak theoretically, analysts tend to use them because they are solved forward in time

and recursively begin with present prices and quantities. Another reason is that

simulation models offer a prediction of how today’s disequilibrium will evolve in the

future (disequilibrium models).

In practice, more or less every model, both simulation and optimization models, has

been rejected as result of empirical tests comparing the development of the oil market

with the projections. Among others, empirical studies have been conducted by known

economists as Griffin (1985), Dahl and Yuccel (1991), Griffin and Neilson (1994) and

Gulen (1996). Lynch, (1992) stated; “Number of question papers have attempted to

predict the actual oil price, but neither of these attempts have shown any accuracy”.

In spite of these result, analysts and academics employ global oil market models to

forecast oil prices. In this paper, as mentioned, we are using the forecasts of IEO2003.

7.2. Oil Market Conditions66

Crude oil is a non-renewable natural resource, which are the most consumed energy

source and the most traded commodity in the world. Individuals who rely highly on

energy for transportation, power and heat are naturally suitors for crude oil. Globally,

large consumers are the industrialized countries, or the Organization for Economic

Cooperation and Development (OECD) countries.

Crude oil production originates from several regions around the world, either from

land-based reservoirs or from reserves in ultra deep water. This geographical

difference is crucial since it is easier and less expensive to identify and extract oil

from land-based reservoirs than identifying and extracting oil in ultra deep water.

Consequently, some regions will have a natural production advantage over others.

7.2.1. Oil Supply

Globally, crude oil production can be separate into two groups, OPEC (Organization

of Petroleum Exporting Countries) and non-OPEC suppliers. OPEC is an oil cartel of

eleven member nations (Algeria, Indonesia, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar,

Saudi Arabia, the United Arab Emirates and Venezuela) that was established in

66 Numbers are collected from BP Statistical Review of World Energy. June 2003

196067. Total oil production from these eleven member nations constitutes OPEC

production. The remaining production is from non-OPEC countries. There are

fundamental differences in the production of these two groups.

The cartel enjoys a comparative advantage in oil production since the cartel claims

approximately seventy-eight percent of the Worlds proven oil reserves, which is

roughly 785 billion barrels of oil68. Further is the oil reserves characterized as large

land based concentrated pools of oil, where the marginal cost of producing the oil

ranges from USD 1.50 to USD 5.50 per barrels of oil. According to estimates, OPEC

countries have the ability to produce oil continuously for the next 80 years, while non-

OPEC producers can only produce oil continuously for the next fifteen years69.

The OPEC cartel works to safeguard revenues through influencing the oil prices

through organized production quotas. As OPEC limits its oil production, the cartel

enjoys relatively higher oil prices, but it also implies that the non-OPEC production

should increase. However, most non-OPEC producers cannot increase their oil

production significantly, as they are running at near capacity. This inability of the

non-OPEC producers to meet increased demand gives OPEC, to some extent, the

ability to control world crude oil prices.

In comparing, the non-OPEC countries are controlling only 22 percent of the

resources, but have produced sixty percent of the world’s annual production during

the last decade70. The majority of non-OPEC production originates from three distinct

regions: North America, Asia and Europe. Most of the non-OPEC reserves are not

land-based and the oil is typically diffused throughout the ground. Exploring and

drilling for oil is therefore on average more costly than OPEC production. The

marginal costs average are between USD 10 to USD 20 per barrel of oil, and

depending on the price of oil, some wells are currently unprofitable to produce, with

current prices and technology.

67 OPEC was established to coordinate the members’ oil politic and to stabilize “harmful and unnecessary” fluctuations in the oil price. 68 BP Statistical Review of World Energy, June 2003 69 IEA. 2002, International Energy Outlook 2003, The Energy Information Administration, USA 70 Cooke, M and Kinnersley, D. 2000. An Overview of the Global Oil Industry 2000. PriceWaterhouseCoopers, The Petroleum Group ABAS TICE Energy.

7.2.2. Oil Demand

The most vital factors on the demand side are the economical growth in the world, the

income- and demand elasticity for energy in general and specially the demand for

crude oil. Industrialized countries produce the greatest amount of economic activity,

and thereby, have the greatest need for energy, which are the countries of the OECD.

These countries consume about sixty-two percent of the world’s oil consumption. The

primary use of oil in these OECD countries is for transportation, heating and power.

The regional concentration of the OECD countries exhibits seasonal trends for the

demand after oil. Cold winter months create a collective need for heat in all

industrialized countries, and thereby causing significant increase in demand after oil.

In general, there is a swing of three to four million barrels per day between the 4th

quarter, when demand is the highest, and the 3rd quarter of a year, when the demand is

lowest. So on the crude oil price tend to peak during the winter months and fall off in

the summer.

7.2.3. Oil Inventories

In addition to the production of the world crude oil, portions of the global oil supply

are not consumed, but held in stock. There are two categories of oil reserves,

discretionary petroleum reserves (DPR) and strategic petroleum reserves (SPR). The

difference between the two categories is ownership. DPR are inventories held by

industry participants and governments hold SPR. The Energy Intelligence Group

estimates that there are seven to eight billion barrels of oil held in total reserves with

majority held in strategic reserves.

Governments hold strategic inventories for precautionary reasons. Governments,

mainly of the industrialized countries, hold strategic reserves to protect themselves

from adverse price shocks due to unexpected supply shortages. The United States

owns the largest SPR and as result of the Energy Conservation Policy Act holding up

to four billion barrels of crude oil. In total, roughly ninety percent of the world’s oil

storage is held in SPR.

The remaining ten percent of the world’s oil inventories are held in DPR. Although

minor in volume, DPR provide an important function for the world’s oil market. First

DPR helps to smooth market disturbances between market supply and demand

imbalances. Second, DPR reveal valuable information about current and future market

conditions.

7.3. Historic Oil Price Development71

The oil price has been highly volatile during the last 25 years, as subject to changes

caused by supply and demand imbalances. These imbalances arises from events like

war, formation/breakdown of trade agreements, unexpected weather patterns,

economic patterns, economic crisis and changes in political regimes etc.

From 1949 to 1972, the yearly oil price declined from approximately USD 15 to USD

11 in real terms. Due to events in 1973 and in 1979-80 (see figure 14) the oil price

seven-fold to about USD 76 (real) a barrel by 1981. The soaring crude oil prices in the

early 1980s contributed to world recession and development of alternative energy

sources, which led to a decrease in demand and falling prices. Efforts by OPEC to set

production quotas, in an effort to shore up prices were largely unsuccessful, as

member nations routinely violated limits due to disagreement of the distribution of the

quotas. Up to 1985, Saudi Arabia had been the buffer country to absorb the cheating

among members and thereby keep overall OPEC quotas on target, but this practice

were abandoned at the request of Saudi Arabia. In august 1986, the oil price fall

bellow USD 30 per barrel (real), due to overproduction by several OPEC members.

After 1986, the oil price has fluctuated in the region of 25-30 USD per barreø (real)

except in 1990-91 and 1997-98. The prices went sky high to about USD 35-40 per

barrel (real) in response to uncertainty created by the Iraqi invasion of Kuwait 1990-

91, but retreated after Iraq was defeated by allied forces. In the summer of 1998, the

oil price dropped as low as USD 14 per barrel (real) due to abnormal high

71 Numbers collected from www.wrtg.com

temperatures during the winter in the industrialised countries and the Asian financial

crisis. The average world oil price from 1861 until present has been calculated to

around 19 USD per barrel of crude oil.

Figure 14: Crude Oil Prices Since 1861 in Nominal and Real Terms

Source: BP Statistical Review of World Energy 2003

As explained, the oil market conditions have changed radically over the years since

1861. During the last years, from 1999 until today, with the exception of the terrorist

attacks on the United States on 11.09.01, the crude oil price has been above 22 USD

per barrel, mainly caused by market uncertainty and OPEC’s ability to control the oil

prices. In 2000, OPEC countries established their “price band” or range of preferable

prices indicating that prices should be between 22 and 28 USD per barrel of crude oil.

By showing loyalty to the cut back strategies, OPEC has been successful in achieving

this goal and since 2000 the average oil price has been 26.60 USD per barrel of oil72.

72 Own calculation (numbers from IEO2003)

Figure 15: Oil Prices Since 1996 Compared to OPEC’s “Optimal” Price Range


7.4. World Oil Supply and Demand Forecast

Fluctuations in oil prices are caused by supply and demand imbalances. In order to

foresee future developments in the oil price, we present forecasts on oil demand and

supply from some of the leading oil and energy agencies. The forecasts are divided

into long- and short-term projections.

7.4.1. Short Term

Global oil demand rose by 1.4 million barrels per day in 2003 and major economic

forecast groups expect that the demand will increase by 1.1-1.6 millions barrels per

day in 2004. The US is the largest consumer of oil, accounting for nearly 25 percent

of global demand. However, the rapid increase in Chinese oil demand is the main

reason behind recent trends. The Chinese oil demand increased by one million barrels

per day during the past year.

The general expectation is that oil production will increase with 1.4 million barrels

per day in 2004 and the production amongst OPEC suppliers is projected to grow at

an annual rate of 2.5 percent through 2005, which is slightly more than estimated

production growth among non-OPEC suppliers. However, there is some uncertainty

connected to the ability for oil producing countries to increase oil production. Under

investments in production, transportation, refinery and storage capacity in recent years

have created bottlenecks and it may be more difficult to increase production than

assumed. There is also reason to worry about the security of oil supply, as terrorist

attacks have become a threat in the Gulf region and especially in Saudi Arabia.

Figure 16: Global Oil Demand (above) and Supply Forecast

Source: CIBC World Markets Corp

7.4.2. Long Term

IEO2003 projects the world oil demand to grow from today’s 78 million to 119

million barrels per day by 2025. This is an increase of 53 percent in 20 years. The

global economic growth is the most vital driver of oil demand growth and is expected

to average 3.1 percent per year until 2025.

IEO2003 expects the world oil supply to grow from today’s 77 million to 118 million

barrels per day in 2025. Increases in production are expected for both OPEC and non-

OPEC producers. New exploration and production technologies, cost reduction and

attractive fiscal terms to producers by governments are contributors to the expected

continued growth in production and in production capacity.

Table 7: OPEC oil production (left) and non-OPEC production73 1990 – 2025

(Million of barrels per day)


As we can see, the projected production estimates are close to the estimated world

demand. This is a natural consequence since oil producers are adjusting their

production and new investments in proportion to the oil demand. The adjustments are

mainly done by the OPEC countries, while non-OPEC countries are producing at

maximum capacity as long as the oil price is above their cost of production. The non-

OPEC countries are also, as mentioned, more exposed to shifting oil prices because of

higher exploring and production costs than the OPEC countries that mostly produce

on-shore.

The world oil is, as mentioned, a non-renewable resource that will eventually dry out.

However, in our time horizon of estimation, the oil resources are expected to cover

the expected demand. It is therefore likely to believe that the amount of oil resources

will have minor effects on the oil price in our time horizon. The world oil resources

are shown in table 6.

73 Notes to the figures: Includes the production of crude oil, natural gas plant liquids, refinery gain, and other liquid fuels.

Table 8: Estimated World Oil Resources 2000 - 202574 (Billion of barrels)


7.5. Estimation of Oil Prices

Incorporating the recent price turbulence into the estimation of intermediate and long-

term oil is difficult. One question is if OPEC will be able to keep the oil price inside

their preferred range by using cut-back production strategies. Another question is if

the non-OPEC suppliers are able to increase their production rates. At the other hand,

will the demand for oil continue to grow or is their a possibility to develop

competitive substitutes for oil?

The oil estimates made by IEO2003 and other international energy agencies may be

far from reality if some of the market influencing factors radically change. The fact

that there is a lot of uncertainty in the global economic market, and in special the oil 74 Notes to the figure: Resources include crude oil and natural gas plants liquids. (The oil resource consists of three categories; remaining proved reserves (oil that has been discovered but not produced); reserve growth (increases in proved reserves that occur over time as oil fields are developed, produced, and as exploiting technology are improving); and undiscovered oil (that remains to be found through new field exploration). IEO2003 has used the annual assessment of worldwide reserves published by Oil & Gas Journal and the World Petroleum Assessment 2000 by the US Geological Survey in their estimation of reserves and resources.

market, is a reason why the oil prices recently have been escalating. The more

uncertainty, the more risk premium is incorporated in the oil price.

We have summarized some major developments influencing the oil market and the oil

prices. Changes in these factors may radically change future oil prices. We must

therefore be aware that oil prices are strongly volatile and difficult, almost impossible,

to predict.

The low oil price in 1998 and in the beginning of 1999 was slowing the pace

of development in deepwater exploration due to high exploration costs.

However, the increase in oil prices during the past years and expected high oil

prices in the future have expanded the development of new oil fields offshore.

The economy in Asia has been growing at high speed during the last decade,

fronted by China and India. It is crucial to the long-term growth of oil markets

that the economic development in Asia continues.

OPEC is expected to increase its share of world oil supply significantly over

the next two decades, but non-OPEC countries are also expected to remain

competitive and project the oil prices from escalating too much. Other

competitive resources will be other sources of energy and in particular natural

gas.

The war in Iraq, the international war on terrorism, uncertain economic

recovery in Asia and Japan, the development of China’s economy and political

regime and the social conflicts in Venezuela (large oil supplier) are some of

the other factors making the near-term oil market behaviour uncertain.

The average world oil price from 1861 until present has been around 19 USD per

barrel of crude oil75, but the oil market conditions have changed radically over the

years. As mentioned earlier, the average price since 1999 has been 26.60 USD. We

have chosen to rely on the IEO2003 projections (See figure 17). 75 www.wtrg.com

Figure 17: World Oil Prices in Three Cases 1998 – 200876

0

5

10

15

20

25

30

35

USD per barrrel

Historic oil price 12,92 18,25 28,71 22,26 23,71 27,29

Reference case 27,29 26,88 24,7 23,48 23,66 23,83

Low oil price 27,29 16,87 16,99 16,99 16,99 16,99

High oil price 27,29 30,81 31,18 31,62 32,04 32,44

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008


IEO2003 present the future world oil price in three scenarios; the reference case, high

oil price and low oil price. The reference case assumes that OPEC producers adjust

their production to keep world oil prices between the 22 to 28 USD per barrel range.

The low oil price case represents a future market where all oil production becomes

more competitive and OPEC’s influence is minor. The high oil price case represents a

more market-assertive OPEC, with lower production goals and other non-financial

(geopolitical) considerations.

In our valuation, we use the oil prices projected in the base (or reference) case

scenario, with some adjustments (except in the scenario analysis where we also use

the best and worst case). The world oil price, presented in figure 14, is defined as the

annual average U.S. refiner’s acquisition cost of imported crude oil. Hydro produces,

however, North Sea oil (Brent oil), which is known to have a better quality than the

average crude oil imported in by the U.S. In correspondence to the world oil prices

presented in the figure, it is normal to find the price of North Sea oil (or Brent oil) by

adding 1 USD per barrel to the defined world crude oil prices.

76 See appendix 5

In the valuation of Hydro, we therefore use the estimated world oil price in the

reference case and adding 1 USD. We have not considered the fact that Hydro is

increasing its production in other locations than the North Sea (the Brent area)

because in our time horizon (until 2008) the main production would still be North Sea

(or Brent) oil.

Table 9: North Sea Oil Price (Brent Oil) Projections

2004E 2005E 2006E 2007E 2008E North Sea Oil Prices 27,88 25.70 24,48 24,66 24,83

Compared to other international energy agencies, the IEO2003 projections are

generally at the high end of the spectrum of price forecasts across the time period

2005-2025, with some exceptions (See table 10). In the valuation process, we have to

be careful not using too high estimations of oil prices, but we believe that in our

relatively short time horizon (2008) the estimation that we have decided to use still is

relatively careful and pessimistic. The future prices for oil until 2007 are above 30

USD per barrel77, which indicate that our price estimates are not too optimistic.

Table 10: Comparison of World Oil Price Projections 2005 - 2025 (2001 USD per barrel)


77 www.nymex.com

7.6. Natural Gas Forecast

Natural gas is becoming a global industry as the distributions of gas from reserve

fields to markets are becoming more cost-effective. There is an ongoing process

integrating the supply and demand as economies of scale are increased, new alliances

formed and regional markets developed and linked with each other. The process of

change began in the United States during the 1980s and has now spread to continental

Europe via the UK encouraged by the EU gas directive. The European Gas

Directive’s goal is to develop new market structures by 2008, which implies that

national governments are obligated to adopt legislation to give customers the right to

choose their suppliers. It also implies that distribution companies must allow third-

part access to their pipeline systems. The major goal is to create a single gas market

for all aspects of trade and commerce by 2010.

7.6.1. Worldwide Development

Natural gas is the fastest growing primary energy source in the IEO2003 forecast. In

general energy demand is rapidly growing, but spurred by environmental

considerations, natural gas has become the fastest growing segment of the energy

market. The majority of new power plants around the world are gas fired, and CO2,

nitrous oxide and sulphurous oxide emissions are much lower than from power plants

burning fuel oil, coal and lignite. Natural gas is ultimately more abundant that oil, and

on current production rates it will outlive oil by twenty years78. In the IEO2003 report

the consumption of natural gas is projected to nearly double between 2001 and 2025,

mostly because of the growing demand from developing nations.

78 IEA. 2001, International Energy Outlook 2002, The Energy Information Administration, USA

7.6.2. Western Europe Development

Western Europe’s natural gas consumption is projected to almost double over the

forecast period, growing at an average annual rate of 2.4 percent, from 14.8 million

cubic feet in 2001 to 25.9 million cubic feet by 2025 (See figure 18)

Figure 18: Natural Gas Consumption in Western Europe 1970 - 2025


Western Europe’s dependence for natural gas is projected to reach 60 percent by

202079. With the exception of small quantities exported by France, Germany and

Norway to Eastern Europe, all western European production is consumed in the

region. Most of the regions resources are concentrated in United Kingdom, the

Netherlands, and Norway. All three countries currently produce more than they

consume and export the balance. Norway’s share of European gas markets is

approximately 12 percent80 . This percentage is expected to rise in future years based

on existing contract commitments and remaining reserves. The United Kingdom, in

particular, is an attractive market for Norwegian gas due to the maturing U.K. North

Sea Fields, expected to demonstrate a decline in production by 2005. Given its close

proximity to the United Kingdom, the Norwegian continental shelf is considered a

competitive source for new deliveries. The Norwegian and UK authorities have

recently agreed on the main principles for a new pipelines between the two countries,

making the shipment of gas from new gas fields possible, such as Ormen Lange field,

to the United Kingdom. The Norwegian natural gas is competitive in the European

79 IEA. 2002, International Energy Outlook 2003, The Energy Information Administration, USA 80www.hydro.com

region because of its location, transportation infrastructure and substantial reserves,

both discovered and undiscovered.

7.7. Estimation of Natural Gas Prices

The economics of transporting natural gas to consumers depends on the market price,

and the pricing of natural gas is not as straightforward as the pricing of oil. More than

50 percent of the world’s oil consumption is traded internationally, whereas natural

gas markets tend to be more regional in nature, and prices can vary considerably from

country to country. In Europe for example, LNG markets are strongly influenced by

oil product markets rather than by natural gas prices. As the use and trade of natural

gas continue to grow, it is expected that pricing mechanisms will continue to evolve in

coherence with better facilitation of international trade and the opening of regional

and global natural gas markets.

The majority of Hydro’s gas production is sold to European counterparties based on

long-term supply contracts. The complex price mechanism and the fact that we do not

have information about each contract, makes it difficult for us to estimate the actual

price Hydro receives. Looking at historical prices Hydro’ realised a gas price of 0.95

NOK in 2002 and 1.00 NOK pescm in 200381. The price improvement reflects the

development in oil prices. In 2000 and 2001 the prices were respectively 0.99 NOK

and 1.23 NOK pescm82. The historic gas prices are transformed into USD price per

barrel in table 12.

Table 11: Hydro’s Historic Realised Gas Prices (Numbers in USD)

2000 2001 2002 2003 Gas Price 17,83 21,68 19,07 23,16

81 Annual report Norsk Hydro ASA 2003 82 ibid

Historically gas prices have been approximately 20 percent lower than the world oil

price83. Since the oil and gas markets are influenced by more or less the same market

factors and the fact that long-term gas contracts often are indexed to the oil price, we

assume a positive correlation of the markets. Comparing the world oil price to the

natural gas price in the US from 1999 until present, support our assumption and gives

a positive correlation of 0.6584.

Since there is a positive correlation between oil and gas prices, and the fact that

natural gas price historically has been about 20 percent lower than the oil price, we

use the projected oil price projections as basis for future gas prices. We simply

assume the natural gas price in Europe to be 20 percent lower than the price of North

Sea Oil. Table 12 shows the gas prices used in the valuation of Hydro.

Table 12: Gas Prices as a Product of Future Oil Prices (Numbers in USD)

2004E 2005E 2006E 2007E 2008E North Sea Oil Price 27,88 25.70 24,48 24,66 24,83

Natural Gas Price85 22.30 20.56 19.58 19.73 19.86

83 Edwards, A.G., Global Oil Market Analysis. December 8, 2003 84 See appendix 6. We note this is simple comparison only use 5 years historical data, the number can only be used as an indicator of positive correlation. 85 The natural gas price are re-calculated

8. Exchange Rate (NOK/USD)

Hydro is selling its oil in the international market. Since oil is a homogeneous

commodity, the market has a universal spot (and forward) price. The price of oil is

denominated in USD, or influenced by movements in the value of other currencies

against the USD. Furthermore, since oil is quoted in USD, exchange rate movements

have a sizeable differential impact on Hydro’s revenue stream. In the case of natural

gas, Hydro is mainly selling to the Western Europe market. However, we are only

estimating the future relationship between USD and NOK as USD is the primary

foreign currency risk and the currency that affects Hydro’s operating results most.

8.1. Estimation of Exchange Rate (NOK/USD)

Differences in economic growth and interest rates are the main factors influencing the

exchange rate between currencies.

The Norwegian monetary policy has from 2001 been oriented towards low and stable

inflation. The operational target of monetary policy is so on to keep the annual

consumer price inflation growing at an approximate level of 2.5 percent over time86.

The target is also approximately in line with the average inflation rate in Norway in

the 1990s87.

The Norwegian crone was strengthening during the period from the summer 2000 to

the beginning of 2003 due to high interest difference compared to foreign countries.

The interest rates were decreasing abroad, while the interest rate in Norway was

relatively high. The international stock markets were at the same time falling and

Norway experienced an increased demand for the Norwegian crone. In order to

prevent this development further, the interest rate in Norway has been lowered

significantly. 86 www.norges-bank.no 87 Ibid.

The US monetary policy does not have a specific target as the Norwegian inflation

target. However, US monetary policy also tries to establish a sound and stabile

economic growth with inflation as one of the most important indexes.

Affected by the international stock markets decline and the US economic problems

that occurred in the end of 1999 the US economy suffered. In accordance to the US

economy decline, the Federal Reserve (the central bank of US) has made cuts in the

interest rate during the last years.

According to un-stability in the world economy and especially with regards to the US

and Norwegian economy the exchange rate between USD and NOK has been

fluctuating considerably since the beginning of 2000. In coherence to the discussion

above the Norwegian crone was extremely strong compared to US dollars in the

period 2000- 2002, but has dropped to a level underneath 7, which is just underneath

the average exchange rate during the shown time period (see figure 19).

Figure 19: The Exchange Rate between NOK and USD during the Period 1990 – 2003

USD vs NOK

0

2

4

6

8

10

jan.

90

jan.

91

jan.

92

jan.

93

jan.

94

jan.

95

jan.

96

jan.

97

jan.

98

jan.

99

jan.

00

jan.

01

jan.

02

jan.

03

Source: www: bloomberg.com

Its difficult to project the future of exchange rates but as both countries seem to be in

the same situation at the time being, it most probable that the exchange rate will not

be radically different from today’s in the coming few years. Hydro’s realized a

average exchange rate of 7.07 NOK/USD in 2003, which is slightly below the average

exchange rate for the period 1990 – 2003 of 7.23 NOK/USD.

We assume that the exchange rate will grow from the level of 2003 towards the

average level for the period 1990 – 2003 in a linear way.

Table 13: NOK/USD Estimated Exchange Rate

2003 2004E 2005E 2006E 2007E 2008E NOK/USD exchange rate 7.07 7.10 7.13 7.16 7.19 7.23

9. Valuation of Hydro

To valuate Hydro we have to translate the strategic perspective into financial forecasts.

As in the strategic analysis, the focus is on the Production and Exploration segment.

We valuate Hydro based on the discounted cash flow model, followed by the

EV/EBITDA and EV/DACF multiples.

9.1. Budget Period

The budget period is separated into two periods, during the explicit forecast period

and after the explicit forecast period, also referred as the continuing value. During the

explicit forecast, Copeland, Koller, and Murrin (2000) recommend an estimation

period of at least 10-15 years. However, as pointed out in chapter 3 it is a major

difference between oil companies compared to firms with a manufacturing logic. The

long-term survival for an oil company depends on their access of reserves and their

ability of locating new reserves. Hydro’s access to reserves was at the end of 2003

about 2449 mboe and their total production was about 193 mboe, which indicates that

their reserves would last for about 13 years. With regard to their ability of locating

new reserves, we point out in section 9.2.1.1.2 a potential upside of about 2229 mboe,

which would extend their reserve lifetime by 12 years. However, using an estimation

period in the oil industry of nearly 25(13+12) years is clearly unrealistic as much of

these reserves are not developed and highly un-secure. Further, it is extremely

difficult to predict vital factors as commodity prices, currency fluctuations, and

technology developments, and so on that far into the future.

We have chosen to use an estimation period of five years during the explicit forecast

period. This is also the common practice by most investment banks. The residual

value (year 5) of Hydro would normally be based on the continuing value according

to the cash flow and subsequent return in the residual year, and on the long-term

growth rate. However, instead of estimating the residual value it is common to value

the present value of the remaining oil reserves after the explicit forecast period (See

section 9.5).

9.2. Forecast of Future Revenues and Costs88

In order to perform a DCF valuation with reasonable accuracy, we are forecasting the

business segments individually as the two segments have different strategic focus and

thereby different growth rates. The first section presents an in-depth analysis of

Hydro’s operations on the NCS and internationally, and determines Hydro’s outlook

with regard to future production, costs and reserves. In the second section, we analyse

Hydro’s E&OM segment more briefly.

9.2.1. Exploration and Production

First, we look at Hydro’s Exploration and Production division’s operations on the

NCS. Secondly, we project future developments in international operations.

9.2.1.1. NCS Operations

9.2.1.1.1. Current Production

Hydro’s current oil/gas field operator ship includes the Oseberg fields, Troll, Snorre

fields 89 , Sleipner fields90 , Åsgård, Ekofisk fields, Gullfaks fields, Norne, Brage,

Visund, Njord, Frigg, Varg, Heimdal, Vale, Yme, Grane, Fram Vest and Mikkel91.

Hydro’s total Norwegian oil and gas production in 2003 was 470.000 boe per day.

88 The information in this section is mainly from Norsk Hydro annual report 2003, 2002 and Fact Sheet 2003, 2002, if nothing else is stated. 89 Includes Snorre, Tordis, Tordis Southeast, Tordis East, Borg, Statfjord East and Sygna fields 90 Includes Sleipner West, Sleipner East, Gungne and Sigyn fields 91 Further information about Hydro’s interest, the field operator, the timing of production start-up, production and reserves is presented in the tables locate on page 156-157 of the Company’s annual report 2003.

9.2.1.1.2. Production Outlook

As a consequence of the development of two large fields and several small fields in

the mid-1990s, Hydro is currently among the fastest growing petroleum companies in

the Western world. Hydro’s production target at the NCS is approximately 539.000

boe per day by 2006. Using 2002 as a base year this represents a compound annual

growth rate of 5.7% over the period 2002-06. In comparison Hydro has a higher

growth rate than for example BP and Shell (both 3% per annum), and is on par with

companies like Total and ENI (respectively 5 and 7% per annum) (See figure 20).

However, compared to companies of similar size, such as the BG Group, Hydro’s

output growth is more modest.

Figure 20: Stated Production Growth Targets Per Year by Major Oil

Exploration and Production Companies

0 %1 %2 %3 %4 %5 %6 %7 %8 %

EniHyd

ro

KerrMcG

eeTota

lBG

Repsol

Statoil

Exxon

Mobil BP

Shell

Chevro

nTex

aco

Conoc

oPhil

ips

Maratho

n

Source: Company presentations

In the past couple of years, both the European super majors Shell and BP have had to

downgrade their short-term growth targets. Both firms concluded that strong growth is

too difficult to sustain over a multiyear period. As these targets were downgraded,

share prices suffered significantly. Although Hydro’s growth target on the NCS is as

high as BP’s and Shell’s initial target, we believe that the Hydro will be able to realise

its target. Firstly Hydro is a much smaller company and secondly with the projects

that are currently under development the future growth looks to be steady.

This confidence is also based upon on our bottom-up analysis of Hydro’s production

profile. From now on and until 2006, the company will have around 12 new projects

coming on stream, which are estimated to add about 197.000 boe per day to its total

oil and gas production. Our analysis suggests that the current portfolio (which

produced 432.000 boe per day in 2002) is likely to decline by around 3.9% per annum

to 368.000 boe/d by 200692. The combined result of this gives a total production from

the NCS of around 368 + 197 = 565.000 boe per day in 2006, which is 4.8% above

the company’s target of 539.000 boe per day (or annual growth of 5.7 percent).

Although calculations this far into the future inevitably have a high degree of

uncertainty attached, we believe the 4.8% safety margin is enough to remain confident

in the production target (or not too optimistic).

Table 14: New Projects Coming On-Stream (reserves and production in mboe)93

Reserves Production

Field On-Stream

Oil /NGL Gas Total 2006E

Fram 2003 50 33 83 9 Grane 2003 286 20 306 76 Mikkel 2003 8 12 20 6 Sigyn 2003 4 3 7 2 Vale 2003 5 40 45 3 Tune 2003 15 58 73 24 Total 2003 368 166 534 120 Kvitjeborn 2004 20 49 69 27 Skirne and Byggve 2004 1 4 5 3 Volve 2004 7 1 8 7 Total 2004 28 54 82 37 Kristin 2005 38 27 65 28 Svale 2005 10 10 3 Total 2005 48 27 75 31 Snohvit 2006 15 89 104 9 Total 2006 15 89 104 197 Sum Total 459 336 795

Source: Company data, Fact Sheet

92 www.woodmac.com 93 See appendix 7 (for our full-scale production profile for Hydro’s new fields on NCS) and 9 (for our full-scale production profile for Hydro’s total oil and gas production).

There are still considerable resources on the NCS that are undiscovered, but it is not

expected to find any major reserves such as Troll and Oseberg fields. Recent

exploration successes have been much more modest (see Figure 23), and 2002 was

actually a very disappointing year. 2003 has also followed the similar trend. (This is

the so-called “creaming curve” effect: the largest finds are made first, and the average

size of discovery diminishes over time as the area matures). Only the Ormen Lange

field stands out as the single major finding on the NCS in recent years. This raises an

important question about the maturity of the NCS and Hydro’s future opportunities

for further exploration. Beginning in 2009-10, the company will be dependent on new

discoveries and/or new acquisitions in order to maintain production levels. In addition,

the production growth in the oil and gas business is not something that comes quickly.

The developing period from the first successful exploration well to plateau in a field is

in most instances 7 years or more. The maturity phase (the period from the successful

find to the decision to develop a field) is often longer than the development phase.

This is the case for both Ormen Lange (10 years, of which 6 years of maturity) and

Grane (12 years, of which 9 years of maturity). It is therefore reasonable to conclude

that due to limited number of findings on the NCS since Ormen Lange, there will be

no major contributions to Hydro’s production profile from new fields on the NCS

until 2011 as the earliest.

Even though the NCS is a mature region, we believe that the NCS still offer a lot of

opportunities for new discoveries. According to our estimates we believe that around

4,748 million boe of 3P reserves (that is, proven, 90% commerciality + probable, 50%

commerciality + possible) could ultimately be available for Hydro on the NCS,

although this might be conservative94. This compares to proven reserves at the end of

2003 of 2449 million boe. The potential upside is coming from the following three

sources:

Revisions and extensions. According to SEC rules, only reserves with a 90%

probability of commerciality can be booked as “proven reserves”. This means

that the most likely estimate (that is, proven + probable, which has above 50%

probability of commerciality) of reserves is significantly larger than that. 94 See appendix 8

According to estimates by the Norwegian Petroleum Directorate (NPD), it is

most likely to believe that Hydro’s reserves are approximately 1.1 million higher

than 1P reserves in Norway.

Enhanced oil recovery (EOR). Through a combination of technologies, such as

gas or water injection, horizontal drilling and 4D seismic, Hydro should be able

to improve the recovery rate from many of its fields. Hydro has had success with

several new well solutions on fields such as Troll and Oseberg, which have

increased the original forecast more than three times figured. The NPD expects

that several EOR techniques should increase of 2P reserves on the NCS by

around 12% (this percentage has been revised downwards significantly during

the recent months, see figure 21). Applying this percentage to Hydro’s 2P

number suggests an additional 438 mboe that can be available, which would

represent around 17.8% of 1P reserves today and close to 3 years of their

Norwegian production with current production pace.

Discoveries. There is still some potential for further discoveries. According to

NPD estimates, approximately 21.1 billion boe of commercially exploitable

reserves are still to be found on the NCS, with a 90% confidence interval of 8.2

– 38.4 billion boe. At the moment, Hydro’s share of proved reserves on the NCS

is approximately 9%. Assuming the company can obtain an equal share of

discoveries based on the conclusion in the value shop (based on the lower

estimate of 8.2 billion boe, which is very conservative). This would imply an

extra 738 million boe to be available (although there would be upside potential

to this if we take the mid-point of the NPD range rather than the lower bound

estimate).

Figur 21: Estimated Undiscovered Resources on NCS – Estimate Revision

2001/2004 (billion boe)

Source: Norwegian Petroleum Directorate

In the long term, however, we expect Hydro to find it increasingly difficult to find

sufficient reserves to maintain reserve life and keep production growing at its current

rate. In the coming few years, Hydro will still have reserves to book from reserve

revisions and further field development of the fields that are listed in table 13

However, the following factors will put reserve life under pressure.

Production is growing quickly. With 6% production growth, Hydro has to

discover 6% more reserves every year to simply maintain reserve lift. This

means that as soon as reserve replacement slows down, actual production

could decline quite quickly.

NCS exploration success is declining. As shown in figure 22, the exploration

success on the NCS is declining. The major findings, such as Oseberg and

Troll, all occurred in the 1980s, with Ormen Lange being the only considerable

finding in the 1990s. It is unlikely that such huge fields will be found again

and new findings will probably be smaller in size.

24,321,1

6,08

2,43

Estimate Dec, 2001 Estimate Dec, 2004

Undiscovered resources

Potential from Enhanced Oil Recovery

-25%

Figure 22: Oil and Gas Reserves Discovered in Norway 1972-2002

01000200030004000500060007000

1972

1974

1976

1978

1980

1982

1984

1986

1988

1990

1992

1994

1996

1998

2000

2002

(mbo

e)

Oil/NGL Gas

Source: Norwegian Petroleum Directorate

9.2.1.1.3. Operating Cost per Barrel

As stated in Hydro’s annual report 2003, Hydro’s announced target for operating

expenditure excluding exploration is NOK 82 per boe. Operating costs excluding

exploration were for 2002 and 2003 respectively NOK 79 and NOK 76 per boe, which

is below the announced target. In coming years we expect operating cost of Hydro’s

existing/producing portfolio to start increasing, due to the fixed element in the

production cost and declining well pressure.

However, we expect these factors to be largely compensated by the more favourable

cost trend of the new fields that are likely to come on-stream in coming years. As

these assets are still ramping up production, their cost-per-barrel will actually decline.

Given Hydro’s considerable portfolio of ‘new’ assets and strong production growth,

we expect the company to be able to keep operating cost-per-barrel more or less flat in

its Norwegian operations.

Although we believe that Hydro will be able to keep operation cost-per-barrel

constant in coming years, we expect that after 2007, Hydro will see an increase in its

real opex/bl. In the long term, Hydro’s growth rate would be very difficult to sustain

and as soon as production starts flattening out (or starts to decline) opex/bl is likely to

go up, especially when new fields are smaller (less economies of scale) and located in

areas with harsher conditions.

9.2.1.1.4. Hydro’s Production Mix

Given Hydro’s resource base and production profile, we expect that in coming years

its production mix will shift away from oil and towards more gas, in-line with the

NCS trend (the oil is pumped up first, than the natural gas). Even though, fields such

as Grane, Fram and Kristin will produce significant amounts of oil towards 2010.

Whilst the split was about 75% and 25% for oil and gas (on a boe basis) in 2003, we

expect the gas sale to increase 18% each year and by 2008 the amounts of produced

oil and gas will become equal (50-50)95. This confidence is based upon the fact that

Hydro’s gas sale in the last 5-year has increased on average 19% and in addition

Ormen Lange will more or less only produce gas.

Gas prices, however, are on a significant discount to oil, when both are expressed on a

boe-basis. Whilst the average Brent crude oil price for 2003 was approximately USD

28.7/bl, Hydro’s realised gas price was around USD 23.2/boe. This represents a 24%

price difference. As the product mix shifts away from gas and towards oil this means

that the revenue likely will decline. In figure 23, we have estimated that this effect

could reduce revenue by around 4.5 percent.

95 See appendix 9

Figure 23: Oil versus Gas Mix and Impact on Revenue 2003/200796

75 %

50 %

25 %

50 %

2003 2007

GasAverage price 2003

USD 23.2/boe

OilAverage price 2003

USD 28.7/boe

Average price: USD 27.2/boe USD 26/boe-4.5%

9.2.1.1.5. Conclusion

As seen from table 15, we expect production volumes to grow quickly, especially in

the coming few years. This will presumably allow Hydro to keep operating cost more

or less flat, as the declining opex/bl of new fields offsets the increase opex/bl of

existing fields. In the long term, however, we foresee downward pressure on returns,

as the region is a very mature region with limited opportunities for long-term growth.

Operating costs are likely to go up as soon as Hydro’s production growth levels off.

Table 15: Hydro’s National Oil and Gas Production97

2004E 2005E 2006E 2007E 2008E Oil production (kboe/d) 377 365 346 307 239

Gas production (kboe/d) 157 186 219 258 305

Hydrocarbon production (kboe/d) 534 550 565 562 544

Source: Company data, Fact Sheet

96 Note, oil and gas prices assumed to remain constant between 2003 and 2007 for the purpose for this calculation, which is not our official forecast 97 See appendix 9

9.2.1.2. International Operations

We have a negative outlook for Hydro’s international expansion activities. The

exploration failures during the last two years have caused a substantial shrunk in the

international opportunity set. As the entire sector suffers from a lack of growth areas

and competition for new reserves is intense, we believe it will be very difficult for

Hydro to realise the step change that is necessary to make the portfolio more balanced

between NCS and international shelves.

Hydro recognised its need to expand internationally early, and until recently the

company had aggressive international growth plans. In 2001, the company was aiming

for five new international core areas, each producing more than 50.000 boe per day.

The implication of this was that total production would grow to around 800.000 boe

per day eventually. The company did not specify an exact timeframe for their plans,

but it would be equivalent to, for example, growing at an aggressive 7% per annum

for ten years. To realise this ambition, Hydro increased its international exploration

budget significantly (see figure 24).

Figure 24: Exploration Expenditure Norway versus International 1999-2003

(NOK million)

Source: Company data

53 % 51 % 46 %26 % 27 %

47 % 49 % 54 %74 % 73 %

1999 2000 2001 2002 2003

Norway International

1498 1799 2018 2495 1609

Hydro’s international strategy was based on leveraging the company’s NCS

competence, such as deepwater drilling and working together with partners with

whom they had a good relationship on the NCS already. As a result, Hydro has

undertaken much of its international exploration activity together with Total (who, by

contrast, has had a very good exploration record). During 2002, Hydro was involved

in a relatively large number of international exploration activities. However,

promising acreage such as in the Gulf of Mexico, Block 34 in Angola, and in

Trinidad & Tobago turned out to be dry. Out of 13 exploration wells drilled and

completed during 2003, one discovery was made in the Gulf of Mexico, whereas two

were made in Norway. As a result of this, few new projects have been added to

Hydro’s international portfolio. In table 16, we have compared Hydro’s project

pipeline as reported in its 2001 and 2003 strategy presentation. This overview shows

clearly that over a two-year period in which exploration activity peaked only two

projects were added. In addition, start-up dates for key projects such as Dalia, Rosa

and Lirio seem to have been postponed by one and two years respectively.

Table 16: International Fields to Come On-Stream (in million mboe)98

Fields to Come On-Stream

Presentation September 2001 Presentation May 2003 Field Production1 On-Stream Field Production1 On-Stream Terra Nova2 20 2001 Terra Nova2 - Producing

Girassol 20 2002 Girassol - Producing

Kharyaga 2 9 2003 Kharyaga 2 9 2003

Jasmin 5 2003 Jasmin 4 2003

Dalia 20 2005 Dalia 20 2006

Rosa/Lirio 10 2005 Rosa/Lirio 12 20063

Kharyaga 3 8 2006

Murzuq A-field 4 2004 Source: Company data

98 Notes to the figure: (1) Production refers to Hydro’s share; (2) Hydro obtained Terra Nova through the acquisition of Saga; (3) According to Hydro’s annual report 2003 is this project postponed to 2007.

9.2.1.2.1. Hydro’s International Oil Fields

In 2003, Hydro obtained around 11% of its oil and gas production from areas outside

Norway, and less than 8% of the company’s proved reserve base is located

internationally. The company currently has activities going on in the following

countries.

Angola is Hydro’s most developed country outside Norway and provides the

company with an opportunity to apply its deep-water oil production skills. The

company’s most important asset is a 10% stake in the Total-operated Girassol

field in Block 17, which came on-stream in 2001 and is currently producing

around 200.000 boe per day. In addition, Hydro acquired a 20% stake in Block

25 from Exxon Mobil in 3Q02. Block 25 is operated by Eni who so far has

drilled two wells that turned out to be dry. One more exploration well is still to

be drilled. Hydro has also a 10% stake in the Zinia field, which is another

recent discovery by Total in Block 17. Estimated reserves are in the order of

500 mboe. Production is not likely to start before 2008/2009. Finally, Hydro

has a 34% stake in Block 34 in the ultra deepwater Lower Congo Basin. The

operator of this field is Sonangol, the Angolan state oil company, whilst Hydro

provides technical support. One exploration well has been drilled, but it was

also dry. Sonangol and Hydro are committed to drill two more wells in this

block, but Hydro has indicated not be in a rush.

Hydro has been active in Canada since 1996 and got hold of its current

operations by swapping some NCS assets with PetroCanada. At the moment,

the company has interests in two fields off the east coast of the country: a 5%

stake in the Hibernia field, which started in 1997 and is currently producing

200.000 boe per day in total, and a 15% stake in the Terra Nova field that has a

total output of 150.000 boe per day. In addition, Hydro participates in

exploration activities in the Flemish Pass (east of New Foundland) and the

Scotian Shelf (Nova Scotia).

Activities in Iran include research and exploration of the Anaran field in the

southwest part of the country. As this field is close to the border with Iraq,

there are still many mines left from the Iran-Iraq war in the area. As a result,

Hydro has also been overseeing the mine-clearance for the seismic operations.

The Anaran field is estimated to hold a staggering 2.5 billion barrels of oil.

However, Iran operates a buy-back system when dealing with foreign oil

companies, which means that Hydro will only be able to book a small part of

these reserves and will be allowed to make an internal rate of return only

marginally above its cost of capital over a relatively short five- to seven-year

period.

In the Gulf of Mexico Hydro has the option to participate (with a share of 25%)

in 55 licences on a field-by-field basis, which is operated by ConocoPhilips.

Exploration wells have been drilled since 2000 and so far two discoveries have

been commercial. Currently there is a development plan being worked out for

these.

In Libya, Hydro is working together with Repsol YPF and Total. Hydro is a

partner in the onshore Mabruk field, with a stake of 25%. This field, which is

operated by Total, is currently producing around 11.000 boe per day. In

addition, Hydro is also involved in exploration activities in the Murzuq fields

together with operator Repsol YPF.

Finally, Hydro has oil production in Russia from the Kharyaga field, where it

has a 40% stake. It is operated by Total and produced around 13.800 boe per

day in 2003. Ongoing extension of the field means that Hydro expects the

production to reach 70.000 boe per day in 2007.

9.2.1.2.2. Conclusion

Despite significant expenditure, Hydro has failed to realise a material expansion of its

international portfolio and despite the importance of the matter, we believe the

prospects for Hydro to realise this expansion organically in coming years are small.

Even though if Hydro would achieve a stake in the Shotkman field as mentioned in

chapter 5, would this field not operate before 2011 at earliest and as it highly

unsecured if Hydro get a stake and the size of the stake, we have choose not consider

this field. Further, as mentioned under the caption “Operating Cost per Barrel” in

chapter 9.2.1.1.3 we presumably also here expect that average production cost will

decrease due to increased production, followed by increased production cost after

2007. Based on the above-mentioned information we believe that Hydro’s

international production will be as in table 1799.

Table 17: Hydro’s International Oil Production

Years 2004E 2005E 2006E 2007E 2008E Oil production (kboe/d) 71 76.5 102 110 67


9.2.1.3. Key Points Hydro Exploration and Production:

Stable production growth between now and 2007, 9% decrease between 2007

and 2008100

Increased share of gas in the Hydro’s production mix (unfavourable shift)

Hydro will still have reserves to book from reserve revisions and further

development of the fields listed in table 14

The oil prices will decrease from last year’s average of USD 28.7/bl towards

USD 23.88/bl in 2008, whereas the gas price will be sold at 20 percent

discount in relation to the oil price (see chapter 7).

The NOK/USD will steadily increase towards its historical average of USD

7.23 (see chapter 8).

99 See appendix 10 100 See appendix 9 for our full scale production profile for Norsk Hydro Oil and Energy

As seen in appendix 11, the Exploration and Production’s operating costs as a

percentage of revenues have fluctuated between 20.7 percent and 35.2 percent

during 2000 to 2003. In the forthcoming years we expect that Hydro will be

able to keep its costs at 26.3% of the revenue towards 2007, whereas we

expect that after 2007 we will see an increase in the costs as their production

decreases.

9.2.2. Hydro Energy and Oil Marketing

We believe that the activities within Energy and Oil Marketing in the forth-coming

years will not improve significantly. However, we are confident that the management

aims to enhance its position in the Energy market due to expected increased

production of crude oil and gas as mentioned under the caption “Hydro Exploration

and Production”. Consequently, it is therefore most likely to believe that the volume

will increase notably in the next few years. However, we do not believe that this will

have any major impact on the profit, as most of these operations are predominantly

margin-based sales and trading activities.

With regard to Hydro’s hydroelectric power system, the prices in the Nordic region

have been influenced by electricity prices within the European continental market.

Presently the prices are high due to high coal prices, due to restrictions on greenhouse

gas emissions in the European Union and low reservoir levels (20 percent lower than

normal). The present reservoir in the Nordic market area and lack of new capacity to

cover expected annual demand growth of more than 1 percent in the coming years

results in an expected price level above historic average. Reservoir levels are

expected to slightly improve and be approximately 12 percent below the normal

levels during 2004. However, such estimates are uncertain and depend on

precipitation levels. Increased reservoir levels may therefore outcome in increased

production versus last year production of 7.5TWh/y. Even though reservoir levels

most likely would increase in the forthcoming years, we believe that increased

production will offset with lower prices.

Further, it is not very likely to believe in any takeover scenario because of the

following factors:

Power assets and aluminium manufacturing are seen by many as inseparable,

due to important synergies that may be lost in the separation.

It is political difficult to sell a large power producer to non-Norwegian

owners101 (for sentimental reasons, as it remain a tough task to move such

assets out of the country).

Statkraft is the only expected Norwegian buyer for such large unit. This is a

company that is already facing strong accusations of monopolistic behaviour

from competition authorities.

9.2.2.1. Key Points Hydro Energy and Oil Marketing:

We expect a revenue increase of 2.5 percent per year for the E&OM segment,

due to our assessment of an increased production of hydrocarbons in E&P.

This is somewhat lower than the average revenue increase in recent years.

However, as last years price level for oil, oil products and gas was higher than

normal, and since we expect that the prices will normalize in the forth-coming

years, we feel confident that the revenue will increase but not as much as last

year. Further, we assume that increased hydroelectricity production will offset

with lower prices102.

The Energy and Oil Marketing’s operating costs as a percentage of revenues

have been fluctuated between 92.3 percent and 95.8 percent during 2000 to

2003. We assume that in the forth-coming years that the operating costs

101 The most recently example is Fortum’s failure of buying Oslo County’s share of Hafslund (the third largest power producer in Norway). 102 See appendix 11

remains at 2003 level of 93.4 percent, given that the operations are

predominately margin based sales and trading activities103.

9.3. Forecasting Other Spread Sheet Assumptions104

9.3.1. Tax Rate

Norway has a relatively high tax rate on oil and gas profits. In addition to the 28%

corporate tax, oil companies pay 50% on profits gained from offshore oil and gas

production, resulting in a marginal tax rate of 78%.

As the NCS matures and the prospects for growth diminish, we believe that the

Norwegian government eventually will be forced to reduce the marginal tax rate for

oil companies. If taxes stay at today’s high level, domestic and international oil

companies are likely to be more and more reluctant to invest on the NCS. In time, this

may hurt tax revenues more than lowering the tax rate. Moreover, reduced investment

may have a negative impact on employment in the Norwegian oil industry, which in

total amount to around 23,000 people105.

However, changes in the petroleum tax are politically sensitive and will not happen

over night. The last change to the tax regime was made in 1991, and in 1994 the

government appointed a committee to study the tax regime again. Although this

committee proposed a number of amendments very few of them were actually

implemented. A recent report by Kon-Kraft (2003) (a joint project between the

authorities, the oil companies, the labour unions and the financial industry)

highlighted the need for lower taxes to increase the level of exploration on the NCS.

However, this group advised the government to keep the main features of the tax

system unchanged for existing fields and only lower the taxes for new investments.

Such an approach would result in a decline in the effective tax rate, but only in the

long horizon. It will probably also take a couple of years to work out a sufficient plan

103 See appendix 11 104 If nothing else stated, is all calculations from appendix 11 105 Statistics Norway 2004

in order to make these changes in the oil tax system. We expect the current

government to not take any serious action before the next election, which are

scheduled to September 2005.

Finally, in a recent interview with Statoil’s interim CEO Inge Hansen (who was CFO

at the time of the interview) stated that the oil companies understood that the current

tax system had worked very well for the Norwegian people so far. Mr Hansen also

expressed that making more exploration acreage available on the NCS was more

important than lowering the taxes.

Hydro’s effective tax rate has been between 55.8 percent and 58.4 percent historically

with the exception of 2000 due to the acquisition of Saga Petroleum. Most likely no

assumed changes to the oil tax system will have any serious impact on our during

explicit forecast, and for that reason we use an effective tax rate of 57.2 percent,

which has been the historical average.

9.3.2. Hydro Exploration and Production Capital Expenditure106

After 1998, Hydro made a step change in its total E&P capital expenditure. During

1999-2003 Hydro spent approximately NOK 10 billion per year on exploration and

development, which is clearly higher than in 1997 and 1998 with respectively NOK

7.5 billion and NOK 5.9 billion in exploration and development costs. This step-up in

expenditure was driven by the company’s effort to expand outside Norway and

diversify geographically. Going forward, we expect that E&P will maintain at least

this level of spending in order to sustain a minimal level of growth of around 2-3

percent.

We believe it is reasonable to assume a long-term growth of 2 percent per annum due

to E&P limited opportunities both nationally and internationally and that they want to

maintain its present reserve life of 12.65 years. In order to manage this, they first have

to replace 100 percent of its annual production (193.6 mboe in 2003). In addition,

106 Johnston, D. 1992, Oil Company, Financial Analysis in Nontechnical Language, PennWell Publishing Company

E&P needs to expand its reserve base by 193.6 mboe * (1+2%) * 12.65 years = 2498

by the end of next year. Compared to initial reserves of 2449 mboe, this means

another 49 mboe need to be found, or 25 percent of the yearly production. All together,

to sustain a 2 percent growth rate at reserve life of 12.71, a reserve replacement rate of

125 percent is required each year.

This means that to realise the 125 percent reserve replacement rate, E&P’s future

capital expenditure has to be in the range of NOK 10-12 billion depending on the

company’s long-term growth ambition and F&D cost (Table 18). As mentioned under

the caption “Future Production Outlook” new reserves are likely to be much smaller

than the major findings in the 1990s. In addition, it is likely that the remaining

reserves on the NCS will be found longer north than current producing areas (for

example Barents Sea) where conditions are generally harsher. Both factors result in

increasing pressure on F&D cost-per barrel. Hydro has an F&D target of USD 6/bl

which, depending on the exchange rate, is NOK 35-45/bl. Based on the above

mentioned factors F&D cost is set to NOK 43.4 and our capital expenditure is set to

NOK 10.55 billion per year (193.6 mboe per year x 125 percent x NOK 43.4/bl).

Table 18: Hydro Exploration and Production Capital Expenditure107

F&D cost (NOK/bl)

Production growth

(% per annum) 40 45 50 55 65

0% 7708 8671 9635 10598 11562

1% 8687 9773 10859 11945 14117

2% 9667 10875 12084 13292 15709

3% 10647 11977 13308 14639 17301

4% 11626 13079 14533 15986 18892

5% 12606 14181 15757 17333 20484


107 See appendix 12, Note. Different scenarios, in NKr billion

9.3.3. Hydro Energy and Oil Marketing Capital Expenditure

With regard to E&OM capital expenditure, we make a simplified assumption. We

assume that E&OM, in order to maintain its position in the European energy market,

equals their capital expenditure with its deprecation.

9.3.4. Working Capital

Between 2000 and 2003, the net working capital was about 11.5 percent of the total

revenue. The only significant change in any single items during this period was other

current liabilities and prepaid expenses and other current assets. We believe these

items will revert to a normal level of 17.5 percent and 3.3 percent respectively.

Further, we believe that Hydro in the near future will not consider any acquisition or

other growth strategies that differ from the ordinary, given our oil and gas price

forecast, as it historically has shown that oil mergers occur under periods with low oil

prices108. For that reason, we generate a forecasted level of working capital of 11.5

percent of the revenues.

9.3.5. Depreciation

Most of the depreciable assets purchased by Hydro are related to the company’s

operating facilities on the NCS and the international continental shelf. In the years

2000 to 2003, deprecation was between 10.3 percent and 12.2 percent of net plant,

property and equipment for E&P, and between 0.3 percent and 1.1 percent for E&OM.

We assume that the depreciation remains constant for net plant, property, and

equipment (PPE) at respectively 12.2 percent and 0.8 percent. Further, we forecast

that net PPE will remain same as in 2003, due to our consideration of Hydro’s future

acquisitions and growth strategies as mentioned earlier.

108 With the exception of the Chevron/Texaco merger in October 2000 where the Brent price was USD 31/boe, the Brent prices have been between USD 10/boe and USD 19/boe for the recent mergers since 1998 (BP/Amaco, Exxon/Mobil, TotalFina, Repsol/YPF, BP Amoco/Arco, Norsk Hydro & Statoil/Saga, TotalFina/Elf Aquitiane and Conoco/Philips Petroleum).

9.3.6. Projecting Other Assets

Other current assets and non current assets, which are unrelated to the level of

production and sales, are kept at their value on the last day of fiscal year 2003.

9.3.7. Projecting Other Liabilities

The annual report provides the amortization schedule for Norsk Hydro ASA’s existing

debt. We reduce the amount of outstanding long-term debt according to the maturity

schedule provided in the notes to Norsk Hydro ASA’s 2003 annual report (see table

19).

Table 19: Hydro’s Maturity Schedule109

Year 2004 2005 2006 2007 2008 Current portion of long-term debt 1241 1349 781 582 525

Remaining balance of long-term debt 28568 27220 26439 25857 25332

Source: Annual Report Norsk Hydro ASA 2003

Further, we hold short-term debt and other long-term liabilities constant since they are

not directly related to the Hydro’s level of activity.

Minority shareholders interest in consolidated subsidiaries is kept at the level on the

last day of fiscal year 2003, whereas we for simplicity assume that Hydro repurchase

shares to make the liabilities equal to assets of net income. Excess cash is paid to

shareholders through dividend.

9.3.8. Other

Eliminations revenues and eliminations other operating expenses as percentages of

revenues, have both been equal to around 46 percent. For simplicity, we forecast that

it will remain as the average for 2000 to 2003 in the forth-coming years.

109 Note, these numbers represent Norsk Hydro ASA and are adjusted for Norsk Hydro Oil and Energy’s 2003 ratio of 44%.

9.4. Estimation of Cost of Capital

9.4.1. The Discounted Cash Flow Model

The foundation in a DCF model is to discount the future free cash flow of the firm

(FCF) at the rate equal to the cost of capital of the firm. The FCF is the cash flow

available after necessary capital expenditures that have been made to sustain or

maintain productive capacity. For an oil company maintenance capital would include

funds necessary to drill wells and maintain facilities. We have chosen to create the

FCF using the following model110:

Net Income

+ Deprecation, Depilation and Amortization111

+ Exploration Expenses (1-taxes)112

- Gross Investments113

= Free Cash Flow

9.4.1.1. Weighted Average Cost of Capital (WACC)

The general formula for estimating the after-tax WACC is simply the weighted

average of the marginal after-tax cost of each source of capital:

)1( cde trVD

rVE

WACC −+= ,

E = book value of the firm's equity

re = required rate of return for equity

D = book value of the firm's interest bearing debt

rd = required rate of return for debt

V = E + D

110 Johnston, D. 1992, Oil Company, Financial Analysis in Nontechnical Language, PennWell Publishing Company 111 See section 9.3.5 112 We forecast Hydro’s exploration expenses to be the average for 1999 to 2003 (See figure 25). 113 See section 9.3.2., 9.3.3 and 9.3.4.

tc = marginal corporate tax rate

We have chosen to use one single WACC for the entire forecast. This most common

even though the most theoretical correct approach is to use a different WACC each

year. Based on the components from figure 25, we assume Hydro’s WACC to be

6.3% for the entire forecast114. In the following sections, we will go through each

component showed in the figure below.

Figure 25: Components of the WACC

9.4.1.2. Capital Structure

The Modigliani-Miller Theorem states that in the absence of taxes and other market

frictions, the capital structure does not affect firm values. However, the real world is

different from the simple world in which Modigliani and Miller’s assumptions are

based on. Since the different providers of capital request different rates of return

according to the risk they are facing, capital structure does influence on the WACC

114 See appendix 13

WACC

Cost of debt capital

DebtEquity

Cost of equity capital

Risk free rateRisk premiumBeta

Capital Structure

and therefore on the value of a firm115. A company’s debt ratio may therefore not

reflect the capital structure expected to prevail over the life of the business as it

depends on the investment activity. To determine Hydro’s future capital structure we

utilize their historical net interest bearing debt supported by how their investment

activity will change their capital mix.

As their debt is not publicly traded, we assume their common debt to be equal to the

book value. To find the market value of Hydro’s equity, we make a simplified

assumption that the equity is equal to its book value. We find this assumption

reasonable as Hydro is a part of a conglomerate and therefore not publicly traded.

Hydro has acquired a number of different company’s outstanding shares. However,

the annual report does not specify the exact number of shares of each company. We

have therefore limited our analysis to the total amount and valued the minorities equal

to their book value.

Hydro will have around 16 new projects coming on stream that would probably

require an investment activity in the region of 36-40 billion NOK. These anticipated

activities will most likely ensure a greater debt ratio by that Hydro is financing the

activity by their equity or by obtaining more debt. Opposed to Hydro’s past years

activity and its size, we find it therefore reasonable to believe that the current

debt/equity ratio do not reflect the targeted capital structure. We have therefore

chosen a debt ratio of 40% as the target, which also is comparable with their peers.

Table 20: Hydro’s Target Ratio116

Year 2000 2001 2002 2003 Average Target Equity Ratio 0.55 0.60 0.64 0.74 0.63 0.60

Debt Ratio 0.45 0.40 0.36 0.26 0.37 0.40

115 Miller, M. H. 1988, The Modigliani-Miller Propositions After Thirty Years, Journal of Applied Corporate Finance 116 See appendix 14, 15 and 16

9.4.1.3. The Cost of Equity

The cost of equity is estimated as the opportunity cost of equity financing sources.

There are two widely used models to estimate the cost of equity: CAPM117 and

APT118. Empirical evidence confirms that APT explains expected return better than

CAPM119. However, due to extreme complexity, the APT can reach and the slight

differences in explanatory power between both models, the CAPM is the dominant

model for estimating the cost of equity among firms120. We have therefore chosen the

CAPM model in our calculation of the cost of equity (ke).

The formula for the calculation of the cost of equity (ke) is:

ke = rf + β [E(rm)-rf]

rf = The risk-free rate of return

E(rm) = The expected rate of return on of the market portfolio

E(rm)-rf = The market risk premium

β (beta) = The systematic risk of the equity

After computing the below-mentioned values, we obtain a cost of equity of 8.11%121.

9.4.1.4. The Risk Free Rate

The risk free rate (rf) is the return on securities or portfolio of securities that has no

default risk and is completely uncorrelated to other assets. The best estimate of the

risk free rate would be a market portfolio with equities with a zero beta, but in

practice it is not practical to estimate the risk-free rate. The best alternative is to use

different alternatives of government securities considered the least risky asset in the 117 CAPM is a single factor model. The model distinguishes between systematic (non-diversifiable) and unsystematic (diversifiable) risk, which provides an easy and comprehensive understanding of risk and its components. 118 APT is a multi-factor model. These factors measure the state of the economy, interest rates, inflation and many other factors that can influence the rate of return of a security. 119 Copeland, T., Koller, T. and Murrin, J. 2000, Valuation Measuring and Managing the Value of Companies, Third Edition, McKinsey & Company Inc. 120 Bruner, Eades, Harris & Higgins 1998, Best Practices in Estimating the Cost of Capital: Survey and Synthesis, Financial Practice and Education Review 121 See appendix 13

market. These securities should be hold by the US government, because most of

Hydro’s debt is denominated in USD, and that the price of crude oil and natural gas

either are fixed in USD or affected by changes in exchange rate between home

currency and USD.

Copeland, Koller and Murrin (2000) recommend using long-term risk-free Treasury

bonds with maturities with ten years maturity or greater. They specifically

recommend using a 10-year Treasury bill rate since it approximates the duration of the

stock market index portfolio and its use is therefore consistent with the betas and

market risk premiums estimated relative to these market portfolios. Further, they

argue that a shorter time measure is not recommend to use, because it would not

match the duration of the company’s cash flows.

As a conclusion, we use the US 10-year T-bill, which was 4.52% at December 30

2003122.

9.4.1.5. Market Risk Premium

The market risk premium is the difference between the expected rate of return on the

market portfolio and the risk free rate (E(rm)-rf)123. Estimation of the market risk

premium can be based on either historical data, assuming that the future will be like

the past, or on ex ante estimates that attempt to forecast the future124. Both approaches

have their proponents and critics125. According to Claus Parum (2001), the historical

approach is the most widely used. The question is than if you should use 75-, 50- 10-

or 2 year historical average. We have chosen to use 5.35% as market risk premium,

which is based on a 2 years historical average for continental Europe126.

122 www.reuters.com 123 Copeland, T., Koller, T. and Murrin, J. 2000, Valuation Measuring and Managing the Value of Companies, Third Edition, McKinsey & Company Inc. 124 ibid 125 ibid 126 After a conversation with a DNB Markets analyst

9.4.1.6. Beta (β )

Beta is the measure of a company’s systematic risk relative to the stock market index

and can be derived from historical volatility and return data. Since we are talking

about a business unit within a conglomerate, it is not possible to estimate equity beta

by using stock data. To overcome this problem, we have un-levered the betas from

our peers in chapter 6, and then re-levered the average beta from the peers by using

Hydro’s target capital structure. This gives us a beta of 0.67127.

9.4.1.7. The Cost of Debt

The cost of debt is estimated as the weighted average opportunity cost of all non-

equity financing sources and reflects the markets required rate of return. In order to

get around this, we use the risk free rate from the caption “The risk free rate” and the

market risk premium for Hydro’s debt as it can be seen in the formula below:

Kd = (1 + Rf) + (1 + q)

Kd = Cost of debt for Hydro

Rf = Risk free rate of return

Q = Market risk premium for Hydro’s debt

The market risk premium for Hydro’s debt is rated by Standard & Poor’s and

Moody’s to be A and A2 respectively, which indicate a credit spread of approximately

36 basis points or 0.36%128. Using the formula above, we obtain a cost of debt of

3.51% after tax129.

127 See appendix 13 128 See appendix 17 129 See appendix 13

9.5. DCF - Valuation of Hydro

In the following tables, we present the final outputs from our valuation of Hydro.

9.5.1. Exploration and Production130

Table 21: Hydro Exploration and Production Income Statement 2003 – 2008E

E&P summary (NOKm) 2003 2004E 2005E 2006E 2007E 2008E

Oil production (kboe/d) 395 448 441 448 413 306

Gas production (kboe/d) 133 157 185 219 259 305

Hydrocarbon production (kboe/d) 526 605 626 667 672 611

Brent crude oil price $/bl 28.7 27.88 25.70 24.48 24.66 24.83

NOK/$ exchange rate 7.07 7.09 7.13 7.17 7.20 7.23

Brent Crude Oil Price, NOK/bl 203 193 192 177 170 173

Natural gas price $/bl 23.16 22.30 20.56 19,58 19,73 19,86

Natural Gas Price NOK/bl 151 158 147 140 142 144

E&P summary

Operating Revenues 37904 41378 39430 39940 40183 36501

Depreciation and amortization 9052 9729 9315 9778 9803 9373

Operating charges 10352 10882 10370 10504 10568 10202

Operating income 18500 20766 19745 19658 19812 16475

130 See appendix 18

9.5.2. Energy and Oil Marketing131

Table 22: Hydro Energy and Oil Marketing Income Statement 2003 – 2008E

E&OM summary (NOKm) 2003 2004E 2005E 2006E 2007E 2008E

Operating Revenues 49370 50604 51869 53166 54495 55858

Depreciation and amortization 591 635 608 638 640 612

Operating charges 46111 47264 48445 49657 50898 52170

Operating income 2668 2705 2816 2871 2957 3075

9.5.3. Hydro Oil and Energy132

From the above-mentioned assumptions, we have predicted the following cash flow

for Hydro Oil and Energy.

Table 23: Hydro Oil and Energy Cash Flow 2003 – 2008E

Hydro Oil & Energy (NOKm) 2003 2004E 2005E 2006E 2007E 2008E

Net Income 9352 10548 10137 10146 10251 8850

+ Depreciation and amortization 10364 9923 10416 10443 9985

+ Exploration Expenses 1354 1354 1354 1354 1354

- Capital Expenditure 11185 11158 11188 11190 11162

- Change Working Capital (1410) (184) 742 (525) (191)

= Free Cash Flow 12490 10440 9985 11382 9218

PV of FCF 11731 9210 8273 8858 6738

= Total PV of FCF 45045

Based on the discounted cash flow we find a present value of NOK 45054 billion for

the explicit forecast period. However, as mentioned under the caption “Budget

Period” we will value the after explicit period by valuing the present value of Hydro’s

reaming oil reserves in 2008.

131 See appendix 18 132 See appendix 19 and 20

According to our conclusion in section 9.2.1.3, we believe that Hydro still will have

reserves to book from reserve revisions and further field development. Hydro’s

reserve replacement rate (RRR) was last year 141%133, however, due to that expected

reserves is considered to be lower on the NCS and that Hydro’s international position

is considered to be unsteady we lower these estimates and assuming an RRR of 125%

for the next five-year period. With that said Hydro’s reserves in 2008 are seen at 2739

million barrels. According to our estimates in appendix 9 it is expected that 22% of

the reserves are oil with no RRR, whereas 42% today. However, we expect that it still

would be booked some reserves of oil and than especially from the international

continental shelf. Anyhow, most of the remaining reserves on the NCS are anticipated

to be booked as gas. We assume therefore 30% of the reserves in 2008 to be oil.

Furthermore, we assume a long-term oil price of USD 21.5 per barrel (long term

historical oil price), whereas the gas volumes are subjected to a sales price discount of

20%, in the line with historical standards. Operating costs are assumed to be NOK

25.5 per barrel (currently NOK 21), capital expenditure of NOK 30 per barrel

(average existing fields NOK 27), a tax rate of 50% (due to expected decline in tax

rate on the NCS). The value of the discounted cash flow of 2008 reserves is NOK

48678 billion of which oil reserves are valued at NOK 21.2 billion and gas reserves at

NOK 27.4 billion134. We find that a fair value of Hydro’s equity to be around NOK

83.3 billion.

9.6. Sensitivity Analysis

In the following section, we analyse the valuation model’s sensitivity towards changes

in certain value drivers.

As shown from the sensitivity analysis in table 24, we can notice that beside from

changing the exchange rate (USD/NOK), changes in the oil/gas price and WACC

133 excluding sales, purchases and swaps 134 See appendix 18

have greater relative impact on the equity value of Hydro than “other operating costs”.

Further, we find that the risk free rate has greater relative impact on the equity value

than risk premium and beta, within the WACC.

From the sensitivity analysis, we therefore conclude that the exchange rate and the

commodity prices are the most crucial factors influencing Hydro’s equity value.

Changes in these parameters involve respectively – 10.4% and +10.5% and – 32.5 %

and +32.6% percentage change in equity value. It should be noticed that the oil price

tends to be negatively correlated with the development in the value of USD, which

means that a change in one of the factors to some extent will be compensated by a

positive change in the other factor135.

Table 24: Sensitivity Analysis

Relative change in value drivers % change in equity value

Operational drivers - Reference case + - +

Oil/gas price (-/+ 1 USD) 74.6 83.3 92.0 - 10.4% 10.5%

USD/NOK (-/+ 1 NOK) 56.1 83.3 110.5 - 32.5% 32.6%

Other operating costs (-/+1%) 85.0 83.3 81.6 2.0% - 1.9%

Cost of capital - Reference case + - +

WACC (-/+ 1%) 86.9 83.3 79.9 4.3% - 4.0%

Risk free rate (-/+0.5%) 85.5 83.3 81.2 2.7% - 2.5%

Beta (-/+ 0.1) 84.4 83.3 82.2 1.3% - 1.3%

Risk premium (-/+ 0.5%) 84.0 83.3 82.6 0.9% - 0.8%

9.7 Scenario Analysis136

The scenario analyse considers changes in the oil and gas prices and the exchange rate.

These factors have, as seen in the sensitivity analysis, great impact on Hydro’s equity

value. Another issue concerning these factors is that they historically have been highly

volatile and can change rapidly in the future.

135 Edwards, A.G., Global Oil Market Analysis. January 22, 2004 136 See appendix 21(best) and 22(worst)

As discussed in earlier chapters, we believe the exchange rate between USD and NOK

to stay at more or less at the same level as today in the forthcoming five-year period,

since both the Norwegian and the US economy seem to be going in the same direction.

In the case of oil and gas prices, however, we are far more uncertain about the future

(See chapter 6). Market uncertainty, production capacity and OPEC’s behaviour are,

among others, factors that highly influence oil and gas prices.

In the scenario analysis, we look at the best and worst case scenario considering these

factors. We assume other factors to stay constant – one because they are less volatile

and secondly because they have less impact (or minimal) on the equity value of Hydro.

In the best case scenario we assume the oil price to equal the high oil price projected

by IEO2003 (see figure 17). In line with historical standards, the gas price is assumed

being 20 percent lower than the oil price. As mentioned, high oil prices influence the

exchange rate. We find it therefore realistic that in the case of a low exchange rate, the

oil price will increase and vice versa. In the best case, we therefore assume the

exchange rate to be 7.00 USD/NOK, which is slightly lower than in the reference case.

In the worst case, we assume the oil price to equal the low price projected by

IEO2003 (see figure 17). The gas price is accordingly decreasing – sold at 20 percent

discount in relation to the oil price. In the worst-case scenario, we set the exchange

rate to 7.50 USD/NOK. The increased exchange rate will have a positive effect on the

value of Hydro, but not as significant as the negative effect of the decrease in oil and

gas prices.

As seen in the appendix 23 and 24, the best and worst-case scenarios respectively

valuate Hydro’s equity to NOK 95.2 billion and NOK 75.8 billion, which indicates a

price range of 19.4 billion. Even though we have been realistic creating the scenarios,

the range is quite wide. Both the sensitivity and the scenario analyses indicate that

Hydro’s equity value changes radically according to changes in key variables.

9.8. EV/EBITDA Multiple Valuation of Hydro Oil & Energy

As a supplement to our DCF-valuation, we have estimated Hydro’s value based on

EV/EBITDA method.

9.8.1. Peer Multiples

The EBITDA valuation measure is hard to interpret in our selected peer group from

chapter 6. This is due to the relatively large differences in effective tax rates. The peer

group has an average effective tax rate of 45% based on a four-year average, from

ENI’s 30% to Statoil ASA’s 66%. For that reason, we have chosen to only use Statoil

as peer, since both Hydro and Statoil ASA is more or less affected by the same tax

regime.

The EV/EBITDA multiple for Statoil is currently 3.4137 , which gives Hydro an

enterprise value of NOK 108.2 billion and an equity value of NOK 97.8.billion138.

However, we believe that Hydro should be traded at a substantial discount compared

to Statoil ASA because:

Statoil ASA’s operations are around twice the size of Hydro’s;

Statoil ASA has a better record, particularly internationally; and

Statoil ASA seems better positioned in the European gas market. In addition to

larger gas reserves, Statoil ASA is also producing gas outside the NCS. In the

forthcoming years, Statoil ASA will serve the south European market from

Algeria and the southeast market with gas from the Caspian Sea.

137 DNB Markets. 2003, Sector Update, December 11 138 See appendix 25

9.9. EV/DACF Multiple Valuation of Hydro Oil & Energy

As a second supplement to our DCF- valuation, we have estimated Hydro’s value

based on the EV/DACF multiple. This multiple is according to UBS Warburg (2001)

most correct to apply on oil companies due to great differences in tax rates.

9.9.1. Peer Multiples

As shown in figure 26, the valuation multiples in the oil sector are heavily depended

on the size of each company. Since Hydro’s EV/DACF multiple is most likely

affected by the company’s conglomerate profile, we have used an average multiple

based on Hydro’s peers from chapter 6. However, we believe that Hydro should be

traded at a substantial discount compared to its peers, according to the same

arguments as pointed out in section 9.8.1.

Figure 26: EV/DACF Multiples139

Source: Company data, Deutche Bank

We value Hydro’s enterprise value and equity value to be NOK 104.8 billion and

NOK 92.8 billion140.

139 Hydro’s multiples is based on Norsk Hydro ASA 140 See appendix 25

0

2

4

6

8

10

12

0 5000 10000 15000 20000 25000

2003 Oil & Gas Reserves

2004

E E

V/D

AC

F

Norsk Hydro

StatoilRepsol YPF

ENI

ExxonMobil

BP

Chevron/Texaco

TotalRD/Shell

10. Conclusion

Our aim has been to analyse Norsk Hydro Oil and Energy as external analysts and to

determine a fair value of the company. The focus has been on the E&P segment, due

to the fact that nearby 90 percent of the division’s operating income is derived from

this segment. We have assessed possible strategic frameworks and valuation methods

best suited to analyse and valuate a petroleum company. In order to process a fair

value of Hydro we have also analysed important factors such as commodity prices and

exchange rates.

The petroleum industry is a problem solving industry largely driven by economic

growth and technological developments. The products are homogeneous and the

prices are determined on the world market. Since the resources are exhaustible and

owned by governments, governments and especially the OPEC organisation are strong

market players controlling oil production quotas. At the time being, there are no

substitutes threatening the petroleum products as the main energy resource. The

substitutes are either more polluting or too expensive. However, firmer environmental

restrictions and more investments in “greener” energy may constitute a threat in the

long term.

The competitiveness among the petroleum companies is fierce. Many companies

compete on each concession, and as there are few growth areas available, the

competitiveness will be even fiercer in the future. The remaining petroleum resources

are also to some extent located in harsher conditions, which requires more capital and

better technology.

In spite of the fierce competition, Hydro has financially performed at the upper class

compared to other oil companies and in the short term, the prospects of Hydro’s

Norwegian E&P activities are relatively bright. There are several projects coming on-

stream in the years ahead supporting the company’s 6% growth target for the NCS

and allows it to keep production cost per barrels under control. However, the NCS is a

mature region, offering a limited growth potential. Over the last four years, Hydro has

invested significant amounts in exploration activities abroad. This however, has not

yet lead to the material geographic diversification that the company was looking for

and Hydro failed to create international sources of long-term growth, though their

eventually partnership in Russia could indicate a turning point. The future long-term

opportunities on the NCS are also limited, as the region is maturing. Hydro has a

particular disadvantage not being among the largest oil companies. Super majors such

as Shell etc, are attractive partners to reserve holding countries, because they have a

more extensive record of accomplishment and the financial ability to make large

investments. Going forward, we believe that Hydro is “stuck in the middle”, with

limited strategic options. It will be important for Hydro to establish their position as a

one of the leading players in offshore exploration and development to succeed.

The world oil price is the most important external factor influencing the valuation of

Hydro. We have used the IEO2003 projections with comparisons, but the oil price has

historically been highly volatile and it is difficult to project. The gas is to some extent

traded geographically, and the prices vary. However, looking at historical prices the

gas price tends to follow the oil price. Hydro is also highly influenced by changes in

the NOK/USD exchange rate, since the world oil price is denominated in USD.

However, we have projected that the exchange rate NOK/USD will stay more or less

at today’s level in the forecasted period.

We have estimated Hydro’s fair value using three different approaches. The DCF

approach is qualitatively most correct. We are therefore using the EV/EBITDA and

EV/DACF multiples as supplements to evaluate the DCF estimate. Our calculations

gave the following results estimating the value of Hydro:

DCF method: NOK 82.6 billion

EV/EBITDA multiple: NOK 97.8 billion

EV/DACF multiple: NOK 92.8 billion

The EV/EBITDA and EV/DACF estimates are respectively 18.4% and 12.3% higher

than the DCF estimate. However, as pointed out earlier, both the EV/EBITDA and the

EV/DACF estimates are too high considering the fact that Hydro is a smaller

company and should be traded at a discount compared to its peers. The discrepancy

between our DCF valuation and our peer group valuations could reflect the discount.

Anyhow, the peer group valuations are supportive to our DCF valuation.

Looking at the sensitivity analyse, we found that small changes in key factors have

great impact on the estimated value. We also have to be aware that Hydro could make

significant oil and gas discoveries, which clearly will have huge impact on the

valuation (Shotkman field). In the future, it may be that real options would outset the

DCF valuation, considering the uncertainty aspect valuating an oil company.

Figure List

FIGURE 1: NORSK HYDRO ASA'S BUSINESS AREAS (2002 NUMBERS) ...........................1

FIGURE 2: THE VALUE CHAIN ACTIVITY TEMPLATE.......................................................6

FIGURE 3: THE THREE STREAMS WITHIN THE PETROLEUM INDUSTRY ............................7

FIGURE 4: VALUE CREATION LOGIC IN UPSTREAM ACTIVITIES ....................................10

FIGURE 5: THE VALUE SHOP.........................................................................................11

FIGURE 6: VALUE SHOP DIAGRAM FOR A PETROLEUM EXPLORER (A) AND FIELD

DEVELOPER (B) ....................................................................................................15

FIGURE 7: THE POSITIVE SUCCESS FEEDBACK LOOP IN EXPLORATION.........................18

FIGURE 8: DISTRIBUTION OF OIL CONSUMPTION 1970 - 2020.......................................31

FIGURE 9: WORLD NATURAL GAS CONSUMPTION (LEFT) AND NATURAL GAS

CONSUMPTION IN THE DEVELOPING WORLD, 1970 - 2025 .....................................31

FIGURE 10: GROWTH RATES IN GDP FROM 1993-2002 DISTRIBUTED BETWEEN

DEVELOPING COUNTRIES AND THE WORLD ..........................................................32

FIGURE 11: WORLD ENERGY CONSUMPTION BY ENERGY SOURCE ...............................36

FIGURE 12: MAJOR FINDINGS FROM THE PEST ANALYSIS............................................37

FIGURE 13: SUMMARY OF THE FIVE FORCES ANALYSIS................................................45

FIGURE 14: CRUDE OIL PRICES SINCE 1861 IN NOMINAL AND REAL TERMS ................62

FIGURE 15: OIL PRICES SINCE 1996 COMPARED TO OPEC’S “OPTIMAL” PRICE RANGE

..............................................................................................................................63

FIGURE 16: GLOBAL OIL DEMAND (ABOVE) AND SUPPLY FORECAST ...........................64

FIGURE 17: WORLD OIL PRICES IN THREE CASES 1998 – 2008.....................................68

FIGURE 18: NATURAL GAS CONSUMPTION IN WESTERN EUROPE 1970 - 2025 .............71

FIGURE 19: THE EXCHANGE RATE BETWEEN NOK AND USD DURING THE PERIOD 1990

– 2003...................................................................................................................75

FIGURE 20: STATED PRODUCTION GROWTH TARGETS PER YEAR BY MAJOR OIL

EXPLORATION AND PRODUCTION COMPANIES ......................................................79

FIGUR 21: ESTIMATED UNDISCOVERED RESOURCES ON NCS – ESTIMATE REVISION

2001/2004 (BILLION BOE) .....................................................................................83

FIGURE 22: OIL AND GAS RESERVES DISCOVERED IN NORWAY 1972-2002 .................84

FIGURE 23: OIL VERSUS GAS MIX AND IMPACT ON REVENUE 2003/2007.....................86

FIGURE 24: EXPLORATION EXPENDITURE NORWAY VERSUS INTERNATIONAL 1999-2003

(NOK MILLION) ....................................................................................................87

FIGURE 25: COMPONENTS OF THE WACC ..................................................................100

FIGURE 26: EV/DACF MULTIPLES.............................................................................111

Table List

TABLE 1: LEVELS OF STRATEGIC ANALYSIS ...................................................................5

TABLE 2: OVERVIEW OF ALTERNATIVE VALUE CONFIGURATIONS .................................9

TABLE 3: EVALUATION OF VALUATION METHODS .......................................................28

TABLE 4: SWOT ANALYSIS OF HYDRO ........................................................................50

TABLE 5: PEER GROUP COMPARISON............................................................................53

TABLE 6: OIL MARKET MODELS...................................................................................56

TABLE 7: OPEC OIL PRODUCTION (LEFT) AND NON-OPEC PRODUCTION 1990 –

2025(MILLION OF BARRELS PER DAY)...................................................................65

TABLE 8: ESTIMATED WORLD OIL RESOURCES 2000 - 2025(BILLION OF BARRELS).....66

TABLE 9: NORTH SEA OIL PRICE (BRENT OIL) PROJECTIONS .......................................69

TABLE 10: COMPARISON OF WORLD OIL PRICE PROJECTIONS 2005 - 2025 (2001 USD

PER BARREL) .........................................................................................................69

TABLE 11: HYDRO’S HISTORIC REALISED GAS PRICES (NUMBERS IN USD).................72

TABLE 12: GAS PRICES AS A PRODUCT OF FUTURE OIL PRICES (NUMBERS IN USD)....73

TABLE 13: NOK/USD ESTIMATED EXCHANGE RATE...................................................76

TABLE 14: NEW PROJECTS COMING ON-STREAM (RESERVES AND PRODUCTION IN MBOE)

..............................................................................................................................80

TABLE 15: HYDRO’S NATIONAL OIL AND GAS PRODUCTION........................................86

TABLE 16: INTERNATIONAL FIELDS TO COME ON-STREAM (IN MILLION MBOE) ...........88

TABLE 17: HYDRO’S INTERNATIONAL OIL PRODUCTION ..............................................91

TABLE 18: HYDRO EXPLORATION AND PRODUCTION CAPITAL EXPENDITURE..............96

TABLE 19: HYDRO’S MATURITY SCHEDULE .................................................................98

TABLE 20: HYDRO’S TARGET RATIO ..........................................................................101

TABLE 21: HYDRO EXPLORATION AND PRODUCTION INCOME STATEMENT 2003 – 2008E

............................................................................................................................105

TABLE 22: HYDRO ENERGY AND OIL MARKETING INCOME STATEMENT 2003 – 2008E

............................................................................................................................106

TABLE 23: HYDRO OIL AND ENERGY CASH FLOW 2003 – 2008E ...............................106

TABLE 24: SENSITIVITY ANALYSIS .............................................................................108

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Appendix

Appendix 1: Projecting Norsk Hydro’s Oil and Energy Income and Balance Sheets

Appendix 2: Cost Figures Upstream Oil Industry

Appendix 3: Success Rate Hydro Oil and Energy

Appendix 4: Financial Analysis

Appendix 5: World Oil Prices in Three Cases 1998 - 2008

Appendix 6: Correlation Oil and Gas Prices

Appendix 7: Forecast of On-Stream Oil and Gas Fields for Hydro on NCS

Appendix 8: Norsk Hydro Oil and Energy 3P Reserves

Appendix 9: Total Oil & Gas Production

Appendix 10: International Oil Production Forecast

Appendix 11: Spread Sheet Assumptions

Appendix 12: Norsk Hydro Oil and Energy Field & Development Costs

Appendix 13: Norsk Hydro Oil and Energy WACC

Appendix 14: Norsk Hydro Oil and Energy Net Interest Bearing Debt

Appendix 15: Norsk Hydro ASA Balance Sheet

Appendix 16: Norsk Hydro Oil and Energy Balance Sheet and Income Statement

Appendix 17: Market Risk Premium for Norsk Hydro Oil and Energy’s Debt

Appendix 18: Projected Income Statement for Exploration and Production and

Energy and Oil Marketing

Appendix 19: Norsk Hydro Oil and Energy’s Net Working Capital

Appendix 20: Norsk Hydro Oil and Energy DCF-Valuation

Appendix 21: Best Case Scenario

Appendix 22: Worst Case Scenario

Appendix 23: Norsk Hydro Oil and Energy DCF-Valuation (Best Case Scenario)

Appendix 24: Norsk Hydro Oil and Energy DCF-Valuation (Worst Case Scenario)

Appendix 25: EV/EBITDA and EV/DACF valuation of Norsk Hydro Oil and Energy

Appendix 26: Income Statement and Balance Sheet for ENI, Repsol YPF and Statoil

ASA

Appendix 1

Projecting Norsk Hydro’s Oil and Energy Income and Balance Sheets1

Due to non-existing official income and balance sheet for Hydro Oil and Energy, we have made the following assumptions to construct a complete income statement and balance sheet:

Income Statement

Both the posts “minority interest” and “cumulative effect of change in accounting principle” seem to have minor effect on the net income due to their sizes. We have therefore made a simplified assumption where we separate these posts based on Hydro’s revenue share of Norsk Hydro ASA’s revenue for each year.

Example: As Hydro’s revenue amount to around 35% of Norsk Hydro ASA’s revenue in 2003, and the post “Cumulative effect of change in accounting principle” amount to NOK 281 million for Norsk Hydro ASA, the post respectively amount to NOK 98 million for Hydro (281 * 0.35 = 98).

Balance Sheet

With regard to the stated balance sheet in Norsk Hydro ASA’s annual report, we face several problems:

1. Current Assets

In connection to the “current assets”, the “current deferred taxes” is found by subtracting “total current assets”2 from “total current assets” excluding “current deferred taxes”3 . The percentage share of Hydro’s “total current assets” versus Norsk Hydro ASA’s “total current assets” estimates the remaining posts within “total current assets”. This percentage is multiplied with “cash and cash equivalents”, “other liquid assets”, “accounts receivable”, “inventories”, “prepaid expenses and other current assets” from Norsk Hydro ASA’s balance sheet.

Example: As Hydro’s “current assets” amounted to around 21% of Norsk Hydro ASA’s “current assets” in 2003, and the post “cash and equivalents” amount to NOK 15249 million for Norsk Hydro ASA, the post respectively amounts to NOK 3189 million for Hydro (15249 * 0.21 = 3189)

2. Non-Current Assets

With regard to “non-current assets”, most of the information is found on page 106 and 142 in Norsk Hydro ASA’s annual report 2003, with exception of “deferred tax assets”. The “deferred tax assets” is found by subtracting the total amount of “non-current assets” from the following post “non-consolidated investees, property, plant and equipment”, “less accumulated depreciation”, “depletion and amortization”, “prepaid pension, investments and other non-current assets”.

3. Total Liabilities and Equity

With regard to the “total liabilities and equity”, we know the following:

• The amount of “other current liabilities” and “other long-term liabilities”

• Total assets amount to be a certain percentage of Norsk Hydro ASA’s “total assets” and that “total assets” = “total liabilities and equity”. This implies that “total liabilities and equity” also should amount to the same percentage of Norsk Hydro ASA’s “total liabilities and equity”.

We have applied this percentage to the following posts: “bank loans and other interest bearing short-term debt”, “current portion of long- term debt” and “current deferred tax liabilities” and “minority shareholders interest in consolidated subsidiaries”. In order to obtain the value of “shareholders equity”, we have used the value of the “shareholders equity” from Norsk Hydro Produksjon AS, which represent Hydro’s Norwegian operations accounting for around 80% of Hydro’s revenues. As this value is not sufficient to equal “total liabilities and equity” and “total assets”, we have made simplified assumption that equals this account. Since they also have operations abroad, we estimate the remaining value to be equity for their international operations.

1 Information from Hydro ASA’s annual report 2002 and 2003, together with Norsk Hydro Production AS 20022 Annual report 2003, page 1063 Ibid, page 142

Appendix 2

Cost Figures Upstream Oil IndustryAmounts in NOK millionExploration activity 2002 costs % 2003 costs % AverageSupport Administration 735 16,4 % Support Administration 657 15,9 % 16 %problem finding, solving General exploration 731 16,3 % problem finding, solving General exploration 610 14,8 % 16 %chocie, execution Exploratry drilling 2710 60,4 % chocie, execution Exploratry drilling 2451 59,3 % 60 %Evaluation Field evaluation 308 6,9 % Evaluation Field evaluation 416 10,1 % 8 %Total 4484 100,0 % Total 4134 100,0 % 100 %

Field Development 2002 costs % 2003 costs % AverageProblem finding Field development services 6578 24,4 % Problem finding Field development services 9780 32,8 % 29 %Problem solving, Choice Building contrancts 2384 8,8 % Problem solving, Choice Building contrancts 2797 9,4 % 9 %Execution, evaluation Proudction drilling 18014 66,8 % Execution, evaluation Proudction drilling 17213 57,8 % 62 %

on stream preparation on stream preparationTotal 26976 100 % Total 29790 100,0 % 100 %

Source: Statistics Norway 2004

Appendix 3

Success Rate Norsk Hydro Oil and EnergyExploration 1998 1999 2000 2001 2002 2003 AverageProductive 7 10 12 15 12 N/A 11,2Dry 16 24 15 14 17 N/A 17,2Total Drilled 23 34 27 29 29 28,4Success rate 30,4 % 29,4 % 44,4 % 51,7 % 41,4 % 39,5 %

Source: Norsk Hydro ASA Annual report 1997 - 2003

Appendix 4

Profitability RatiosNorsk Hydro Oil and Energy Avereage Statoil ASA Avereage

2000 2001 2002 2003 2000 2001 2002 2003EBITA 21806 19177 15947 21143 EBITA 8601 8051 6180 6150Invested capital 46549 47301 48987 49512 Invested capital 27999 26071 22326 22412

47 % 41 % 33 % 43 % 31 % 31 % 28 % 27 %

(1-Cash tax rate) 56 % 42 % 43 % 39 % (1-Cash tax rate) 33 % 32 % 20 % 36 %

ROIC 26,3 % 16,9 % 13,9 % 16,6 % 18,4 % ROIC 10,0 % 9,7 % 5,6 % 9,9 % 8,8 %

EBITA 21806 19177 15947 21143 EBITA 8601 8051 6180 6150Revenues 55123 52180 55845 59959 Revenues 32953 33859 34839 35633EBITA Margin 39,6 % 36,8 % 28,6 % 35,3 % 35,0 % EBITA Margin 26,1 % 23,8 % 17,7 % 17,3 % 21,2 %

Revenues 55123 52180 55845 59959 Revenues 32953 33859 34839 35633Invested capital 46549 47301 48987 49512 Invested capital 27999 26071 22326 22412Capital turnover 1,18 1,10 1,14 1,21 1,16 Capital turnover 1,18 1,30 1,56 1,59 1,41

ENI SPA Avereage Repsol YPF SA Avereage2000 2001 2002 2003 2000 2001 2002 2003

EBITA 12738 12293 10054 11254 EBITA 7062 5436 6396 6891Invested capital 47619 54427 54933 55741 Invested capital 38154 43395 31634 30384

27 % 23 % 18 % 20 % 19 % 13 % 20 % 23 %

(1-Cash tax rate) 60 % 66 % 63 % 66 % (1-Cash tax rate) 76 % 79 % 90 % 82 %

ROIC 16,0 % 14,9 % 11,6 % 13,3 % 14,0 % ROIC 14,1 % 9,8 % 18,2 % 18,6 % 18,5 %

EBITA 12738 12293 10054 11254 EBITA 7062 5436 6396 6891Revenues 57757 58943 57945 61963 Revenues 54090 51619 43149 43996EBITA Margin 22,1 % 20,9 % 17,4 % 18,2 % 19,6 % EBITA Margin 13,1 % 10,5 % 14,8 % 15,7 % 13,5 %

Revenues 57757 58943 57945 61963 Revenues 54090 51619 43149 43996Invested capital 47619 54427 54933 55741 Invested capital 38154 43395 31634 30384Capital turnover 1,21 1,08 1,05 1,11 1,12 Capital turnover 1,42 1,19 1,36 1,45 1,35

Liquidity RatiosNorsk Hydro Oil and Energy Avereage Statoil ASA Avereage

2000 2001 2002 2003 2000 2001 2002 2003Current Assets 14276 13125 21552 16470 Current Assets 7932 6976 8344 8484Current Liabilities 14333 13569 21257 14771 Current Liabilities 7973 8344 8534 8245Current Ratio 1,00 0,97 1,01 1,12 1,02 Current Ratio 0,99 0,84 0,98 1,03 0,96

Inventory 3029 2317 5425 3629 Inventory 606 757 777 716Current Assets 14276 13125 21552 16470 Current Assets 7932 6976 8344 8484Current Liabilities 14333 13569 21257 14771 Current Liabilities 7973 8344 8534 8245Quick Ratio 0,78 0,80 0,76 0,87 0,80 Quick Ratio 0,92 0,75 0,89 0,94 0,87


Current Assets 21615 21175 25750 24274 Current Assets 13737 14317 13116 14195Current Liabilities 22211 19804 25532 25282 Current Liabilities 17108 15479 10566 12044Current Ratio 0,97 1,07 1,01 0,96 1,00 Current Ratio 0,80 0,92 1,24 1,18 1,04

Inventory 2794 2474 3784 2474 Inventory 3145 2490 2506 2494Current Assets 21615 21175 25750 24274 Current Assets 13737 14317 13116 14195Current Liabilities 22211 19804 25532 25282 Current Liabilities 17108 15479 10566 12044Quick Ratio 0,85 0,94 0,86 0,86 0,88 Quick Ratio 0,62 0,76 1,00 0,97 0,84

Current Ratio Hydro Peers Quick Ratio Hydro PeersAnnual 1,12 1,06 Annual 0,87 0,934 year average 1,02 1,00 4 year average 0,80 0,86

Solvency RatiosNorsk Hydro Oil and Energy Avereage Statoil ASA Avereage

2000 2001 2002 2003 2000 2001 2002 2003Total Liabilities 64436 63590 70953 62968 Total Liabilities 20908 21209 21279 21711Equity 23193 25210 29456 33978 Equity 9725 7423 8175 10061Equity to Total Liabilities 0,36 0,40 0,42 0,54 0,43 Equity to Total Liabilities 0,47 0,35 0,38 0,46 0,42

Total Debt 32411 30602 36399 27340 Total Debt 5303 5993 5323 5345Equity 23193 25210 29456 33978 Equity 9725 7423 8175 10061Total Debt to Equity Ratio 1,40 1,21 1,24 0,80 1,16 Total Debt to Equity Ratio 0,55 0,81 0,65 0,53 0,63


Total Liabilities 37965 43204 46769 48057 Total Liabilities 44079 43635 28945 28854Equity 29741 33630 31049 31568 Equity 17907 17191 16065 16120Equity to Total Liabilities 0,78 0,78 0,66 0,66 0,72 Equity to Total Liabilities 0,41 0,39 0,56 0,56 0,48

Total Debt 12783 14638 18234 19220 Total Debt 26101 24893 14512 12798Equity 29741 33630 31049 31568 Equity 17907 17191 16065 16120Total Debt to Equity Ratio 0,43 0,44 0,59 0,61 0,52 Total Debt to Equity Ratio 1,46 1,45 0,90 0,79 1,15

Equity to Total Liabilities Hydro Peers Total Debt to Equity Ratio Hydro PeersAnnual 0,54 0,56 Annual 0,80 0,644 year average 0,43 0,54 4 year average 1,16 0,77

Source: Norsk Hydro ASA's Annual Report 2000 - 2003, Reuters.com

Appendix 5

World Oil Prices in Three Cases - US OilYear Historic Year Reference Case Low Case High Case1970 11,26 2003 27,29 27,29 27,291971 11,51 2004 26,88 16,87 30,811972 11,21 2005 24,70 16,99 31,181973 13,44 2006 23,48 16,99 31,621974 37,87 2007 23,66 16,99 32,041975 38,55 2008 23,83 16,99 32,441976 35,28 2009 24,01 16,99 32,921977 35,74 2010 24,18 16,99 33,281978 33,46 2011 24,37 16,99 33,621979 45,96 2012 24,54 16,99 33,831980 65,70 2013 24,73 16,99 34,021981 65,73 2014 24,90 16,99 34,171982 56,02 2015 25,08 16,99 34,241983 47,08 2016 25,27 16,99 34,321984 44,78 2017 25,46 16,99 34,401985 40,54 2018 25,65 16,99 34,481986 20,58 2019 25,84 16,99 34,561987 25,86 2020 26,03 16,99 34,641988 20,10 2021 26,22 16,99 34,721989 24,03 2022 26,41 16,99 34,801990 27,85 2023 26,61 16,99 34,881991 23,08 2024 26,80 16,99 34,961992 21,95 2025 27,01 16,99 35,041993 18,991994 17,881995 19,34 Year Historic oil pReference caLow oil pric High oil price1996 22,85 1998 12,921997 20,13 1999 18,251998 12,92 2000 28,711999 18,25 2001 22,262000 28,71 2002 23,712001 22,26 2003 27,29 27,29 27,29 27,292002 23,71 2004 26,88 16,87 30,81

2005 24,7 16,99 31,18Source: IEO2003 2006 23,48 16,99 31,62

2007 23,66 16,99 32,042008 23,83 16,99 32,44

World Oil Prices in Three Cases, 1998-2008 (IEO2003)

0

5

10

15

20

25

30

35

Year

USD

per

bar

rel

Historic oil price 12,92 18,25 28,71 22,26 23,71 27,29

Reference case 27,29 26,88 24,7 23,48 23,66 23,83

Low oil price 27,29 16,87 16,99 16,99 16,99 16,99

High oil price 27,29 30,81 31,18 31,62 32,04 32,44

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Appendix 6

Correlation Oil and Gas Prices 1990-2003Oil-Gas Oil-NOK/USD

Kovar 4,71 1,29Corr 0,65 0,26

Min 10,46 5,57Max 39,10 9,37StDev 5,31 0,93Average 20,75 7,23

Month Brent Oil Gas - US NOK/USD31.01.1990 20,06 6,51328.02.1990 19,48 6,52930.03.1990 18,38 6,545530.04.1990 17,12 1,565 6,5331.05.1990 16,24 1,59 6,5129.06.1990 16,14 1,519 6,40931.07.1990 19,84 1,411 6,146531.08.1990 26,75 1,5 6,0928.09.1990 39,1 1,935 6,06531.10.1990 34,41 2,36 5,89430.11.1990 29,2 2,445 5,84631.12.1990 28,27 1,95 5,869531.01.1991 20,06 1,38 5,78528.02.1991 18,68 1,373 5,96929.03.1991 18,17 1,405 6,602530.04.1991 19,42 1,375 6,731.05.1991 19,21 1,333 6,776528.06.1991 18,72 1,208 7,001531.07.1991 19,74 1,26 6,82130.08.1991 20,7 1,564 6,8330.09.1991 21,05 1,935 6,50631.10.1991 22,1 2,046 6,53429.11.1991 20,13 2,09 6,3931.12.1991 17,61 1,343 5,98531.01.1992 18,15 1,18 6,30428.02.1992 17,55 1,171 6,418531.03.1992 18,14 1,357 6,46430.04.1992 19,66 1,422 6,455529.05.1992 20,79 1,625 6,257530.06.1992 20,41 1,518 5,96931.07.1992 20,47 1,892 5,824531.08.1992 19,87 2,112 5,5730.09.1992 20,34 2,515 5,7830.10.1992 19,45 2,295 6,24430.11.1992 18,84 2,087 6,631.12.1992 18,29 1,687 6,947529.01.1993 18,47 1,597 6,8726.02.1993 18,92 1,856 731.03.1993 18,9 2,069 6,865830.04.1993 19,15 2,365 6,703531.05.1993 18,6 2,141 6,76830.06.1993 17,51 2,181 7,21430.07.1993 16,75 2,22 7,46531.08.1993 17,08 2,375 7,279530.09.1993 17,43 2,291 7,16529.10.1993 15,8 2,368 7,391330.11.1993 14,52 2,243 7,46131.12.1993 13,2 1,997 7,536531.01.1994 14,22 2,554 7,45128.02.1994 13,35 2,208 7,395531.03.1994 13,25 2,075 7,28529.04.1994 15,69 2,067 7,170831.05.1994 16,45 1,917 7,141730.06.1994 17,52 2,184 6,923529.07.1994 18,59 1,893 6,907531.08.1994 16,36 1,586 6,933930.09.1994 17,15 1,657 6,784531.10.1994 16,92 1,95 6,533530.11.1994 17,11 1,695 6,831330.12.1994 16,5 1,725 6,76431.01.1995 16,8 1,354 6,6828.02.1995 16,87 1,483 6,485131.03.1995 17,5 1,685 6,137928.04.1995 19,06 1,662 6,242531.05.1995 17,7 1,718 6,288430.06.1995 16,38 1,53 6,152231.07.1995 16,01 1,614 6,143131.08.1995 16,25 1,748 6,418129.09.1995 16,12 1,75 6,287631.10.1995 16,33 1,866 6,228230.11.1995 17,04 2,018 6,364329.12.1995 18,33 2,619 6,345731.01.1996 16,52 2,658 6,509729.02.1996 17,76 2,236 6,408829.03.1996 19,41 2,336 6,412430.04.1996 19,02 2,224 6,573531.05.1996 17,8 2,406 6,507828.06.1996 18,91 2,911 6,504431.07.1996 18,9 2,163 6,368

Brent Oil Prices 1999-2003

05

101520253035

Janu

ary-99

May-99

Septem

ber-9

9

Janu

ary-00

May-00

Septem

ber-0

0

Janu

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May-01

Septem

ber-0

1

Janu

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May-02

Septem

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2

Janu

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May-03

Septem

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3

Year

USD

per

bar

rel

Appendix 6

30.08.1996 20,78 1,859 6,411430.09.1996 23,21 2,214 6,492231.10.1996 22,67 2,728 6,38529.11.1996 22,77 3,497 6,425131.12.1996 23,81 2,757 6,377431.01.1997 22,52 2,385 6,48328.02.1997 18,85 1,821 6,740831.03.1997 19,38 1,926 6,615330.04.1997 18,52 2,184 7,120930.05.1997 19,4 2,239 7,112930.06.1997 18,51 2,139 7,329831.07.1997 18,94 2,177 7,626629.08.1997 18,51 2,714 7,482330.09.1997 19,9 3,082 7,062531.10.1997 20,02 3,552 7,024328.11.1997 18,94 2,578 7,19631.12.1997 16,52 2,264 7,373830.01.1998 15,96 2,257 7,593627.02.1998 14,17 2,321 7,58631.03.1998 14,26 2,522 7,622530.04.1998 14,46 2,221 7,45829.05.1998 14,37 2,17 7,557330.06.1998 13,38 2,469 7,66231.07.1998 13,09 1,844 7,541331.08.1998 12,56 1,752 7,804530.09.1998 14,68 2,433 7,38730.10.1998 13,22 2,275 7,30630.11.1998 10,46 1,976 7,506431.12.1998 10,53 1,945 7,551529.01.1999 11,35 1,777 7,536126.02.1999 10,88 1,628 7,897431.03.1999 15,24 2,013 7,764830.04.1999 16,57 2,253 7,809431.05.1999 15,2 2,358 7,892530.06.1999 17,51 2,394 7,831730.07.1999 19,37 2,543 7,773331.08.1999 21,33 2,825 7,84730.09.1999 23,58 2,744 7,702329.10.1999 21,69 2,961 7,822530.11.1999 23,64 2,304 8,06331.12.1999 25,08 2,329 8,016731.01.2000 25,97 2,662 8,329429.02.2000 28,09 2,761 8,388231.03.2000 24,77 2,945 8,467928.04.2000 23,89 3,141 8,945231.05.2000 28,31 4,356 8,891630.06.2000 30,57 4,476 8,595931.07.2000 26,93 3,774 8,854531.08.2000 31,72 4,782 9,087129.09.2000 29,84 5,186 9,068531.10.2000 30,76 4,49 9,27430.11.2000 31,88 6,589 9,266929.12.2000 23,87 9,775 8,803131.01.2001 26,66 5,707 8,777128.02.2001 25,57 5,236 8,906330.03.2001 24,74 5,025 9,174330.04.2001 27,89 4,695 9,103231.05.2001 29,34 3,914 9,365829.06.2001 26,08 3,096 9,324731.07.2001 24,69 3,296 9,118831.08.2001 26,41 2,38 8,828528.09.2001 23,26 2,244 8,869931.10.2001 20,37 3,291 8,885630.11.2001 19,14 2,701 8,920931.12.2001 19,9 2,57 8,963231.01.2002 19,18 2,138 9,124328.02.2002 21,33 2,357 8,878529.03.2002 25,92 3,283 8,842630.04.2002 26,47 3,795 8,413431.05.2002 24,45 3,217 7,972128.06.2002 25,58 3,245 7,497831.07.2002 25,44 2,954 7,637330.08.2002 27,47 3,296 7,538530.09.2002 28,75 4,138 7,405231.10.2002 25,72 4,156 7,434129.11.2002 25,16 4,2 7,322731.12.2002 28,66 4,789 6,93731.01.2003 31,1 5,605 6,91728.02.2003 32,79 8,101 7,160431.03.2003 27,18 5,06 7,27230.04.2003 23,68 5,385 6,999530.05.2003 26,32 6,251 6,687730.06.2003 28,33 5,411 7,203431.07.2003 28,37 4,718 7,288529.08.2003 29,49 4,731 7,508630.09.2003 27,61 4,83 7,044431.10.2003 27,7 4,893 7,10628.11.2003 28,45 4,925 6,816731.12.2003 30,17 6,189 6,6652

Source: Bloomberg.com

Appendix 7

Forecast of On-Stream Oil and Gas Fields for Hydro on NCSReserves (mill boe) Production

Field On-Stream Oil /NGL Gas Total 2003 2004E 2005E 2006E 2007E 2008E

Fram 2003 50 33 83 2 9 9 9 9 9Grane 2003 286 20 306 21 76 76 76 76 76Mikkel 2003 8 12 20 2 6 6 6 6 6Sigyn 2003 4 3 7 2 2 2 2 2 2Vale 2003 5 40 45 3 3 3 3 3 3Tune 2003 15 58 73 24 24 24 24 24 24Total 2003 368 166 534 54 120 120 120 120 120Kvitjeborn 2004 20 49 69 7 27 27 27 27Skirne and Byggve 2004 1 4 5 2 3 3 3 3Volve 2004 7 1 8 7 7 7 7 7Total 2004 28 54 82 135 37 37 37 37Kristin 2005 38 27 65 7 28 28 28Svale 2005 10 10 3 3 3 3Total 2005 48 27 75 167 31 31 31Snohvit 2006 15 89 104 9 9 9Total 2006 15 89 104 197 9 9Ormen Lange 2007 26 441 467 11 11Tyrihans 2007 39 41 80 10 10Total 2007 65 482 547 218 21Dagny 2008 1 2 3 2Skarv 2008 15 19 34 3Total 2008 16 21 37 223Sum Total 540 839 1379

Note, If production starts at the end of year, only the last quater of full production is calculatedFurther all numbers is rounded to whole numbersProduction and reserves refer to Hydro's net share: all reserves in million of barrels of oil equivalent; production in mboe/d

Source: Company date, Fact Sheet

Appendix 8

Norsk Hydro Oil and Energy 3P reservesAmounts in million boe

Exploitable Reserves still to be found NCS 8200

Proven reserves Probable 2P reserves EOR Discoveries 3P reservesNCS reserves 2263International reserves 186Proven reserves according to Sec rules (1P reserves) 2449Add Propable (2P reserves) 11322P reserves 3581EOR 430Discoveries 7383P reserves 4748

Appendix 9

Total Oil & Gas ProductionInputAverage Annual Decline 2002-06 (%)Decline Rate of Portofolio of Fields that Produced in 2002 6,60 %Decline Rate of Portofolio of Fields that Were in Decline in 2002 3,90 %Source: JP Morgan, Wood Mackenzie estimates

Our Target 2004E 2005E 2006E 2007E 2008E TotalReserve Replacement 125 % 276 286 304 306 279 1452

1999 2000 2001 2002 2003 Avereage% incresed Gas Sale 20 % 20 % 15 % 19 % 20 % 19 %

Our Target18 %

Volume1 cubic feet 0,028317 cubic meters1 cubic meter 6,2898 barrelsDays in year 365

NCS Oil and Gas Production1995 1996 1997 1998 1999 2000 2001 2002 2003 2004E 2005E 2006E 2007E 2008E

Oil production kboe/d 208,5 216,4 211 211 249,3 299,3 312,9 320,8 337,0 376,7 364,6 346,3 303,6 239,4Gas production kboe/d 37,6 50,7 54,2 56,6 67,8 81,5 93,4 110,9 133,2 157,2 185,5 218,9 258,3 304,8Gas in millions of cubic feet 211,0 284,9 304,1 317,8 380,8 457,5 524,4 622,7 748,0New projects Coming On-Stream 53,8 135,3 167,0 197,0 218,0 223,0Total kboe/d Norway (excluding new projects) 246,1 267,1 265,2 267,6 317,1 380,8 406,3 431,7 414,9 398,7 383,1 368,2 343,9 321,2Total kboe/d Norway (including new projects) 246,1 267,1 265,2 267,6 317,1 380,8 406,3 431,7 468,6 533,9 550,1 565,2 561,9 544,2Total mboe 89,8 97,5 96,8 97,7 115,8 139,0 148,3 157,6 171,0 194,9 200,8 206,3 205,1 198,6

International Oil and Gas Production1995 1996 1997 1998 1999 2000 2001 2002 2003 2004E 2005E 2006E 2007E 2008E

Oil production kboe/d 2,7 16,5 24,7 14,8 48,2 57,7 71,0 76,5 102,0 109,8 66,9Gas production kboe/d 5,3 7,0 0,0 0,0 0,0Gas in millions of cubic feet 29,8 39,4 25,9 27,9 37,2 40,1 24,4

(Total kboe/d International) 2,7 21,8 31,7 14,8 48,2 57,7 71,0 76,5 102,0 109,8 66,9Total mboe 1,0 6,0 9,0 5,4 17,6 21,1 25,9 27,9 37,2 40,1 24,4

Total Hydrocarbon Production 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004E 2005E 2006E 2007E 2008E

Effect of new convension factor 2,6Oil production kboe/d 208,5 216,4 211,0 213,7 265,8 324,0 327,7 369,0 394,7 447,7 441,1 448,3 413,4 306,4Gas production kboe/d 37,6 50,7 54,2 56,6 73,1 88,5 93,4 110,9 133,2 157,2 185,5 218,9 258,3 304,8Hydrocarbon production kboe/d 246,1 267,1 265,2 270,3 338,9 412,5 421,1 479,9 526,3 604,9 626,6 667,2 671,7 611,1Oil production mboe 76 79 77 78 97 118 120 135 145 163 161 164 151 112Gas production mboe 14 19 20 21 27 32 34 40 49 57 68 80 94 111Hydrocarbon production mboe 89,8 97,5 96,8 98,7 123,7 150,6 153,7 175,2 193,6 220,8 228,7 243,5 245,2 223,1

Total Oil & Gas Reserves

Oil reserves 615 624 598 546 837 820 825 883 852 714 581 455 344 257Gas reserves 901 898 800 770 1056 1064 1055 1170 1411 1354 1286 1206 1112 1000NCS reserves 1516 1522 1398 1316 1893 1884 1880 2053 2263 2068 1867 1661 1456 1257Oil reserves 93 92 153 156 193 172 186 160 132 95 55 30Gas reserves 38International reserves 93 92 191 156 193 172 186 160 132 95 55 30

Total reserves (No RRR) 1516 1522 1491 1408 2084 2040 2073 2225 2449 2228 1999 1756 1511 1288Total oil reserves 615 624 691 638 990 976 1018 1055 1038 875 714 550 399 287Total gas reserves 901 898 800 770 1094 1064 1055 1170 1411 1354 1286 1206 1112 1000Total reserves (With RRR) 2504 2561 2622 2684 2739

Distribution Oil 41 % 41 % 46 % 45 % 47 % 48 % 49 % 47 % 42 % 39 % 36 % 31 % 26 % 22 %Distribution Gas 59 % 59 % 54 % 55 % 53 % 52 % 51 % 53 % 58 % 61 % 64 % 69 % 74 % 78 %

Source: Company date, Fact Sheet

Appendix 10

International Oil Production ForecastInputOngoing extenssion 2007E Increse per yearKharyaga 28 5,5Days 0,365

International Oil ProductionShare Prod 2003 2004E 2005E 2006E 2007E 2008E

Country Field On-Stream %Producing in 2003Angola Girassol 2001 10 19 19 19 19 17,0Canada Terra Nova 2002 15 19 19 19 19 14,2Canada Hibernia 1997 5 11 11 11 11 8,1Russia Kharyaga 1999 40 5,5 11 16,5 22 27,5 27,5Libya Mabruk 1995 25 3 3 3 3 3 3

Not Producing in 2003Angola Dalia 2006 10 20 20 20Angola Jasmin 2003 10 4 4 4 4 0,4Angola Rosa/Lirio 2007 10 12 12Libya Murzuq 2003 8 4 4 4 4 4

Oil production kboe/d 57,5 71 76,5 102 109,8 66,9Oil production mboe 21 26 28 37 40 24

International Oil ReservesReserves 2004E 2005E 2006E 2007E 2008Emboe

OrgAngola Girassol 27 20,1 13,1 6,2Canada Terra Nova 26 19,1 12,1 5,2Canada Hibernia 15 11,0 7,0 3,0Russia Kharyaga 23 28,5 24,5 18,5 10,4 0,4Libya Mabruk 12 10,9 9,8 8,7 7,6 6,5

Angola Dalia 42 42,0 42,0 34,7 27,4 20,1Angola Jasmin 6 4,5 3,1 1,6 0,2Angola Rosa/Lirio 26 26,0 26,0 26,0 21,6 17,2Libya Murzuq 9 7,5 6,1 4,6 3,2 1,7Total international reserves 191,5 165,6 137,7 100,4 60,4 45,6


Appendix 11

Spread Sheet AssumptionsActual Actual Actual Actual Estimated Estimated Estimated Estimated Estimated

Year 2000 2001 2002 2003 2004 2005 2006 2007 2008Assumptions for Income StatementNet PP&E/Revenues 124,6 % 134,4 % 131,1 % 124,2 % 124,2 % 124,2 % 124,2 % 124,2 % 124,2 %Equity in net income of non consolidated investees/Revenues 0,1 % 0,1 % 0,3 % 0,2 % 0,2 % 0,2 % 0,2 % 0,2 % 0,2 %Interest income and other financial income/Revenues 0,0 % 0,3 % 0,2 % 0,1 % 0,1 % 0,1 % 0,1 % 0,1 % 0,1 %Other income/Revenues 0,7 % 0,3 % 0,1 % 1,4 % 0,6 % 0,6 % 0,6 % 0,6 % 0,6 %Effective tax rate (EBIT) 43,0 % 57,3 % 55,8 % 58,4 % 57,2 % 57,2 % 57,2 % 57,2 % 57,2 %Minority interest/After tax income 0,0 % 0,7 % 0,1 % 0,6 % 0,3 % 0,3 % 0,3 % 0,3 % 0,3 %

Assumptions for Exploration and ProductionSales Growth*Other operating costs/Revenues 20,7 % 25,5 % 35,2 % 27,3 % 26,3 % 26,3 % 26,3 % 26,3 % 28,3 %Depreciation, depletion and amortization/Net PPE 11,7 % 10,3 % 11,3 % 12,2 % 12,2 % 12,2 % 12,2 % 12,2 % 12,2 %Assumptions for Energy and Oil MarketingDepreciation, depletion and amortization/Net PPE 0,3 % 1,1 % 1,0 % 0,8 % 0,8 % 0,8 % 0,8 % 0,8 % 0,8 %Sales Growth NM 0,71 % 0,20 % 7,52 % 2,5 % 2,5 % 2,5 % 2,5 % 2,5 %Other operating costs/Revenues 95,8 % 93,4 % 92,3 % 93,4 % 93,4 % 93,4 % 93,4 % 93,4 % 93,4 %

Balance Sheet Assumptions:

Working Capital AssumptionsInventories/Revenues 5,5 % 4,4 % 9,7 % 6,1 % 6,1 % 6,1 % 6,1 % 6,1 % 6,1 %Accounts receivable/Revenues 8 % 7 % 14 % 10 % 9,5 % 9,5 % 9,5 % 9,5 % 9,5 %Prepaid expenses and other current assets/Revenues 2,8 % 2,7 % 7,4 % 4,5 % 3,3 % 3,3 % 3,3 % 3,3 % 3,3 %Operating cash/Revenues 6,4 % 7,6 % 3,4 % 5,3 % 5,3 % 5,3 % 5,3 % 5,3 % 5,3 %Other current liabilities/Revenues 16,6 % 16,7 % 29,7 % 19,2 % 17,5 % 17,5 % 17,5 % 17,5 % 17,5 %Net working capital/Revenues 12,2 % 11,6 % 11,0 % 11,1 % 11,5 % 11,5 % 11,5 % 11,5 % 11,5 %

Other Assets AssumptionsOther liquid assets 403 355 833 331 331 331 331 331 331Current deferred tax assets 1326 1652 1348 906 906 906 906 906 906Non-consolidated investees 1402 2095 1991 2406 2406 2406 2406 2406 2406Prepaid pension, investments and other non-current assets 1362 1654 1362 1294 1294 1294 1294 1294 1294Deferred tax assets 2560 2255 2838 2610 2610 2610 2610 2610 2610

Other Liabilities AssumptionsBank loans and other interest bearing short-term debt 4090 3806 3580 2450 2450 2450 2450 2450 2450Current portion of long term debt 994 885 959 546 594 344 256 231 231Long-Term Debt 18078 17034 15142 12570 11976 11633 11377 11146 10915Current deferred tax liabilities 116 146 128 281 281 281 281 281 281Other long term liabilities 32025 32988 34554 35628 35628 35628 35628 35628 35628

Equity AssumptionsMinority shareholders interest in consolidated subsdiaries 638 474 557 294 294 294 294 294 294Equity 23193 25210 29456 33978 39576 36579 40937 41407 37914

Other AssumptionsEliminations revenues/Revenues 46,9 % 50,0 % 41,3 % 45,6 % 45,9 % 45,9 % 45,9 % 45,9 % 45,9 %Eliminations other operating expenses/Revenues 47,0 % 50,0 % 41,3 % 45,5 % 45,9 % 45,9 % 45,9 % 45,9 % 45,9 %

* For the forecast period, is the increase/decrease estimated basedupon increase/decrease in production versus oil and gas price and USD/NOK for the Exploration and Production Segment. For the Energy and Oil Marketing we have ????

Sensitivity AnalysisOil Price 0,0US$/NOK Rate 0,0Other Operating cost 0 %WACC 0 %Beta 0,0Risk free rate 0 %Risk preimum 0 %

Appendix 12

Field & Development Costs

Production F&D cost (NOK/bl)Growth (% per annum) 35 40 45 50 55 60 65

0 % 6777 7745 8713 9681 10649 11618 125861 % 7634 8725 9815 10906 11996 13087 141782 % 8491 9704 10917 12130 13343 14556 157693 % 9348 10684 12019 13355 14690 16026 173614 % 10206 11663 13121 14579 16037 17495 189535 % 11063 12643 14223 15804 17384 18965 20545

Reserves 2003 2449Total Production 2003 193,6Remaining Years with Reserves 12,65

0 % 2449 0 0 %1 % 2473 24 13 %2 % 2498 49 25 %3 % 2522 73 38 %4 % 2547 98 51 %5 % 2571 122 63 %

Appendix 13

Norsk Hydro Oil and Energy WACCEquity 60 % BETADebt 40 % Corprate Tax Rates Italy Norway Spain

TC 0,33 0,28 0,35Marginal Corporate Tax Rate 28,0 % 1-TC 0,67 0,72 0,65

Company Eni Repsol Statoil HydroCost of Debt (kd) 4,88 % Debt to equity ratio 0,31 0,48 0,44 0,40kd(after tax) 3,51 % BetaL 0,25 0,54 0,30 0,67Q 0,36 % BetaU 0,48 0,68 0,40

Average BetaU 0,52Risk Free Rate (rf) 4,52 % Source: ReutersRisk Premium (Rm) 5,35 %BetaL 0,67

Cost of Equity (ke) 8,11 %

WACC 6,27 %

Appendix 14

Norsk Hydro Oil and Energy Net Interest Bearing DebtAmounts in NOK million

Capital Structure: Hydro Oil and EnergyYear 2000 2001 2002 2003 Average TargetEquity 23193 25210 29456 33978Minority Interest 638 474 557 294Interest bearing debt 19241 17387 16970 12047Debt + Equity 43072 43071 46983 46318

Equity 0,55 0,60 0,64 0,74 0,63 0,60Debt 0,45 0,40 0,36 0,26 0,37 0,40Debt + Equity 1,00 1,00 1,00 1,00 1,00 1,00

Net Interest Bearing Debt: Hydro Oil and EnergyYear 2000 2001 2002 2003Cash and equivalents 3518 3982 1878 3189Other liquid assets 403 355 833 331Bank loans other interest-bearing short-term debt -4090 -3806 -3580 -2450Current portion of long-term debt -994 -885 -959 -546Long-term debt -18078 -17034 -15142 -12570Net interest-bearing debt -19241 -17387 -16970 -12047

Appendix 15

Norsk Hydro ASA Balance Sheet Oil Oil Oil Oil

Amounts in NOK million share share share shareYear 2000 2001 2002 2003 2004E 2005E 2006E 2007E 2008EAssetsCash and cash equivalents 21766 27148 5965 15249Other liquid assets 2491 2421 2647 1581Accounts receivable 27555 23372 25280 27271Inventories 18738 15794 17232 17350Prepaid expenses and other current assets 9563 9482 13055 12965Current deffered tax assets 1682 2106 2218 1267Total current assets 81795 16 % 80323 15 % 66397 31 % 75683 21 %

Non-consolidated investees 7211 9687 11499 12711Property, plant and equipment, less accumulated depreciation, depletion and ammortization 95025 95277 112342 114998Prepaid pension, investments and other non-current assets 10983 11636 15081 14387Deferred tax assets 1340 999 1892 850Total non-current assets 114559 65 % 117599 65 % 140814 56 % 142946 57 %Total assets 196354 45 % 197922 45 % 207211 49 % 218629 44 %

Liabilities and equityBank loans and other interest bearing short-term debt 9088 8458 7306 5569Current portion of long term debt 2209 1966 1958 1242 1349 781 582 525 525Other current liabilities 33171 32245 38331 42890Current deferred tax liabilities 258 324 262 638Total current liabilities 44726 42993 47857 50339

Long term debt 40174 37853 30902 28568 27219 26438 25856 25331 24806Accrued pension liabilities 2735 4215 8385 9533Other long term liabilities 4686 5912 6248 8004Deferred tax liabilities 31387 31105 36809 33445Total long term liabilities 78982 79085 82344 79550

Minority shareholders interest in consolidated subsdiaries 1419 1051 1143 660Shareholders equity 71227 74793 75867 88080Total liabilities and equity 196354 197922 207211 218629

Operating current assets 79304 77902 63750 74102Operating current liabilities 33171 32245 38331 42890Net Working Capital 46133 45657 25419 31212


Appendix 16

Norsk Hydro Oil and Energy Income StatementAmounts in NOK millionYear 2000 2001 2002 2003 2004E 2005E 2006E 2007E 2008EOperating revenues 55123 52180 55845 59959 64444 61702 64768 64932 62087Deprication, depletion and amortization 8286 8020 9006 9643 10364 9923 10416 10443 9985Other operating costs 25031 24983 30892 29173 30600 29209 31814 31711 32542Operating income (EBITA) 21806 19177 15947 21143 23480 22570 22538 22778 19560EBITA magrin 39,6 % 36,8 % 28,6 % 35,3 % 36,4 % 36,6 % 34,8 % 35,1 % 31,5 %Equity in net income of non consolidated investees* 36 65 179 107 111 106 112 112 107Interest income and other financial income 144 125 47 93 89 94 94 90Other income/(loss), net 387 179 77 816 410 392 412 413 395Earnings before interest expenses and tax (EBIT) 22229 19565 16328 22113 24094 23158 23155 23397 20151EBIT margin 40,3 % 37,5 % 29,2 % 36,9 % 37,4 % 37,5 % 35,8 % 36,0 % 32,5 %Income tax expense -9550 -11202 -9114 -12911 -13771 -13236 -13234 -13372 -11517Minority interest 6 60 5 52 224 215 225 226 216Income before cumulative effect of change in accounting principle 12685 8423 7219 9254 10548 10137 10146 10251 8850Cumulative effect of change in accounting principle 98Net income 12685 8423 7219 9352 10548 10137 10146 10251 8850

Norsk Hydro Oil and Energy Balance SheetAmounts in NOK millionYear 2000 2001 2002 2003 2004E 2005E 2006E 2007E 2008EAssetsCash and cash equivalents 3518 3982 1878 3189 3428 3282 3445 3454 3303Other liquid assets 403 355 833 331 331 331 331 331 331Accounts receivable 4454 3428 7958 5704 6130 5870 6161 6177 5906Inventories 3029 2317 5425 3629 3900 3734 3920 3930 3758Prepaid expenses and other current assets 1546 1391 4110 2712 2146 2055 2157 2163 2068Current deferred tax assets 1326 # 1652 1348 # 906 # 906 906 906 906 906Total current assets 14276 13125 21552 16470 16842 16178 16920 16960 16271

0 0 0Non-consolidated investees 1402 2095 1991 2406 1294 1294 1294 1294 1294Property, plant and equipment, less accumulated depreciation, depletion and amortization 68667 70146 73223 74460 80030 76625 80432 80636 77103Prepaid pension, investments and other non-current assets 1362 1654 1362 1294 1294 1294 1294 1294 1294Deferred tax assets 2560 2255 2838 2610 2610 2610 2610 2610 2610Total non-current assets 73991 76150 79414 80770 85228 81823 85630 85834 82301Total assets 88267 89275 100966 97240 102070 98000 102550 102793 98571

Liabilities and equity 45 % 45 % 49 % 44 %

Bank loans and other interest bearing short-term debt 4090 3806 3580 2450 2450 2450 2450 2450 2450Current portion of long term debt 994 885 959 546 594 344 256 231 231Other current liabilities* 9133 8732 16589 11493 11272 10792 11328 11357 10859Current deferred tax liabilities 116 146 128 281 281 281 281 281 281Total current liabilities 14333 13569 21257 14771 14596 13867 14315 14319 13821

Long term debt 18078 17034 15142 12570 11976 11633 11377 11146 10915Other long term liabilities** 32025 32988 34554 35628 35628 35628 35628 35628 35628Total long term liabilities 50103 50022 49696 48198 47604 47261 47005 46774 46543

Minority shareholders interest in consolidated subsdiaries 638 474 557 294 294 294 294 294 294Shareholders equity**** 23193 25210 29456 33978 39576 36579 40937 41407 37914Total liabilities and equity 88267 89275 100966 97240 102070 98000 102550 102793 98571

Eliminations revenues 25871 26070 23040 27315 27537 29597 28338 29746 29821Eliminations Other operating expenses 25900 26070 23066 27290 27546 29607 28347 29755 29831Diff -29 0 -26 25 -9 -9 -9 -9 -9

* Includes Accounts payable, Income taxes payable, Payroll and value added taxes,Accrued liabilities and Other liabilities** Includes Accrued pension liabilities, Other long term liabilities and Deferred tax liabilities*** Plug

Financial statesment per segmentHydro Exploration and Production 2000 2001 2002 2003 2004E 2005E 2006E 2007E 2008EOperating revenues 35494 32426 32970 37904 41378 39430 39940 40183 36051Deprication, depletion and amortization 8046 7240 8242 9052 9729 9315 9778 9803 9373Other operating costs 7340 8276 11591 10352 10882 10370 10504 10568 10202

Hydro Energy and Oil MarketingOperating revenues 45500 45824 45915 49370 50604 51869 53166 54495 55858Deprication, depletion and amortization 240 780 764 591 635 608 638 640 612Other operating costs 43591 42777 42367 46111 47264 48445 49657 50898 52170


Appendix 17

Rating Curve Chart

Source: Nordea Markets

Rating Curve Chart

A1, 28-10-2003

SCHLUM B 5.25 03/10/08 (A1/A+)

A2, 28-10-2003

NORSK HYD 6.25 15/01/10 (A2/A)

A2, 28-10-2003

GAS NAT 6.125 10/02/10 (A2/A+)

Aa3, 28-10-2003

ENI 6.125 09/06/10 (Aa3/AA)

A2, 28-10-2003

STATOIL (EUR) 5.125 30/06/11 (A1/A)

A1, 28-10-2003

SCHLUM B 5.875 03/10/11 (A1/A+)Aa3, 28-10-2003

ENI 4.625 30/04/13 (Aa3/AA)

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Appendix 18

Norsk Hydro Exploration and ProductionAmounts in NOK millionAssumptions: 2003 2004E 2005E 2006E 2007E 2008EUS$/NOK Rate 7,07 7,09 7,13 7,17 7,20 7,23Brent crude oil price, $/bl 28,7 27,88 25,70 24,48 24,66 24,83Brent crude oil price, NOK/bl 203 198 183 176 178 180Gas price (NOK/scm) 1,03Gas price $/bl 23,16 22,30 20,56 19,58 19,73 19,86Gas price NOK/bl 164 158 147 140 142 144

Oil production mmboe 145 163 161 164 151 112Gas production mmboe 49 57 68 80 94 111Hydrocarbon production mmboe 194 221 229 244 245 223

Operating revenues 37904 41378 39430 39940 40183 36051Depreciation, depletion and amortization 9052 9729 9315 9778 9803 9373Other operating expenses 10352 10882 10370 10504 10568 10202Operating income 18500 20766 19745 19658 19812 16475

Capital expenditure 10550 10550 10550 10550 10550

Valuation of Remaining Hydrocarbon ReservesAssumptions: 2008Remaining hydrocarbon reserves 2739Oil reserves 822Gas reserves 1917Long-term brent crude oil price, $/bl 21,5Long-term brent crude oil price, NOK/bl 155,4US$/NOK Rate 7,23Long-term gas price, $/bl 17,2 0,8Long-term gas price, NOK/bl 124,4Operating cost 26Captial expenditure 30Tax 50 %

Total PV Oil PV Gas PVRevenues 366157 270169 127729 94245 238428 175924Cost 69853 51541 20953 15460 48891 36074Total 296304 218628 106776 78785 189537 139850Tax 148152 109314 53388 39392 94768 69925Capex 82180 60636 24651 18189 57519 42440Total 65972 48678 28737 21204 37249 27484

Norsk Hydro Energy and Oil Marketing2003 2004E 2005E 2006E 2007E 2008E



Appendix 19

Norsk Hydro Oil and Energy's Net Working CapitalAmounts in NOK millionYear 2000 2001 2002 2003 2004E 2005E 2006E 2007E 2008EOperating current assets 13873 12770 20719 16139 16511 15847 16589 16629 15940Operating current liabilities -9133 -8732 -16589 -11493 -11272 -10792 -10792 -11357 -10859Operating working capital 6740 6039 6132 6649 5239 5055 5797 5272 5081Net property, plant, and equipment 68667 70146 73223 74460 80030 76625 80432 80636 77103Other operating assets, net of other liabilities -30663 -31334 -33192 -34334 -34334 -34334 -34334 -34334 -34334Operating invested capital (ex goodwill) 44744 44851 46163 46775 50936 47346 51895 51574 47850Goodwill 0 0 0 0 0 0 0 0 0Operting invested capital (including goodwill) 44744 44851 46163 46775 50936 47346 51895 51574 47850Excess cash and securities 403 355 833 331 331 331 331 331 331Non-operating investments 1402 2095 1991 2406 1294 1294 1294 1294 1294Total investor funds 46549 47301 48987 49512 52560 48971 53520 53199 49474

Appendix 20

Norsk Hydro Oil and Energy DCF-ValuationAmounts in NOK millionYear 2003 2004E 2005E 2006E 2007E 2008ENet income 9352 10548 10137 10146 10251 8850Depreciaton, depletion and amortization 10364 9923 10416 10443 9985Exploration Expenses 1354 1354 1354 1354 1354Capital Expenditure 11185 11158 11188 11190 11162Change in WCR -1410 -184 742 -525 -191= Free Cash Flow 12490 10440 9985 11382 9218

Present Value 11753 9245 8321 8925 6802

WACC 1,063

Discounted free cash flow 45045Present value of remaning oil and gas reserves 48678=Operating value 93723Excess market securities 331Financial fixed assets 1294= Enterprise value 95348- 2003 net debt -12047= Equity Value 83301

Appendix 21

Hydro Exploration and ProductionAmounts in NOK millionAssumptions: 2003 2004E 2005E 2006E 2007E 2008EUS$/NOK Rate 7,07 7,00 7,00 7,00 7,00 7,00Brent crude oil price, $/bl 28,7 31,81 32,18 32,62 33,04 33,44Brent crude oil price, NOK/bl 203 223 225 228 231 234Gas price (NOK/scm) 1,03Gas price $/bl 23,16 25,45 25,74 26,10 26,43 26,75Gas price NOK/bl 164 178 180 183 185 187






Hydro Energy and Oil Marketing2003 2004E 2005E 2006E 2007E 2008E



Appendix 22

Hydro Exploration and ProductionAmounts in NOK millionAssumptions: 2003 2004E 2005E 2006E 2007E 2008EUS$/NOK Rate 7,07 7,50 7,50 7,50 7,50 7,50Brent crude oil price, $/bl 28,7 17,87 17,99 17,99 17,99 17,99Brent crude oil price, NOK/bl 203 134 135 135 135 135Gas price (NOK/scm) 1,03Gas price $/bl 23,16 14,30 14,39 14,39 14,39 14,39Gas price NOK/bl 164 107 108 108 108 108






Hydro Energy and Oil Marketing2003 2004E 2005E 2006E 2007E 2008E



Appendix 23

Norsk Hydro Oil and Energy DCF-Valuation (Best Case)Amounts in NOK millionYear 2003 2004E 2005E 2006E 2007E 2008ENet income 9352 11879 12585 13392 13598 11771Depreciaton, depletion and amortization 11206 10991 11859 11736 11153Exploration Expenses 1354 1354 1354 1354 1354Capital Expenditure 10937 10924 10977 10969 10934Change in WCR -1058 -90 1307 -996 -243= Free Cash Flow 14560 14096 14320 16713 13588

Present Value 13701 12482 11933 13105 10026

WACC 1,063


Appendix 24

Norsk Hydro Oil and Energy DCF-Valuation (Worst Case)Amounts in NOK millionYear 2003 2004E 2005E 2006E 2007E 2008ENet income 9352 7158 7115 7675 7591 6470Depreciaton, depletion and amortization 8222 9235 9247 9428 9011Exploration Expenses 1354 1354 1354 1354 1354Capital Expenditure 10250 10250 10250 10250 10250Change in WCR -2306 424 17 64 -175= Free Cash Flow 8789 7031 8008 8059 6759

Present Value 8271 6226 6673 6319 4987

WACC 1,063


Appendix 25

Multiple Valuation Norsk Hydro Oil and EnergyAmounts in NOK million

EV/EBITDA Valuation

Multiple 3,4EBITDA 31826=Operating value 108208Excess market securities 331Financial fixed assets 1294= Enterprise value 109833- 2003 net debt -12047= Equity Value 97786

EV/DACF Valuation

Multiple 5,4DACF 18995=Operating value 103206Excess market securities 331Financial fixed assets 1294= Enterprise value 104831- 2003 net debt -12047= Equity Value 92784

Company Norsk Hydro Repsol-YPF Statoil ENI Total Chevron/Texaco RD/Shell BP ExxonMobilOil & Gas Reserves 2249 5433 4264 7282 11404 11890 14350 18338 219842004E EV/DACF 4,5 5,7 5,1 5,5 6,6 8,4 8,4 8,8 10,6

Source: Company data, Deutche Bank, DNB Markets

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valuation of norsk hydro oil & energy - au...

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