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HYDRO: FROM UTSIRA TO FUTURE ENERGY SOLUTIONS Jordan Mitchell prepared this case under the supervision of Professor Robert Klassen solely to provide material for class discussion. The authors do not intend to illustrate either effective or ineffective handling of a managerial situation. The authors may have disguised certain names and other identifying information to protect confidentiality. Ivey Management Services prohibits any form of reproduction, storage or transmittal without its written permission. Reproduction of this material is not covered under authorization by any reproduction rights organization. To order copies or request permission to reproduce materials, contact Ivey Publishing, Ivey Management Services, c/o Richard Ivey School of Business, The University of Western Ontario, London, Ontario, Canada, N6A 3K7; phone (519) 661-3208; fax (519) 661-3882; e-mail cases@ivey.uwo.ca. Copyright © 2006, Ivey Management Services Version: (B) 2009-09-21 Two-meter waves crashed against the hull of a small ferry headed from the remote island of Utsira to the port town of Haugesund on Norway’s mainland. Aboard were Elisabet Fjermestad Hagen, director of Hydrogen Projects, and Torgeir Nakken, head of research and development (R&D) for Hydrogen Projects, both employed by the diversified energy and aluminum giant, Hydro. The two had just spent a day on the island of Utsira visiting the site that many had called the world’s first hydrogen economy. The planning phases had started in 2002, and since being fully operational in July 2004, the project had focused on providing renewable power for 10 per cent of Utsira’s inhabitants. Established as a research and development project with no expectation for profit, the project used a combination of wind power and hydrogen to generate on-site electricity for the island. In the summer of 2005, a number of lessons had been garnered from the experiment. While the project would likely run until 2007. Fjermestad Hagen and Nakken wondered what the next step would be and whether an economically viable business case could be made to commercialize the concept. Working with others in Hydro’s New Energy division, the two managers identified two potential markets for an Utsira-like application. The first was developing similar solutions for other remote or island communities. Although more than 1,000 remote communities existed in the European Union (EU) alone, the opportunity was potentially much greater on a global basis, since one-quarter of the world’s population lived without electricity. The second was offering a solution to utility providers for the load balancing of electricity grids. Electricity could potentially be stored as hydrogen for later use. As the boat was pulling up to Norway’s mainland, Fjermestad Hagen and Nakken considered plans to make Hydro’s energy solution attractive from technological, ecological and financial perspectives. HYDRO IN BRIEF Based in Norway with operations in 40 countries, 37,000 employees, €19 billion in revenues and €4 billion in operating income, Hydro was listed as one of the pre-eminent energy Fortune 500 companies. Established in 1905, the same year that Norway became an independent nation, the company began its

Page 2 9B06M044 operations as Norsk Hydro with a hydroelectric power generation site and a production facility for agricultural fertilizers. The company came under German ownership in 1929 and endured bombings and sabotage during the Second World War, before being handed back to Norwegian authorities. The year 1963 marked three important developments for Norsk Hydro: the beginning of aluminum production, the conversion of ammonia production from electrochemical to petrochemical processes and participation in an offshore oil exploration project, the first for a Norwegian company. By the late 1960s, the company had been transformed after the discovery of oil on the Norwegian continental shelf. Norsk Hydro began operating its first oil field in 1988 and expanded its oil and gas business through participation in multi-company exploration projects and acquisitions. In its aluminum operation, Norsk Hydro bought ÅSV, the Norwegian state-run aluminum company, and VAW, a major German aluminum supplier. These acquisitions helped Norsk Hydro to double the production of oil, gas and aluminum in less than six years. In 2004, the company divested itself of its 100-year-old fertilizer business and changed its name to become known simply as Hydro. In 2005, Hydro had two major divisions: Aluminum with 32,500 employees, representing 52 per cent of revenues and six per cent of operating profits; and Oil & Energy with 4,500 people, which accounted for the remaining revenue and the bulk of the operating profits. The relationship between the two divisions was described by Bård Hammervold, head of Marketing & Infochannels in Oil & Energy: “A simple explanation is that aluminum production needs a lot of energy, and oil and gas provides that energy.” The company’s annual report summarized the company’s overall strategic direction:

We aim to further develop the main business areas of energy and aluminum globally based on the company’s financial and management capacity. The main challenges for the core activities in the future are to increase oil and gas reserves and to improve profitability in the aluminum business.

Exhibit 1 shows Hydro’s key figures and Exhibit 2 shows the company’s organizational structure. ALUMINUM With direct investments in 28 countries, Hydro was the world’s third largest integrated aluminum supplier. In 2004, Hydro produced 1.7 million tonnes of primary metal and sold 3.4 million tonnes.1 Because Hydro sold more aluminum than it produced, the firm was an active purchaser of raw aluminum in the world markets. Hydro had increased its self-sufficiency in production when it moved from producing 25 per cent of primary metal in 1998 to 45 per cent in 2004. The company’s primary markets for aluminum were the automotive, packaging, construction and printing industries. Hydro was reorganizing to improve efficiencies and increase operating income; as a result, the division had grown by 15 per cent with adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) climbing by 33 per cent in 2004. 1 The world’s top two producers were Alcoa and Alcan, at 7.4 million tonnes per year and 5.8 million tonnes per year, respectively. (Alcoa Annual Report, www.alcoa.com, December 31, 2004, pp. 66 and 2. Alcan Facts 2005, www.alcan.com, accessed October 5, 2005, pp. 5 and 11.)

Page 3 9B06M044 OIL & ENERGY Hydro was the second largest oil and gas operator on the Norwegian continental shelf behind Norway’s government-run Statoil and the third largest oil and gas offshore operator in the world behind Shell and Exxon. Hydro’s primary oil and gas operations were in Norway with additional oil and gas production facilities in Angola, Canada, Russia and Libya. The company was currently undergoing exploration activities in the Gulf of Mexico, Iran and Denmark. As of 2005, Hydro operated 14 oil and gas installations, with total production being about 570,000 barrels per day. Exhibit 3 reports key financial and operating figures for this division. Hydro was in the process of developing its largest project to date — Ormen Lange off Norway’s west coast — along with partners Petoro, Statoil, Dong, ExxonMobil, Conoco and Shell. Hydro owned 20 per cent of the project, and Shell was to take over as the operator of the field once it was operational. The project included an offshore gas development site, an onshore plant and the ability to export gas and condensates to the United Kingdom in a multi-stream singular pipeline. This undertaking was unique, as it was the first gas field to be at such an extreme depth (1,100 meters below sea level). When completed in 2007, Norway would be the second largest gas exporter, ahead of Canada and behind Russia. The Oil & Energy division comprised four areas: Exploration, Projects, Operations and Markets. Exploration was responsible for identifying and finding potential oil and natural gas reserves and testing the viability of proceeding with a development project. The Projects team physically built the capabilities to extract the oil, natural gas or other condensates. Operations was responsible for all production and ensured that the given fossil fuel was delivered to either a refinery or distributor. Oil and gas fields were typically operated under license by Hydro since many development projects were funded in coordination with other oil and gas companies. Hydro had previously owned an oil refinery, but had sold the business in 2001 in an effort to streamline operations. Markets, the fourth division of Oil & Energy, was made up of four subdivisions: Oil and Gas Market Trading, Oil and Gas Products, Power Production and New Energy. Power Production was responsible for the operation of Hydro’s 19 hydroelectric power plants in Norway, which had the capacity to produce 10 per cent of the country’s combined total power generation. Normal annual production was nine million megawatt hours (MWh), which was sufficient to supply electricity to approximately 450,000 homes.2 Since Hydro consumed more electricity than it produced, the Power Production division was also responsible for purchasing electricity through long-term contracts and financial derivative instruments, such as futures and options. Depending on the demand and supply of electricity produced through its hydroelectric plants, Hydro also sold electricity to the grid. The European Union (EU) promoted the use of renewable energy through the use of green certificates under a directive to increase renewable energy to represent 12 per cent of total energy consumption by 2010.3 Under a compulsory green certificate power market, renewable energy producers were awarded green certificates, and purchasers (electric utilities or electricity wholesalers) were required to buy a certain number of green certificates per year. Sweden and Norway were planning a joint renewable energy certificates market to be operational as of January 2007.

2 Hydro website, www.hydro.com, accessed October 2, 2005. 3 Hydro Annual Report, December 31, 2004, p. 41.

Page 4 9B06M044 HYDRO’S NEW ENERGY DIVISION Hydro’s New Energy subdivision comprised wind power, hydrogen, research and development, and a ventures fund for renewable energy projects. The New Energy division was treated by Hydro as an area for future investment. The division employed about 30 people. Senior management articulated how this division fit into the rest of the business portfolio:

Our passion to develop new forms of energy has a long history. The company was founded on the basis of renewable hydroelectric power. We were among the first to invest in exploration of oil and gas in the North Sea. New energy as an obvious part of our energy portfolio is a natural continuation of this 100-year-old tradition . . . . [New energy] projects show the breadth of Hydro’s involvement in new forms of energy, which runs in parallel to the core activities of Oil & Energy, namely to supply the market with oil, gas and hydroelectric power. We are convinced that new forms of energy will find their way into the energy chain. For us it is important to be involved early, to build expertise and establish a position in the emerging new markets.

Wind Power Beginning in 2001, Hydro had inaugurated its first wind project, the Arctic Wind Park located in Northern Norway at Havøygavlen. The project had 16 wind turbines with production capacity of 40 megawatts (MW), allowing it to provide power to 5,000 to 6,000 homes.4 Hydro was in the process of establishing 10 other wind parks in the country ranging from 15 to 330 turbines with production capacity of 50 to 1,000 MW. The average installed cost of a wind turbine was €1 million per MW. In June 2005, Hydro had signed an agreement to purchase a 50 per cent stake in Scira, a U.K.-based power group that had the rights to build a 315 MW offshore wind farm near Norfolk, England. Hydrogen Hydro had produced hydrogen for use in ammonia production for more than 75 years. Ammonia was, in turn, used in the production of fertilizers. In addition, since 1927, Hydro had produced water electrolysis equipment to separate water into hydrogen and oxygen (see Exhibit 4 for a brief summary of the characteristics of hydrogen and its generation and use). In the early 1990s, the company had created a separate legal entity for the sale of electrolysis equipment: Norsk Hydro Electrolysers A/S. This company was 100 per cent owned by Hydro and reported to Hydro’s hydrogen unit. Norsk Hydro Electrolysers A/S had installed more than 300 electrolyser units for use within Hydro and another 200 around the world with external organizations. Depending on the size and capacity to produce hydrogen, electrolysers ranged from a capital cost of €5,000 to €10,000 per kW. The company’s hydrogen division had participated as a partner in several hydrogen demonstration projects around the world. In 1999, Hydro invested €163,000 in a non-profit organization called the Icelandic New Energy Company. This investment was combined with funds from local Icelandic companies, institutions and global firms, such as Shell and DaimlerChrysler, to support three projects aimed at converting Iceland into a hydrogen economy by 2050. Besides investing in the project, Hydro Electrolysers installed an electrolyser unit at the world’s first commercial hydrogen refuelling station to convert water into usable 4 Hydro website, www.hydro.com, accessed October 2, 2005.

Page 5 9B06M044 hydrogen to power city buses. In addition to the Icelandic project, Hydro had also delivered a refuelling station in Hamburg as part of the pan-European CUTE initiative5 and was the owner and operator of an electrolyser in the Clean Energy Partnership (CEP) Berlin project. Research and Development Working under Hydro’s New Energy division, research and development covered all forms of energy, including improvements to oil and gas processing, the removal of carbon dioxide from fossil fuels and investigation of future energy options, including wind power and hydrogen. Hydro was also involved in a number of research initiatives with other companies and the European Union. One example was Hydro’s role in forming HyNet along with Shell Hydrogen and BP. The aim of HyNet was to establish a European hydrogen network from European industry and research institutes funded by the European Commission, thereby providing a single voice to the European Commission on hydrogen in society. Hydro Ventures In March 2001, Hydro set up a venture fund of €45 million in order to invest in new technologies related to Hydro’s Oil & Energy activities. Hydro Ventures invested in for-profit companies and focused on five main areas: renewable energy companies in wind, wave, solar, bio or tidal power; distributed power, power quality and energy storage; carbon-efficient technologies; enabling technologies; and upstream oil and gas companies, such as drilling and sub-sea solutions. As of 2005, Hydro Ventures had invested in four companies and three energy funds. Direct investments included a water treatment company, an electric energy company, both based in Norway, a wave power company in Scotland, and a market intelligence company operating in the United States and Israel. Exhibit 5 shows more details about the investments. THE UTSIRA PROJECT Led by the Hydrogen group within the New Energy division, the Utsira demonstration project combined wind and hydrogen power to demonstrate the delivery of autonomous renewable power. Located off the southwest coast of Norway (see Exhibit 6), Utsira was an island with 240 inhabitants and 100 homes. The idea to combine wind and hydrogen power in a self-sufficient site had been talked about within Hydro’s offices since the late 1990s. However, it was not until Christopher Kloed, then head of Hydro Electrolysers, accidentally met up with the island’s chief councillor, Robin Kirkhus, that the project moved forward. In the chance encounter, Kirkhus explained Utsira’s vision to utilize green technology ranging from biodynamic foodstuffs and ecological farming to solar power and windmills. Kloed mentioned the possibility of a hydrogen energy system, which was welcomed by Kirkhus. Utsira was chosen as the demonstration site due to several factors. One of the most important was the island’s windy conditions — it was estimated by Hydro engineers that over the past 10 years, the maximum period of time without wind had been two consecutive days. The choice of Ustira was also supported by the following: the electricity load of Utsira households were representative of other European homes; the island was not too remote from the mainland; a backup system was in place; and the island’s inhabitants were supportive of the demonstration project. Exhibit 7 presents representative data for wind speed and electrical energy demand by customers.

5 CUTE stands for Clean Urban Transport for Europe, a European Union public-private project that involved demonstration projects for city buses to run with hydrogen fuel cells.

Page 6 9B06M044 Hydro executives viewed the project as a research and development initiative with no objective to make money. The project purpose was documented internally as: “to demonstrate how renewable energy can provide safe and efficient energy supply to remote areas.” The project goal was to install a full-scale demonstration and testing of a wind-hydrogen energy system. The idea was that the wind turbine would generate electricity for two purposes: to power 10 homes, or 10 per cent of the island. The peak power demand was expected to be about 50 to 60 kW, with annual energy consumption of about 20,000 kWh per home.6 When there was excess wind, the turbines would power the electrolysis unit, which would break down water into its basic elements: hydrogen and oxygen. The hydrogen would then be stored and be fed into a hydrogen fuel cell or a hydrogen internal combustion engine to generate electricity when the wind slowed or stopped blowing. Functionality of the System A schematic of the system is shown in Exhibit 6. Originally planned with one 600 kW wind turbine, the Utsira development team decided after six months to install two turbines. The second turbine was not part of the stand-alone system but rather produced “green power” for export to Norway’s mainland. The motion of air caused the turbine to turn, creating electric energy, which was then passed through electric cables to the power grid. During periods of low demand, excess electricity generated by the turbine was automatically channelled through an inverter to the electrolyser. Simultaneously, water was piped in at 175 pounds per square inch (psi) of pressure from the island’s water reservoir and purified before being fed into the electrolyser. The electrolyser created hydrogen and oxygen. The hydrogen was pressurized in gas form to 2,900 psi and stored in a large tank (2,400 cubic meters); the tank had been designed to provide two full days of continuous power for the 10 households. When the wind turbines could not generate sufficient electricity to meet demand, the control system automatically switched on both the hydrogen fuel cell and the internal combustion engine to take over as the energy provider. The wind and hydrogen systems could deliver power simultaneously. Before being transferred to the power grid, the electricity needed to be transformed from 400 to 220 Volts AC to make it usable by Utsira’s households.7 Finally, the flywheel, battery and permanent magnet synchronous motor (PMSM) were back-up systems needed to balance and stabilize the grid. Project Milestones and Choosing the Components In April 2003, Hydro approved the project with a total budget of €5 million (see Exhibit 8). The Utsira development team of 10 people then worked to secure the main supplier contracts. Hydro forged agreements with Norwegian government agencies: Enova and NRF,8 organizations to facilitate energy developments, and the SFT,9 the pollution authority. Choosing other partners to supply the project required detailed consideration. Fjermestad Hagen explained:

6 Two facts need to be emphasized. Power, or the rate at which energy is consumed, is expressed in kilowatts (kW). Energy, or the total amount used, is expressed in kilowatt hours (kWh). Thus power can be thought of as “how many light bulbs are lit?” and energy as “how long are those bulbs lit?” A typical home requires five to six kW of peak power, and consumes about 20,000 kWh of energy annually. 7 The European standard for electricity is 220 V rather than 110 V, as in North America. 8 NRF stands for Norsk renholdsverks-forening, which translates as Norwegian Association of Solid Waste Management. 9 SFT stands for Statens forureiningstilsyn, which translates as Norwegian Pollution Control Authority.

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The converted internal combustion engine was not part of the original plan. We couldn’t get a 50 kW fuel cell at a sensible price, so we purchased the engine plus a small fuel cell. Regarding the fuel cell, we faced an interesting dilemma when we were looking for suppliers, as we needed them to consider how the component could be integrated into the system. The question came up internally — should we look for a separate company that can do the integration? Or should we try and push manufacturers of components such as fuel cell suppliers to do more integration?

Hydro eventually settled on a German company, Enercon, to supply the two wind turbines, the flywheel, the battery and the PMSM. The Danish company IRD was selected to supply the 10 kW fuel cell, and the Belgian company Continental was chosen for the 55 kW rebuilt internal combustion engine that used hydrogen fuel. Other parts of the system, such as the compressor, hydrogen storage tanks, piping and electrical cables, were either purchased from local suppliers or developed in-house. Finally, Hydro Electrolysers supplied the electrolyser unit. In June 2003, construction on the site began, and by autumn the windmills had been set up. During the first few months of 2004, the team built the hydrogen plant, and in July 2004, the project was completed with the installation of the fuel cell and hydrogen-powered internal combustion engine. Given the research focus of the project, a great deal of time was dedicated to developing the system’s components and their interconnectivity as the project progressed. In the words of Nakken, the project was not a “plug and play” or turnkey solution. System in Operation After the first full year of operations in 2005, the team had encountered several operational challenges and had made several conclusions on the system’s overall functionality. Nakken summarized the three major priorities of the project:

The first priority for the system was making all of the installed components work in the system. Then, the second priority was testing the system. The third priority is looking at the commercialization and marketing, which means considering any of the early markets where we could apply this technology.

In the time span of one year, the system had been given a reliability rate of 80 to 90 per cent, after taking into account the availability of the stand-alone system over a 30-day period. In case of failures, the homes were immediately connected back to the ordinary grid. Aside from the initial set-up period, the system was fully automatic. Hydro had assigned one person to check on the system once a week. In addition, the site was being controlled and monitored by Hydro’s mainland research and development center in Porsgrunn/Rjukan. Making the fuel cell work as part of the larger system required that the team adapt the control and regulating systems to allow for automatic switching between the wind turbine, fuel cell and internal combustion engine. The team also needed to ensure that there was sufficient communication between all of the components for operations, such as increasing the pressure of hydrogen gas from the electrolyser to the storage tanks. Other parts, such as the inverter and transformer, required constant monitoring to ensure that electricity was being generated and transferred efficiently.

Page 8 9B06M044 As anticipated, during periods when the energy generated by the wind turbine exceeded demand, often during early morning hours, hydrogen was produced and stored (see Exhibit 9a). In contrast, when this situation reversed and demand exceeded energy generated from wind power, hydrogen was consumed (see Exhibit 9b). However, the efficiency of the fuel cell and internal combustion engine was less than expected: overall, approximately 70 to 80 per cent of the energy was lost when converting wind-generated electricity to hydrogen and then back again to electricity. As a result, the 2,400-cubic-meter hydrogen storage tank could provide only 2.9 megawatt hours (MWh) of stored energy, much less than its theoretical capacity of 7.2 MWh. Nakken talked about the performance of the fuel cell:

The fuel cell stack works fine in isolation; however, within the overall system it has not worked well. This is largely because Utsira is a very small grid, with few households (low load) served by a relatively large wind turbine. This, especially in periods with high winds can create power fluctuations in the grid. At least in the start of the project this was inevitable. Another key problem has been converting the electricity without losing energy. The whole system has not been tested over a long period of time. In future solutions, we see the fuel cell becoming more important.

From the beginning, the team planned the system to be functional in a harsh climate. Nakken explained the climatic setting:

Even though this is an onshore project, we are dealing with more offshore-like conditions. There’s a lot of salt in the air and the temperature is between 0 and 10 degrees Celsius all year around. Also, there are tremendous waves. This means you have certain weather windows. This all needs to be considered when designing the system since you have a lot of long lead times in ordering the parts. For instance, we built a quay at Utsira to move in all of the parts such as the wind turbines. We couldn’t use the ferry system and the roads on the island would not allow us to move the parts. All of the islanders said, “Don’t build a quay there.” And, as usual, they were right. We built it and then after a major storm, all the rocks caved in and ruined the quay.

Despite these growing pains, the Utsira project generated critical acclaim — in December 2004, the project won the prestigious Platts Global Energy Award. It also attracted significant international press with some sources citing the project as the “world’s first hydrogen economy.” POTENTIAL COMMERCIALIZATION OF THE TECHNOLOGY Fjermestad Hagen and Nakken saw two potential early markets for a similar concept to Utsira: remote communities and grid power balancing. Remote Communities Remote communities could be considered to be islands or any areas that were not connected to a central electricity grid service. Within the European Union, there were thousands of populated islands relying on diesel generators for their main energy source. An estimated 300,000 households within Europe had no access to any electricity grid.10 When asked how big the worldwide market for remote communities was, 10 “Market Potential Analysis for Introduction of Hydrogen Energy Technology in Stand-Alone Power Systems; Market Potential Report,” H-SAPS Altener Programme, 2004, p. 8, www.hsaps.ife.no, accessed September 2006.

Page 9 9B06M044 Fjermestad Hagen responded: “Consider that there are 1.6 billion people — that’s 25 per cent of the world’s population, living without any electricity.” A journalist from Britain’s Guardian newspaper touched on the same opportunity in an article in 2004:

The World Bank’s drive to promote fossil fuel-generated power for 1.6 billion people lacking electricity will drive developing countries deeper into debt, a report by a development think tank claims today. Fossil fuels, such as oil, gas and coal, will never provide enough power for developing nations because of the cost of connecting remote communities to a national grid, whereas renewable forms of electricity generation could provide a cheaper solution, the New Economics Foundation says. Rural communities in poorer countries, particularly in Africa, are often many miles from any kind of power grid. On current trends, in 2030 there will be more people relying on wood and dung for cooking and heating than there are now, according to the International Energy Agency. But with small-scale hydro-electric schemes, wind and solar power, developing world villages could become self-sufficient in power.11

“Off-grid” communities typically relied on diesel generators or liquid pressurized gas, and energy needs were increasing by one per cent each year. Remote communities that belonged to a country geographically separated (e.g. Portugal and the Azores) were usually subsidized so that consumers would not pay more in the remote area. Exhibit 10 shows data for selected EU island communities. The costs for delivering a solution to an island community had not been fully determined. Because the system was powered by wind, operating costs were made up solely of a water supply for the electrolyser and minimal labor to perform checks and maintenance. Nakken talked about the total costs of the system:

In Utsira, the cost is far higher than current diesel and gas oil solutions — but it is solely an R&D project. We feel that if we were to install this, we would be able to get the cost to €1.05 per kWh. Within five to ten years, we feel that it could get down to €0.35 per kWh.

Fjermestad Hagen added:

With diesel generators you would have 80 per cent of the cost being operational and 20 per cent being the fixed costs. With something like the wind turbine and the electrolyser, this ratio is reversed. When islands look at the payback period, it’s long. But, we say look at it as a 10-year fixed loan.

Assuming a usable life of approximately seven years, industry sources estimated the comparable capital cost of the two systems: diesel system at €300 per kW versus wind/hydrogen system at €20,000 per kW. Operational costs (excluding fuel) were estimated based on capital costs: 2.5 per cent annually for the diesel system and 1.5 per cent annually for the wind/hydrogen system. Fuel costs for the diesel system ranged between €0.15 kWh and €0.50kWh, depending on the remoteness of the community (recall that 1 kW of installed power translates into about 3,500 kWh of energy annually). In contrast, the wind/hydrogen system had no fuel costs. Moreover, if a renewable energy system were used, the island would also be able to claim green certificate credits, which it could sell for about €0.015 per kWh per year. In initial talks with representatives from island communities, Hydro executives formed criteria for what they would look for in an ideal customer. Fjermestad Hagen commented:

11 Paul Brown, “World Bank Rebuked for Fossil Fuel Strategy,” The Guardian, June 21, 2004, p. 13.

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There are three main conditions we look for: the community is currently dependent on oil imports; they are environmentally focused; and, they have purchasing power. We need to make sure that they can pay for this since we’re not willing to do another demonstration project. As far as the site conditions, with our design, we would be able to substitute wind power with wave or solar power.

When asked why an island would want to move to a system with a substantially higher capital cost in the short term, Fjermestad Hagen rationalized:

On some islands, wind power can already compete when you take into account the transport of gas oil and diesel. In an area like the Azores, they can’t always gain access for the refueling either. It’s important to look at the economics of diesel generators and also ask in areas like the Greek Islands or in Portugal whether all the inhabitants have the same power needs. Many of these communities rely on tourism and want to promote clean air. In tourist spots, you have golf. Golf needs lawns. Lawns require water. The water needs to be desalinated. You can’t do that with diesel because it would cause too much carbon dioxide emissions. Plus, a lot of places want to have a greener image, and often times they can seek funding for the project from the EU or from their national governments.

Grid Power Balancing for Transmission System Operators The electricity transmission system for moving electricity from power generation to consumers was often referred to as a grid. Transmission system operators (TSOs) were constantly looking for new technologies to provide greater stability to the electricity grid, particularly those with a high reliance on wind power. There were a number of different strategies to improve stability. In the event of rare, very large power surges, circuit breakers were used to take the generation facility offline to protect equipment. Less dramatic but more frequent smaller fluctuations potentially caused “brown-outs” or consumer equipment malfunction. Unfortunately, according to experts, these smaller fluctuations tended to increase as the proportion of wind and other renewable energy supplied to the grid expanded. Moreover, on a timescale of hours to days, fluctuations in wind required additional flexibility.12 Out of a total of 36 major grid operators in the EU, approximately five relied heavily on wind power. On the demand side, consumers could be encouraged to smooth their demand patterns, or otherwise adapt to less stable supply. On the supply side, technological solutions to smooth smaller fluctuations were also possible, including flexible generation such as hydroelectric power, and storage options such as batteries and electrolysers. The power supplied by such a typical storage system could be upwards of 1 MW, with stored energy capacity of up to 10 hours or more (i.e. 10 MWh). Overall, because such a system would charge and discharge repeatedly, it might supply 2,500 MWh annually of electricity to the grid. Fjermestad Hagen stated:

These last two options are effectively converting electricity into something that can be stored. Electricity itself cannot be stored. The old saying goes, “you use it, or lose it!”

However, storage options came at a price. Fjermestad Hagen and Nakken believed that a hydrogen-electrolyzer system offered a better alternative than batteries. During periods of excess electricity supply,

12 European Wind Energy Association, “Large Scale Integration of Wind Energy in the European Power Supply: Analysis, Issues and Recommendations,” December 2005, www.ewa.org, accessed September 25, 2006.

Page 11 9B06M044 the electrolyzer would consume electricity to produce and store hydrogen. In contrast, during periods of supply shortages, the stored hydrogen could be fed into a fuel cell to generate electricity (which also yielded green certificates). Moreover, unlike batteries, the incremental cost of increasing energy storage capacity also was quite small. And excess hydrogen could be sold to customers on the open market for upwards of €0.10 per cubic meter. It was estimated that the system would be able to generate approximately 0.2 cubic meters of hydrogen per kWh of energy. Estimates suggested that if new-technology, high-capacity sodium-sulfur (NaS) batteries were used, capital costs would range from €800 to €1,000 per kW (i.e. power), depending on the type of battery employed with a five to 10 year usable life. In addition, capital costs had a variable component based on the maximum amount (i.e. capacity) of stored energy, with capital costs increasing at about €45 per kWh. Annual operating costs were expected to be about €0.35 per kWh.13 A comparably sized hydrogen-electrolyzer system was expected to cost €12,000 per kW (€4,000 for the fuel cell, €6,000 for the electrolyzer and €2,000 for the piping and control system). However, the additional capital cost for stored energy was only about half that of batteries, roughly €20-25 per kWh.14 Annual operating and maintenance costs also were much less, estimated to be only €0.03 per kWh per year. Finally, adding to its appeal, the capital cost of the fuel cell was estimated to fall between 10 and 25 per cent annually for the next 10 years.15

PLANNING THE NEXT STEPS The central question was how to move forward — being a team of two with access to experts from across the company, Fjermestad Hagen and Nakken needed to develop a solid business plan for the next steps. Fjermestad Hagen remarked:

One of the big problems we’re having right now is to keep the interest of those we speak with. We don’t have anything ready yet to install. We do not want to do another demonstration project on an island. That’s clear. We’d be willing to do a demonstration project with an electric utility, but we would want them to pay for the costs — that means we would earn nothing in the way of profits, but they would cover all the costs.

As of the summer of 2005, Nakken and Fjermestad Hagen had given more than 10 presentations to research institutes, electricity providers and island communities around the world. They had also been contacted by a number of interested parties, including a wind farm operator in Scotland, a mining community in Australia, an energy institute in Turkey and energy providers in Greece, the Azores and Chile. Fjermestad Hagen talked about the feedback to date:

Many don’t accept that it’s not ready right now. A lot of them want the solution right away. We have looked at 10 projects and maybe out of those we have identified three to four partners that are sensible. Both types of projects — remote communities and grid power balancing — are nearly commercial. There isn’t anyone that’s currently offering a solution like ours.

13 A. Nourai, “Comparison of the Costs of Energy Storage Technologies,” American Electric Power, 2004, www.electricitystorage.org/pubs/2004/EPRI-DOE%20Storage%20Costs-ESA.pdf, accessed October 1, 2007; P. Davidson, “New Battery Packs Powerful Punch,” USA Today, July 5, 2007, p. B3. 14 D. Aklil, et al., “Characterisation of a Fuel Cell Based Uninterrruptible Power Supply,” SiGEN Ltd., URN No. 04/1399, 2004, p. 28, www.berr.gov.uk/files/file15208.pdf, accessed October 1, 2007. 15 “Pan European Chemicals,” HSBC Analyst Report, April 3, 2003, p. 36.

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Exhibit 1

HYDRO’S KEY FIGURES (€ 000,000s)

Notes: NOK = Norwegian Kroner: NOK1.00 = €0.12 RoaCE: Return on average capital employed PJ: petajoule F/X Rates: Foreign exchange rates Source: Hydro Annual Report 2004, www.hydro.com, accessed December 31, 2004.

Financial Results 2004 2003 2002 F/X Rates 0.12397 0.12397 0.12397

Operating revenues 19,268 16,582 16,624 Operating income 3,948 2,681 2,190 Income from continuing operations before cumulative effect of change in accounting principle 1,423 1,038 880 Net income 1,557 1,360 1,087

Financial dataInvestments 2,413 2,196 5,475 Adjusted net interest bearing debt/equity 0.11 0.38 0.60 Cash flow from operations 3,437 2,823 2,365

Rate of returnRoaCE 13.0 8.4 7.2 RoaCE - normalized 7.9 6.2 6.6

NOK per shareEarnings from continuing operations 5.59 4.03 3.41 Earnings per share 6.12 5.14 4.21 Dividends 2.48 1.36 1.30 Share price, Oslo, 31 December 59.13 44.87 33.94

Operational Results - Society, People and EnvironmentSocietyTotal current tax 2,993 1,799 1,620 Salaries 1,717 1,683 1,650

People*Number of employees (average over the year) 36,938 44,602 42,615 Sick leave (per cent) 3.1 3 2.6Total recordable injuries (per million hours worked) 5.6 7 10.3*Inclusive Agri (Yara)

EnvironmentTotal energy consumption (PJ) 181.4 165.9 182Greenhouse gas emissions (million tonnes CO2e) 8.84 8.16 9.17

Page 13 9B06M044

Exhibit 2

HYDRO’S ORGANIZATIONAL STRUCTURE

Source: Company files.

Hydro President and CEO

Eivind Reiten

Finance Executive Vice

President John O. Ottestad

Aluminum Executive Vice

President Jon-Harald Nilsen

Oil & Energy Executive Vice

President Tore Torvund

Leadership & Culture Executive Vice

President Alexandra Bech Gjørv

Operations

Development Norway

Projects

International Business Units

International Exploration

Oil Marketing

Markets

North America

Automotive

Extrusion

Rolled Products

Metal Products

Primary Metal Other Businesses

Internal Auditing Legal Affairs Communication

Page 14 9B06M044

Exhibit 3

OIL & ENERGY KEY FIGURES (€ 000,000s)

Financial Results – Oil & Energy 2004 2003 2002 Operating revenues 9,015 7,433 6,923Operating income 3,861 2,621 1,977Adjusted EBITDA 5,179 3,945 3,141RoaCE, per cent 23.4 16.2 11.6Investments 1,496 1,396 1,822Exploration expenses 157 196 441Production cost per boe 2.6 2.6 2.8Realized oil price per bbl, USD 37.3 28.7 24.7Realized oil price per bbl 31.2 25.2 24.1Realized gas price per Sm3 0.14 0.13 0.12 Operational Results – Oil & Energy Oil production (1) 417 393 370Gas production (1) 155 137 110Total oil and gas production (1) 572 530 480Power production, TWh 8.1 7.3 10.1Number of employees 3,527 3,464 4,039 Oil & Energy – Operating Income by Division Exploration and Production 3,516 2,293 1,629Energy and Oil Marketing 329 331 345Eliminations 16 (3) 3Oil & Energy 3,861 2,621 1,977

Note: (1) 1,000 barrels oil equivalents per day NOK1.00=€.012 Source: Hydro Annual Report, December 31, 2004.

Page 15 9B06M044

Exhibit 4

EXPLANATIONS OF HYDROGEN AND RELATED THEMES Hydrogen Hydrogen (symbol H on the periodic table) is the lightest atom in nature and one of the most abundant elements on the earth’s surface. It is non-toxic in its pure form and it possesses the highest energy per unit of weight of any chemical fuel (one kilogram of hydrogen produces the same amount of energy as three kilograms of gasoline). Through combustion with oxygen, hydrogen creates energy, with water as its only by-product. Although hydrogen is found in water (H2O) and hydrocarbons, it does not exist in its natural form alone anywhere in the world because it is so light. Thus, it has to be extracted for use. Production of Hydrogen On a commercial level, hydrogen is frequently derived from methane (the primary component in natural gas), gasoline and methanol. The main challenges with this approach are carbon monoxide emissions, low hydrogen purity and additional costs in reforming the different fuels. Electrolysis The other major method of producing hydrogen is through electrolysis, which involves separating water into hydrogen and oxygen by running an electric current through water. While electrolysis appears to be the most benign environmentally, it has a low conversion rate for the energy required and as such is costly due to the electricity needed. Its impact on the environment depends to a large extent on how the electricity was generated — either through non-renewable sources like coal and nuclear energy or through renewable sources like solar, wind and hydro. Fuel Cells A fuel cell is used to create electricity by reacting two components as they pass through the cell. The two most common components used in fuel cells are hydrogen and oxygen, however, other components such as methanol and oxygen can be passed through in order to create electricity. When using hydrogen and oxygen, the only exhaust generated is water vapor. It differs from a battery that needs to be charged, as a fuel cell will continue producing electricity as long as the two components are allowed to react. Source: Ken Mark, Jordan Mitchell and Tima Bansal, “Aiming Toward a Hydrogen Economy: Icelandic New Energy Co. (Íslensk Ny Orka),” Ivey case no. 9B05M001.

Page 16 9B06M044

Exhibit 5

HYDRO NEW VENTURE PROJECTS

COMPANIES Name Location Products/Services Investment Date Amount Minox Technology AS

Norway Products focus on: • Deoxygenation of sea water used

as injection water for the oil industry

• Deoxygenation of cooling water to prevent corrosion in any process industry

Sep 2001 Not public

Ocean Power Delivery Ltd.

Scotland Pelamis wave energy converter. Mar 2002 Not public

Magtech Norway Developing a technology that uses the linear control of magnetic flux for controlling, converting and distributing electric energy.

Nov 2002 Not public

Comverge Israel Provides software and system solutions to over 500 clients in the electric utility industry.

Sep 2003 Not public

Metallic Power U.S. Zinc/air fuel cells. Feb 2003 – Company closed down in Oct 2004 since it could not raise additional financing

Not public

INVESTMENT FUNDS Name Location Focus Investment Date Amount Nth Power Energy Venture Capital Fund II North America

U.S. High-growth investment opportunities arising from the restructuring of the global energy utility marketplace.

Mar 2002 US$5 million

SAM Private Equity Energy Fund I Switzerland

Switzerland Independent asset management company based in Zollikon Switzerland. SAM has derived the basis for the Dow Jones Sustainability Group Index. The SAM private energy fund invested in the emerging energy sector.

June 2001 ŪS$5 million

Energivekst AS Norway Energivekst is a venture company with the objective to be a vehicle for industrial innovation and entrepreneurship in the energy cluster.

Feb 2002 Not public

Source: Compiled by casewriter, www.Hydro.com and www.fuelcellsworks.com.

Page 17 9B06M044

Exhibit 6

UTSIRA PROJECT: SCHEMATIC AND LOCATION

Wind Hydrogen Schematic Location of Utsira Island

Source: Company files.

Page 18 9B06M044

Exhibit 6 (continued)

WIND TURBINES ON UTSIRA

WIND-HYDROGEN TECHNOLOGY SCHEMATIC

Source: Company files.

Page 19 9B06M044

Exhibit 7

WIND SPEED AND CUSTOMER ELECTRICAL DEMAND Note: Data collected from May 2005 to May 2006. Source: Company files.

Exhibit 8

UTSIRA PROJECT BUDGET

Main Components Technical Parametres Supplier Cost % of Total

Wind Turbines 600 kW Enercon 750 15Flywheel 5 kW Enercon 100 2Master Synchronous Machine 100 kVA Enercon 100 2Hydrogen Engine 55 kW (top load) Continental 200 4Fuel Cell 10 kW IRD 100 2Electrolyser 10 Nm3/h, 48 kW Hydro 500 10Hydrogen Storage Capacity 2400 Nm3 Hydro 500 10Project Management Hydro 2,750 55Total 5,000

Note: All cost data are in €000’s. Data have been disguised to protect confidentiality. Source: Company files.

Dem

and

for e

lect

rical

pow

er (k

W)

0

100

60

20

40

80 Wind speed (m

/s)

0 1500 3000 4500 6000 7500 0

50

30

10

20

40

Time (h)

wind speed (right axis)

demand (left axis)

Page 20 9B06M044

Exhibit 9

TYPICAL DAILY OPERATIONAL PERFORMANCE a. High-wind operation: production and storage of hydrogen

0

20

40

60

80

100

2:24

3:36

4:48

6:00

7:12

8:24

9:36

Time (hh:mm)

Pow

er (k

W)

b. Low-wind operation: consumption of hydrogen

Source: Company files.

0

20

40

60

80

100

7:12

9:36

12:0

0

14:2

4

16:4

8

19:1

2

21:3

6

Time (hh:mm)

Pow

er (k

W) wind power

consumer demand

use of hydrogen

wind power

consumer demand

hydrogen production

Page 21 9B06M044

EXHIBIT 10

INFORMATION ON ISLAND COMMUNITIES

Country Cost per

kWh (€ cents)

CurrentSolution

Population Number of Households

ApproximatePower Needs in MWh

Utsira Norway Today 1.05 240 100 Solution – In Future 0.35 Top 5 Islands in EU Faero Islands Independent Nation 0.15 Diesel 46,962 18,785 375,696 Greenland Division of

Denmark 0.25 Diesel 56,375 22,550 451,000

Azores Portugal 0.45 Diesel 238,767 95,507 1,910,136 Greek Islands Greece 0.15 Diesel/Grid 508,000 203,200 4,064,000 Scottish Islands Scotland 0.15 Diesel/Wind/Grid 120,000 48,000 960,000

OTHER POSSIBILITIES

Island Country Sjaeland Denmark Edgeoya Division of Norway Vendsyssel-Thy Denmark Gotland Sweden Fyn Denmark Saaremaa Estonia Hinnæya Norway Lewis and Harris United Kingdom Lanzarote Spain Skye United Kingdom Soisalo Finland Lolland Denmark Shetland Mainland United Kingdom Rügen Germany Isle of Mull United Kingdom

Page 22 9B06M044

Exhibit 10 (continued)

EXAMPLES OF CURRENT RENEWABLE SOLUTIONS FOR REMOTE COMMUNITIES 1. Australia. In a remote community in Cairns, the Bushlight project paid for by the Australian

Greenhouse Office and managed by ATSIC and the Centre for Appropriate Technology had approved the installation of hydro-electric and wind-powered electricity generators.1 In Australia’s Northern Territory, a solar-diesel generator was installed and funded by Northern Territory Centre for Energy Research.2

2. Bengal. In Sagar, Bengal, wind and solar power was established to provide power for 1,600 families.3

3. Canada. In the Canadian Arctic in Ellesmere Island National Park, half of the energy is provided by photovoltaic (solar) energy and the other half provided by a combination of a wind turbine and a diesel generator.4

4. India. In Rajasthan, India, a solar-power project became operational in 2003 to give power to 130 remote villages (15,000 people) in place of kerosene and candles.5

5. Philippines. In Mindanao, Philippines, a micro-hydro scheme supplies power to 110 households, eliminating the needs for diesel.6

6. United States, Alaska. Seven 100kW wind turbines were approved in October 2004 to deliver electricity into the diesel-generated electricity grid. The project, estimated at $1.9 million, was funded by Alaska Village Electric Cooperative (AVEC) and Northern Power Systems, Inc., a subsidiary of Distributed Energy Systems Corp.7

7. United States, Hawaii. As of 2005, on Maui, a 30 MW wind farm was in process by UPC Hawaii Wind Partners and on the island of Hawaii (Big Island), a 10 MW farm was in process by Hawaii Renewable Development.8

1 Tony Grant, “Peninsula Hopes for Green Light,” The Cairns Post, June 7, 2004, p. 7. 2 “Work Begins on Solar Diesel Generator in NT,” Australian Broadcasting Corporation, February 10, 2003. 3 Paul Brown, “World Bank Rebuked for Fossil Fuel Strategy,” The Guardian, June 21, 2004, p. 13. 4 Natural Resources Canada, http://www.canren.gc.ca/tech_appl/index.asp?CaID=5&PgID=267, accessed October 9, 2005. 5 Paul Brown, “World Bank Rebuked for Fossil Fuel Strategy,” The Guardian, June 21, 2004, p. 13. 6 Paul Brown, “World Bank Rebuked for Fossil Fuel Strategy,” The Guardian, June 21, 2004, p. 13. 7 “Northern Power Systems to Supply Northwind(R) 100 Wind Turbines to Alaska Village Electric Cooperative State-of-the-art Wind Turbines Will Supply Renewable Power to 3 Remote Communities,” PR Newswire, October 14, 2004. 8 eHawaii Government website, www.hawaii.gov/dbedt/ert/wind_hi.html#anchor367806, accessed October 7, 2005.