Page 2 9B06M044operations as Norsk Hydro with a hydroelectric power generation site and a production facility foragricultural fertilizers. The company came under German ownership in 1929 and endured bombings andsabotage during the Second World War, before being handed back to Norwegian authorities. The year1963 marked three important developments for Norsk Hydro: the beginning of aluminum production, theconversion of ammonia production from electrochemical to petrochemical processes and participation inan 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 Norwegiancontinental shelf. Norsk Hydro began operating its first oil field in 1988 and expanded its oil and gasbusiness through participation in multi-company exploration projects and acquisitions. In its aluminumoperation, Norsk Hydro bought ÅSV, the Norwegian state-run aluminum company, and VAW, a majorGerman aluminum supplier. These acquisitions helped Norsk Hydro to double the production of oil, gasand aluminum in less than six years. In 2004, the company divested itself of its 100-year-old fertilizerbusiness 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 ofrevenues and six per cent of operating profits; and Oil & Energy with 4,500 people, which accounted forthe remaining revenue and the bulk of the operating profits. The relationship between the two divisionswas described by Bård Hammervold, head of Marketing & Infochannels in Oil & Energy: “A simpleexplanation 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.ALUMINUMWith 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 Hydrosold more aluminum than it produced, the firm was an active purchaser of raw aluminum in the worldmarkets. Hydro had increased its self-sufficiency in production when it moved from producing 25 per centof primary metal in 1998 to 45 per cent in 2004. The company’s primary markets for aluminum were theautomotive, packaging, construction and printing industries. Hydro was reorganizing to improveefficiencies and increase operating income; as a result, the division had grown by 15 per cent with adjustedearnings 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 9B06M044OIL & ENERGYHydro was the second largest oil and gas operator on the Norwegian continental shelf behind Norway’sgovernment-run Statoil and the third largest oil and gas offshore operator in the world behind Shell andExxon. Hydro’s primary oil and gas operations were in Norway with additional oil and gas productionfacilities in Angola, Canada, Russia and Libya. The company was currently undergoing explorationactivities in the Gulf of Mexico, Iran and Denmark. As of 2005, Hydro operated 14 oil and gasinstallations, with total production being about 570,000 barrels per day. Exhibit 3 reports key financial andoperating 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 ofthe project, and Shell was to take over as the operator of the field once it was operational. The projectincluded an offshore gas development site, an onshore plant and the ability to export gas and condensatesto the United Kingdom in a multi-stream singular pipeline. This undertaking was unique, as it was the firstgas field to be at such an extreme depth (1,100 meters below sea level). When completed in 2007, Norwaywould 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 testingthe viability of proceeding with a development project. The Projects team physically built the capabilitiesto extract the oil, natural gas or other condensates. Operations was responsible for all production andensured that the given fossil fuel was delivered to either a refinery or distributor. Oil and gas fields weretypically operated under license by Hydro since many development projects were funded in coordinationwith other oil and gas companies. Hydro had previously owned an oil refinery, but had sold the business in2001 in an effort to streamline operations.Markets, the fourth division of Oil & Energy, was made up of four subdivisions: Oil and Gas MarketTrading, Oil and Gas Products, Power Production and New Energy. Power Production was responsible forthe operation of Hydro’s 19 hydroelectric power plants in Norway, which had the capacity to produce 10per cent of the country’s combined total power generation. Normal annual production was nine millionmegawatt hours (MWh), which was sufficient to supply electricity to approximately 450,000 homes.2Since Hydro consumed more electricity than it produced, the Power Production division was alsoresponsible 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 itshydroelectric plants, Hydro also sold electricity to the grid.The European Union (EU) promoted the use of renewable energy through the use of green certificatesunder a directive to increase renewable energy to represent 12 per cent of total energy consumption by2010.3 Under a compulsory green certificate power market, renewable energy producers were awardedgreen certificates, and purchasers (electric utilities or electricity wholesalers) were required to buy a certainnumber of green certificates per year. Sweden and Norway were planning a joint renewable energycertificates 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 9B06M044HYDRO’S NEW ENERGY DIVISIONHydro’s New Energy subdivision comprised wind power, hydrogen, research and development, and aventures fund for renewable energy projects. The New Energy division was treated by Hydro as an area forfuture investment. The division employed about 30 people. Senior management articulated how thisdivision 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 PowerBeginning in 2001, Hydro had inaugurated its first wind project, the Arctic Wind Park located in NorthernNorway 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 10other wind parks in the country ranging from 15 to 330 turbines with production capacity of 50 to 1,000MW. The average installed cost of a wind turbine was €1 million per MW. In June 2005, Hydro had signedan agreement to purchase a 50 per cent stake in Scira, a U.K.-based power group that had the rights tobuild a 315 MW offshore wind farm near Norfolk, England.HydrogenHydro had produced hydrogen for use in ammonia production for more than 75 years. Ammonia was, inturn, used in the production of fertilizers. In addition, since 1927, Hydro had produced water electrolysisequipment to separate water into hydrogen and oxygen (see Exhibit 4 for a brief summary of thecharacteristics of hydrogen and its generation and use). In the early 1990s, the company had created aseparate legal entity for the sale of electrolysis equipment: Norsk Hydro Electrolysers A/S. This companywas 100 per cent owned by Hydro and reported to Hydro’s hydrogen unit. Norsk Hydro Electrolysers A/Shad installed more than 300 electrolyser units for use within Hydro and another 200 around the world withexternal organizations. Depending on the size and capacity to produce hydrogen, electrolysers ranged froma capital cost of €5,000 to €10,000 per kW.The company’s hydrogen division had participated as a partner in several hydrogen demonstration projectsaround the world. In 1999, Hydro invested €163,000 in a non-profit organization called the Icelandic NewEnergy Company. This investment was combined with funds from local Icelandic companies, institutionsand global firms, such as Shell and DaimlerChrysler, to support three projects aimed at converting Icelandinto a hydrogen economy by 2050. Besides investing in the project, Hydro Electrolysers installed anelectrolyser unit at the world’s first commercial hydrogen refuelling station to convert water into usable4 Hydro website, www.hydro.com, accessed October 2, 2005.
Page 5 9B06M044hydrogen to power city buses. In addition to the Icelandic project, Hydro had also delivered a refuellingstation in Hamburg as part of the pan-European CUTE initiative5 and was the owner and operator of anelectrolyser in the Clean Energy Partnership (CEP) Berlin project.Research and DevelopmentWorking 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 andinvestigation of future energy options, including wind power and hydrogen. Hydro was also involved in anumber of research initiatives with other companies and the European Union. One example was Hydro’srole in forming HyNet along with Shell Hydrogen and BP. The aim of HyNet was to establish a Europeanhydrogen 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 VenturesIn March 2001, Hydro set up a venture fund of €45 million in order to invest in new technologies related toHydro’s Oil & Energy activities. Hydro Ventures invested in for-profit companies and focused on fivemain areas: renewable energy companies in wind, wave, solar, bio or tidal power; distributed power, powerquality and energy storage; carbon-efficient technologies; enabling technologies; and upstream oil and gascompanies, such as drilling and sub-sea solutions. As of 2005, Hydro Ventures had invested in fourcompanies and three energy funds. Direct investments included a water treatment company, an electricenergy company, both based in Norway, a wave power company in Scotland, and a market intelligencecompany operating in the United States and Israel. Exhibit 5 shows more details about the investments.THE UTSIRA PROJECTLed by the Hydrogen group within the New Energy division, the Utsira demonstration project combinedwind and hydrogen power to demonstrate the delivery of autonomous renewable power. Located off thesouthwest coast of Norway (see Exhibit 6), Utsira was an island with 240 inhabitants and 100 homes. Theidea to combine wind and hydrogen power in a self-sufficient site had been talked about within Hydro’soffices since the late 1990s. However, it was not until Christopher Kloed, then head of HydroElectrolysers, accidentally met up with the island’s chief councillor, Robin Kirkhus, that the project movedforward. In the chance encounter, Kirkhus explained Utsira’s vision to utilize green technology rangingfrom biodynamic foodstuffs and ecological farming to solar power and windmills. Kloed mentioned thepossibility 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 theisland’s windy conditions — it was estimated by Hydro engineers that over the past 10 years, themaximum period of time without wind had been two consecutive days. The choice of Ustira was alsosupported by the following: the electricity load of Utsira households were representative of other Europeanhomes; the island was not too remote from the mainland; a backup system was in place; and the island’sinhabitants were supportive of the demonstration project. Exhibit 7 presents representative data for windspeed and electrical energy demand by customers.5 CUTE stands for Clean Urban Transport for Europe, a European Union public-private project that involved demonstrationprojects for city buses to run with hydrogen fuel cells.
Page 6 9B06M044Hydro executives viewed the project as a research and development initiative with no objective to makemoney. The project purpose was documented internally as: “to demonstrate how renewable energy canprovide safe and efficient energy supply to remote areas.” The project goal was to install a full-scaledemonstration and testing of a wind-hydrogen energy system. The idea was that the wind turbine wouldgenerate electricity for two purposes: to power 10 homes, or 10 per cent of the island. The peak powerdemand was expected to be about 50 to 60 kW, with annual energy consumption of about 20,000 kWh perhome.6 When there was excess wind, the turbines would power the electrolysis unit, which would breakdown water into its basic elements: hydrogen and oxygen. The hydrogen would then be stored and be fedinto a hydrogen fuel cell or a hydrogen internal combustion engine to generate electricity when the windslowed or stopped blowing.Functionality of the SystemA schematic of the system is shown in Exhibit 6. Originally planned with one 600 kW wind turbine, theUtsira development team decided after six months to install two turbines. The second turbine was not partof the stand-alone system but rather produced “green power” for export to Norway’s mainland. The motionof air caused the turbine to turn, creating electric energy, which was then passed through electric cables tothe power grid.During periods of low demand, excess electricity generated by the turbine was automatically channelledthrough 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. Theelectrolyser created hydrogen and oxygen. The hydrogen was pressurized in gas form to 2,900 psi andstored in a large tank (2,400 cubic meters); the tank had been designed to provide two full days ofcontinuous power for the 10 households.When the wind turbines could not generate sufficient electricity to meet demand, the control systemautomatically switched on both the hydrogen fuel cell and the internal combustion engine to take over asthe energy provider. The wind and hydrogen systems could deliver power simultaneously. Before beingtransferred to the power grid, the electricity needed to be transformed from 400 to 220 Volts AC to make itusable 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 ComponentsIn April 2003, Hydro approved the project with a total budget of €5 million (see Exhibit 8). The Utsiradevelopment team of 10 people then worked to secure the main supplier contracts. Hydro forgedagreements with Norwegian government agencies: Enova and NRF,8 organizations to facilitate energydevelopments, and the SFT,9 the pollution authority. Choosing other partners to supply the project requireddetailed 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 lightbulbs are lit?” and energy as “how long are those bulbs lit?” A typical home requires five to six kW of peak power, andconsumes 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.
Page 7 9B06M044 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 theBelgian company Continental was chosen for the 55 kW rebuilt internal combustion engine that usedhydrogen fuel. Other parts of the system, such as the compressor, hydrogen storage tanks, piping andelectrical cables, were either purchased from local suppliers or developed in-house. Finally, HydroElectrolysers supplied the electrolyser unit.In June 2003, construction on the site began, and by autumn the windmills had been set up. During the firstfew months of 2004, the team built the hydrogen plant, and in July 2004, the project was completed withthe installation of the fuel cell and hydrogen-powered internal combustion engine. Given the research focusof the project, a great deal of time was dedicated to developing the system’s components and theirinterconnectivity as the project progressed. In the words of Nakken, the project was not a “plug and play”or turnkey solution.System in OperationAfter the first full year of operations in 2005, the team had encountered several operational challenges andhad made several conclusions on the system’s overall functionality. Nakken summarized the three majorpriorities 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 takinginto account the availability of the stand-alone system over a 30-day period. In case of failures, the homeswere immediately connected back to the ordinary grid. Aside from the initial set-up period, the system wasfully automatic. Hydro had assigned one person to check on the system once a week. In addition, the sitewas being controlled and monitored by Hydro’s mainland research and development center inPorsgrunn/Rjukan.Making the fuel cell work as part of the larger system required that the team adapt the control andregulating systems to allow for automatic switching between the wind turbine, fuel cell and internalcombustion engine. The team also needed to ensure that there was sufficient communication between all ofthe components for operations, such as increasing the pressure of hydrogen gas from the electrolyser to thestorage tanks. Other parts, such as the inverter and transformer, required constant monitoring to ensure thatelectricity was being generated and transferred efficiently.
Page 8 9B06M044As anticipated, during periods when the energy generated by the wind turbine exceeded demand, oftenduring early morning hours, hydrogen was produced and stored (see Exhibit 9a). In contrast, when thissituation reversed and demand exceeded energy generated from wind power, hydrogen was consumed (seeExhibit 9b). However, the efficiency of the fuel cell and internal combustion engine was less thanexpected: overall, approximately 70 to 80 per cent of the energy was lost when converting wind-generatedelectricity to hydrogen and then back again to electricity. As a result, the 2,400-cubic-meter hydrogenstorage tank could provide only 2.9 megawatt hours (MWh) of stored energy, much less than its theoreticalcapacity 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 theclimatic 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 projectwon the prestigious Platts Global Energy Award. It also attracted significant international press with somesources citing the project as the “world’s first hydrogen economy.”POTENTIAL COMMERCIALIZATION OF THE TECHNOLOGYFjermestad Hagen and Nakken saw two potential early markets for a similar concept to Utsira: remotecommunities and grid power balancing.Remote CommunitiesRemote communities could be considered to be islands or any areas that were not connected to a centralelectricity grid service. Within the European Union, there were thousands of populated islands relying ondiesel generators for their main energy source. An estimated 300,000 households within Europe had noaccess 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; MarketPotential Report,” H-SAPS Altener Programme, 2004, p. 8, www.hsaps.ife.no, accessed September 2006.
Page 9 9B06M044Fjermestad Hagen responded: “Consider that there are 1.6 billion people — that’s 25 per cent of theworld’s population, living without any electricity.” A journalist from Britain’s Guardian newspapertouched 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 needswere increasing by one per cent each year. Remote communities that belonged to a country geographicallyseparated (e.g. Portugal and the Azores) were usually subsidized so that consumers would not pay more inthe 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 thesystem was powered by wind, operating costs were made up solely of a water supply for the electrolyserand 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 capitalcost 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 thediesel system and 1.5 per cent annually for the wind/hydrogen system. Fuel costs for the diesel systemranged between €0.15 kWh and €0.50kWh, depending on the remoteness of the community (recall that 1kW of installed power translates into about 3,500 kWh of energy annually). In contrast, the wind/hydrogensystem had no fuel costs. Moreover, if a renewable energy system were used, the island would also be ableto 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 whatthey 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.
Page 10 9B06M044 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 theshort 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 OperatorsThe electricity transmission system for moving electricity from power generation to consumers was oftenreferred to as a grid. Transmission system operators (TSOs) were constantly looking for new technologiesto 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 powersurges, 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 consumerequipment malfunction. Unfortunately, according to experts, these smaller fluctuations tended to increaseas the proportion of wind and other renewable energy supplied to the grid expanded. Moreover, on atimescale of hours to days, fluctuations in wind required additional flexibility.12 Out of a total of 36 majorgrid 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 adaptto less stable supply. On the supply side, technological solutions to smooth smaller fluctuations were alsopossible, including flexible generation such as hydroelectric power, and storage options such as batteriesand electrolysers. The power supplied by such a typical storage system could be upwards of 1 MW, withstored energy capacity of up to 10 hours or more (i.e. 10 MWh). Overall, because such a system wouldcharge 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 9B06M044the electrolyzer would consume electricity to produce and store hydrogen. In contrast, during periods ofsupply shortages, the stored hydrogen could be fed into a fuel cell to generate electricity (which alsoyielded green certificates). Moreover, unlike batteries, the incremental cost of increasing energy storagecapacity also was quite small. And excess hydrogen could be sold to customers on the open market forupwards of €0.10 per cubic meter. It was estimated that the system would be able to generateapproximately 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 batteryemployed with a five to 10 year usable life. In addition, capital costs had a variable component based onthe 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.13A comparably sized hydrogen-electrolyzer system was expected to cost €12,000 per kW (€4,000 for thefuel cell, €6,000 for the electrolyzer and €2,000 for the piping and control system). However, the additionalcapital cost for stored energy was only about half that of batteries, roughly €20-25 per kWh.14 Annualoperating 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 percent annually for the next 10 years.15PLANNING THE NEXT STEPSThe central question was how to move forward — being a team of two with access to experts from acrossthe 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 toresearch institutes, electricity providers and island communities around the world. They had also beencontacted by a number of interested parties, including a wind farm operator in Scotland, a miningcommunity in Australia, an energy institute in Turkey and energy providers in Greece, the Azores andChile. 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.
Page 12 9B06M044 Exhibit 1 HYDRO’S KEY FIGURES (€ 000,000s) 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 data Investments 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 return RoaCE 13.0 8.4 7.2 RoaCE - normalized 7.9 6.2 6.6 NOK per share Earnings 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 Environment Society Total 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 2.6 Total recordable injuries (per million hours worked) 5.6 7 10.3 *Inclusive Agri (Yara) Environment Total energy consumption (PJ) 181.4 165.9 182 Greenhouse gas emissions (million tonnes CO2e) 8.84 8.16 9.17Notes: NOK = Norwegian Kroner: NOK1.00 = €0.12 RoaCE: Return on average capital employed PJ: petajoule F/X Rates: Foreign exchange ratesSource: Hydro Annual Report 2004, www.hydro.com, accessed December 31, 2004.
Page 13 9B06M044 Exhibit 2 HYDRO’S ORGANIZATIONAL STRUCTURE Hydro President and CEO Eivind Reiten Communication Legal Affairs Internal Auditing Leadership & Culture Oil & Energy Aluminum Finance Executive Vice Executive Vice Executive Vice Executive Vice President President President President Alexandra Bech Gjørv Tore Torvund Jon-Harald Nilsen John O. Ottestad Operations Primary Metal Other Businesses Development Norway Metal Products International Business Units Rolled Products Markets Extrusion International Exploration Oil Marketing Automotive Projects North AmericaSource: Company files.
Page 14 9B06M044 Exhibit 3 OIL & ENERGY KEY FIGURES (€ 000,000s) Financial Results – Oil & Energy 2004 2003 2002 Operating revenues 9,015 7,433 6,923 Operating income 3,861 2,621 1,977 Adjusted EBITDA 5,179 3,945 3,141 RoaCE, per cent 23.4 16.2 11.6 Investments 1,496 1,396 1,822 Exploration expenses 157 196 441 Production cost per boe 2.6 2.6 2.8 Realized oil price per bbl, USD 37.3 28.7 24.7 Realized oil price per bbl 31.2 25.2 24.1 Realized gas price per Sm3 0.14 0.13 0.12 Operational Results – Oil & Energy Oil production (1) 417 393 370 Gas production (1) 155 137 110 Total oil and gas production (1) 572 530 480 Power production, TWh 8.1 7.3 10.1 Number of employees 3,527 3,464 4,039 Oil & Energy – Operating Income by Division Exploration and Production 3,516 2,293 1,629 Energy and Oil Marketing 329 331 345 Eliminations 16 (3) 3 Oil & Energy 3,861 2,621 1,977Note: (1) 1,000 barrels oil equivalents per day NOK1.00=€.012Source: Hydro Annual Report, December 31, 2004.
Page 15 9B06M044 Exhibit 4 EXPLANATIONS OF HYDROGEN AND RELATED THEMESHydrogenHydrogen (symbol H on the periodic table) is the lightest atom in nature and one of the most abundantelements on the earth’s surface. It is non-toxic in its pure form and it possesses the highest energy per unitof weight of any chemical fuel (one kilogram of hydrogen produces the same amount of energy as threekilograms of gasoline). Through combustion with oxygen, hydrogen creates energy, with water as its onlyby-product. Although hydrogen is found in water (H2O) and hydrocarbons, it does not exist in its naturalform alone anywhere in the world because it is so light. Thus, it has to be extracted for use.Production of HydrogenOn a commercial level, hydrogen is frequently derived from methane (the primary component in naturalgas), gasoline and methanol. The main challenges with this approach are carbon monoxide emissions, lowhydrogen purity and additional costs in reforming the different fuels.ElectrolysisThe other major method of producing hydrogen is through electrolysis, which involves separating waterinto hydrogen and oxygen by running an electric current through water. While electrolysis appears to bethe most benign environmentally, it has a low conversion rate for the energy required and as such is costlydue to the electricity needed. Its impact on the environment depends to a large extent on how the electricitywas generated — either through non-renewable sources like coal and nuclear energy or through renewablesources like solar, wind and hydro.Fuel CellsA fuel cell is used to create electricity by reacting two components as they pass through the cell. The twomost common components used in fuel cells are hydrogen and oxygen, however, other components such asmethanol and oxygen can be passed through in order to create electricity. When using hydrogen andoxygen, the only exhaust generated is water vapor. It differs from a battery that needs to be charged, as afuel 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 Norway Products focus on: Sep 2001 Not public AS • Deoxygenation of sea water used as injection water for the oil industry • Deoxygenation of cooling water to prevent corrosion in any process industry Ocean Power Scotland Pelamis wave energy converter. Mar 2002 Not public Delivery Ltd. Magtech Norway Developing a technology that uses the Nov 2002 Not public linear control of magnetic flux for controlling, converting and distributing electric energy. Comverge Israel Provides software and system Sep 2003 Not public solutions to over 500 clients in the electric utility industry. Metallic Power U.S. Zinc/air fuel cells. Feb 2003 – Company Not public closed down in Oct 2004 since it could not raise additional financing INVESTMENT FUNDS Name Location Focus Investment Date Amount Nth Power Energy U.S. High-growth investment opportunities Mar 2002 US$5 Venture Capital Fund arising from the restructuring of the million II North America global energy utility marketplace. SAM Private Equity Switzerland Independent asset management June 2001 ŪS$5 Energy Fund I company based in Zollikon million Switzerland Switzerland. SAM has derived the basis for the Dow Jones Sustainability Group Index. The SAM private energy fund invested in the emerging energy sector. Energivekst AS Norway Energivekst is a venture company with Feb 2002 Not public the objective to be a vehicle for industrial innovation and entrepreneurship in the energy cluster.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 IslandSource: Company files.
Page 18 9B06M044 Exhibit 6 (continued) WIND TURBINES ON UTSIRA WIND-HYDROGEN TECHNOLOGY SCHEMATICSource: Company files.
Page 19 9B06M044 Exhibit 7 WIND SPEED AND CUSTOMER ELECTRICAL DEMAND wind speed (right axis) 100 50 Demand for electrical power (kW) 80 Wind speed (m/s) 40 60 30 40 20 10 20 0 0 0 1500 3000 4500 6000 7500 demand (left axis) Time (h)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 15 Flywheel 5 kW Enercon 100 2 Master Synchronous Machine 100 kVA Enercon 100 2 Hydrogen Engine 55 kW (top load) Continental 200 4 Fuel Cell 10 kW IRD 100 2 3 Electrolyser 10 Nm /h, 48 kW Hydro 500 10 3 Hydrogen Storage Capacity 2400 Nm Hydro 500 10 Project Management Hydro 2,750 55 Total 5,000Note: All cost data are in €000’s. Data have been disguised to protect confidentiality.Source: Company files.
Page 20 9B06M044 Exhibit 9 TYPICAL DAILY OPERATIONAL PERFORMANCEa. High-wind operation: production and storage of hydrogen 100 80 wind power Power (kW) 60 40 consumer demand 20 0 2:24 3:36 4:48 6:00 7:12 8:24 9:36 Time (hh:mm) hydrogen productionb. Low-wind operation: consumption of hydrogen 100 80 wind power Power (kW) 60 40 consumer demand 20 0 7:12 9:36 12:00 14:24 16:48 19:12 21:36 Time (hh:mm) use of hydrogenSource: Company files.
Page 21 9B06M044 EXHIBIT 10 INFORMATION ON ISLAND COMMUNITIES Country Cost per Current Population Number of Approximate kWh Solution Households Power Needs in (€ cents) 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 0.25 Diesel 56,375 22,550 451,000 Denmark 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 COMMUNITIES1. 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.22. Bengal. In Sagar, Bengal, wind and solar power was established to provide power for 1,600 families.33. 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.44. 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.55. Philippines. In Mindanao, Philippines, a micro-hydro scheme supplies power to 110 households, eliminating the needs for diesel.66. 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.77. 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.81 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.