kap1-5 Faktahefte eng 04 - Forsiden - regjeringen.no · Enova Statnett Norwegian Water Resources...

11.3.5 Statnett SFStatnett SF was founded in 1992. The Minis-try of Petroleum and Energy acts as itsowner on behalf of the government, as spe-cified in the Act of 30 August 1991 relatingto state enterprises.

Statnett SF is responsible for the con-struction and operation of the central elec-tricity grid. It owns about 87 per cent of thecentral grid, and operates the entire sys-tem. Statnett also has short- and long-termsystem responsibility. This means that itcoordinates the operation of the entire Nor-wegian electricity supply system, and ensu-res that the amount of electricity generatedis always equal to the amount consumed.

Statnett’s revenues are regulated by theNVE as part of its regulation of monopolyoperations.

1.3.6 Enova SFEnova SF was founded on 22 June 2001.Based in Trondheim, it is subordinate tothe Ministry of Petroleum and Energy.

On 1 January 2002, Enova becameresponsible for government efforts torestructure energy production and use. Thiswork had previously been split between theNVE and the electricity distribution utilities.Enova’s activities are financed from an Ener-gy Fund, which receives the revenues gene-rated by a levy of NOK 0.01 per kWh on thedistribution tariff, and from ordinary appro-priations over the central government bud-get. Its tasks are to promote more efficientenergy use, the production of new rene-wable forms of energy, and environment-fri-endly uses of natural gas. Quantitative goalshave been set for Enova’s activities.

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Figure 1.1 Organisation of the Ministry of Petroleum and Energy

Minister

Secretary General

Enova Statnett Norwegian Water Resourcesand Energy Directorate

Administration, Budgets and Accounting Department

Energy and WaterResources

Department

Petroleum Department

EnergySection

Energy LawSection

InternationalSection

PowerMarketSection

New, Rene-wable EnergySources andEnergy Use

Section

WaterResources

Section

Exploration and Production -

Market Department

Information Section

Political Adviser

State Secretary

2

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Water inflow

Electricity productionReservoirs filling

Drawdown from reservoirs

TWh

Figure 2.1 Variations in water inflow and electricity output during a year

Source: Nord Pool

Week

tions, but a shorter utilisation period. A high-head power station is often excavated nearthe reservoirs used to regulate the volume ofits water supply. Power station and reser-voirs are connected by tunnels through therock or pipes down the mountainside.

Power stations with an installed capacityof up to 10 MW are designated as small,and usually sub-divided into the followingcategories:• micro (installed capacity below 0.1 MW)• mini (installed capacity from 0.1-1 MW)• small (installed capacity from 1-10 MW)Small power stations are often installed onstreams and small rivers without regulationreservoirs. Their output will then vary withthe level of water flow.

2.1.1 Water inflowWater inflow is the volume of water flowingfrom the entire catchment area of a riversystem into the reservoirs. A catchmentarea is the geographical area which collectsthe precipitation which runs into a particu-lar river system. Useful inflow is theamount of water which can be used forhydropower generation.

Precipitation levels vary from one part of

the country to another, between seasons,and between years. Precipitation is highestin coastal and central parts of western Nor-way. There is also a clear tendency for preci-pitation to increase with elevation above sealevel. Mean annual precipitation is lowest inthe upper Otta valley (300 mm) and ininland parts of Finnmark county (250 mm).The mean annual precipitation in much ofwestern Norway is 3 000-3 500 mm.

Inflow is high during the spring thaw,but normally decreases during summer.High rainfall generally results in an increa-se before the onset of winter, when inflow isnormally very low.

It also varies during the year, dependingon local geographical and climatic conditi-ons. The spring thaw is later in inland regi-ons and in the mountains than near thecoast and in lowland areas. In much of low-land eastern Norway, western Norway andTrøndelag, the rivers run highest duringMay. The highest water levels near thecoast occur at the end of April, but aredelayed until June or July in inland andupland regions. In northern Norway, dis-charge volumes reach a peak in June, orsomewhat earlier in coastal areas.

2Precipitation varies substantially from

year to year and is more than twice as highin the wettest years as in the driest ones.

From 1980 and 1993, precipitation inseveral years was high and ensured highwater inflow for power generation. It wasrelatively low in 1993 and 1994 but veryhigh in 1995 – resulting in record powergeneration. Inflow and electricity generati-on were considerably below normal levelsin 1996. Since then, the level of inflow hasbeen relatively high, and particularly so in2000. Inflow in both 2002 and 2003 wasbelow the normal level. However, variationsthrough the year were considerable in2002. From January-July, inflow was 89TWh or 12 TWh above the normal level.However, the autumn was unusually drywith very low inflow. It was no more than 22TWh, or 19 TWh below normal. Variationsin actual power generation from year toyear over the past decade can be attributedprimarily to differences in inflow, sincegenerating capacity increased very little.

In addition to variations in inflow, elec-tricity demand fluctuates over the year andis much higher in winter than in summer.In fact, the pattern of demand – and thusthe amount which must be generated – is

generally the reverse of inflow variations.When inflow is high, output is often low –and vice versa. Figure 2.1 shows the relati-onship between mean output and usefulinflow over a year. Consumption can alsovary considerably between years becausetemperature changes affect the amount ofelectricity needed for heating.

2.1.2 Regulation reservoirsThe potential energy of water can be storedin regulation reservoirs constructed eitherin natural lakes or in artificial basins createdby damming a river. Water is collected inthe regulation reservoirs when inflow ishigh and consumption low. When inflow islow and consumption high, stored water canbe drawn from the reservoirs and used togenerate electricity. Regulation reservoirsare generally situated in sparsely populatedareas, and usually at high altitudes in themountains in order to make the fullest pos-sible use of the head of water. The differen-ce between the highest and lowest permit-ted water levels in a reservoir is stipulated ina watercourse regulation licence (rules forreservoir drawdown), which takes intoaccount of such factors as topography andenvironmental considerations.

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Maximum (1990–2003)

2003

Minimum (1990–2003)

Median (1990–2003)

Figure 2.2 Degree of filling of reservoirs in 2003Source: Norwegian Water Resources and Energy Directorate

Week

Per

cen

t

2

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Storing water in the summer for use inwinter months, when the demand for powerpeaks, is known as seasonal regulation.

Dry- or multi-year regulation is madepossible by large reservoirs which canstore water in wet years for use in yearswhen precipitation is low. Short-term regu-lation involves a daily or weekly filling andemptying cycle.

A reservoir’s energy capability is theamount of power which can be generatedwhen it is full. Since 1980, the energy capa-bility of Norway’s reservoirs has risen byjust over 26.5 TWh. At 1 January 2004, thetotal energy capability was about 84.3 TWh,corresponding to just over two-thirds ofannual electricity consumption. The degreeof filling of the reservoirs is a measure ofhow much water (potential energy) theycontain at any given time. Figure 2.2 showschanges in the degree of filling during2003, and the minimum, median and maxi-mum degree of filling in the 1990–2003 peri-od, expressed as a percentage of the totalenergy capability of the reservoirs.

Normally, water will be drawn off duringthe autumn and winter when electricitydemand is highest. Demand reaches itslowest level in spring and summer, and the

reservoirs refill. Changes in the degree offilling of the reservoirs reflect variations inelectricity generation and water inflowduring the year.

An economic gain can be obtained bypumping water uphill to a reservoir with agreater head of water, because the potentialenergy of water increases in proportion toits head. If electricity prices are low, it maybe profitable for operators to use power tomove water to a reservoir at a higher altitu-de, so that the water can be used for gene-ration when prices rise again.

2.1.3 Electricity generationNorway now has a total installed capacity ofabout 27 700 MW at 581 hydropower stati-ons larger than 1 MW. In addition come255 MW from thermal2 and 100 MW fromwind power stations. The mean annualgenerating capability of a hydropower stati-on is calculated from its installed capacityand the expected annual inflow in a year ofnormal precipitation. Thirty years is thestandard period used to calculate normal

Figure 2.3 Installed capacity

Sources: Norwegian Water Resources and Energy Directorate and Statistics Norway

2 “Thermal power station” includes all facilities generatingelectricity from fossil fuels, biofuels or nuclear energy.

MW

30 000

25 000

20 000

15 000

10 000

5 000

2

Kvilldal power station in Rogaland coun-ty is Norway’s largest, with a maximumgenerating capacity of 1 240 MW. This cor-responds to about 4.5 per cent of the Nor-wegian total. Table 2.3 shows the numbersand installed capacity of hydroelectricpower stations in various size groups at 1January 2002.

Electricity output in western and sout-hern Norway and in Nordland county exce-eds local consumption. In eastern Norway,on the other hand, electricity consumptionis much higher than the amount generatedin the region. This means that power mustbe transmitted from western and northernregions to the south and east of the country.

The flow of electric power between regi-ons of Norway is also influenced by powerexchange with Denmark, Sweden and Fin-land. Current transmission capacity fromNorway to its neighbours is about 4 000MW. The connections are used for bothimport and export of power (see Chapter7). Power output was generally above avera-ge in the second half of the 1980s and thebeginning of the 1990s because inflow washigh. It was below the mean level in both1996 and 1997. In 1998–2001, hydropoweroutput was generally relatively high. Preci-pitation was above normal for several yearsin a row, with hydropower output high as aresult. In 2000, a new generation record of

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Table 2.3 Hydropower stations in operation at 1 January 2004 by size and total installed capacity *

MW Number Total installed capacity, Mean annual output,MW GWh/year

0–0.1 74 3 180.1–1 98 14 741–10 258 952 4 32310–100 246 8 985 40 766100– 77 17 764 73 326

* Figures for power stations below one MW are based on a study of micro and mini power stations connected to

the grid, carried out by SKM Energy Consulting and completed in 2000.

Source: Norwegian Water Resources and Energy Directorate

Figure 2.4 Trends in hydropower output and mean annual generating capability


Production in a normal year

Consumption

TWh

Actual production

2143 TWh was set, while total output in 2001was only slightly higher than in a normalyear at 120.9 TWh. Figure 2.4 shows trendsin mean annual generating capability andactual hydropower output in Norway from1980 to 2001.

2.1.4 Hydropower potentialNorway’s hydropower potential is theamount of energy in its river systems whichis technically and financially available togenerate electricity, and was calculated tobe 186.5 TWh/year at 1 January 2004.These calculations are based on 1970–99the reference period. Figure 2.5 shows Norway’s hydropower potential at 1 January2004. This includes river systems developed for hydropower, under develop-ment and protected. Other categories arerivers covered by licence applications, forwhich licences have been granted or refu-sed, and for which prior notification ofapplications has been submitted.

Of Norway’s total hydropower potential,36.5 TWh is in protected watercourses, andapplications for development projects cor-responding to 1.4 TWh have been refused.These two categories are therefore un-available for development, leaving a potenti-al of 30.2 TWh in river systems not protected from hydropower development.

At 1 January 2004, the developed meanannual generating capability was 118.4TWh. In addition, projects with a capacity of1.2 TWh were under construction, and thedevelopment of a further 1.4 TWh had beenlicensed.

Most hydropower projects were classifi-ed in the White Paper on a Master Plan forWater Resources. The various categoriesused in this Master Plan indicate the orderin which river systems should be developed.Giving priority to the lowest-cost projectsand those with the fewest conflicts of inte-rest is considered important. The MasterPlan is further discussed in Chapter 4.2.1.

Upgrading hydropower stations involvesmodernising them to use more of the poten-tial energy of the water. In addition, opera-ting costs can be reduced and operatingreliability improved. The head loss can bereduced by widening water channels andincreasing tunnel cross section, for instan-ce. Utilisation rates can also be improvedby using more modern turbine and genera-tor technology.

Expansion involves major works such astransferring water from other catchmentareas, enlarging existing regulation reser-voirs or constructing new ones, increasingthe head of water or expanding technicalinstallations to increase the available power

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Figure 2.5 Norway’s hydropower potential at 1 January 2003, TWh/year


Remainder

Permanently protected

Prior notification

Licence application

Licence granted

Under construction

Developed

36.5 TWh

1.3 TWh

3.6 TWh

0.5 TWh

1.0 TWh

23.9 TWh

118.3 TWh

2

27

Figure 2.6 Gross investment in the electricity supply system. Fixed 2003 NOK

Sources: Norwegian Water Resources and Energy Directorate, Ministry of Petroleum and Energy

Other

Regional and distribution grid

Central grid

Production installations

NO

K b

illio

n

NOK 475 million to local authorities andNOK 122 million to central government in2003.

Local authorities affected by hydroelec-tric development are also entitled to buy aproportion of the power generated. Thelicensee can be required to sell up to 10 percent of the electricity generated to the localauthorities concerned. If this exceeds gene-ral power consumption in the local authori-ty, the county council is entitled to buy thesurplus. The licensee can also be requiredto sell five per cent of the power generatedto the central government, but the latterhas not exercised this right so far. Theprice paid by the power recipient must cor-respond roughly to generating costs or thefull cost of delivery. Deliveries under theseprovisions total about 8.5 TWh/year. Taxes,power supplied under licence terms andfees from power installations account for alarge proportion of total revenues in localauthorities which host major hydroelectricdevelopments.

2.6 The role of the electricity supply sector in the Norwe-gian economy

The gross product in the electricity supplysector in 2003 was NOK 37.2 billion, orroughly three per cent of gross domesticproduct in mainland Norway.

Real capital in the electricity supply sys-tem amounted to NOK 170 billion in 2003,corresponding to 5.3 per cent of fixed realcapital in mainland Norway.

Investment in the power supply sectortotalled about NOK 6 billion in 2003. Grossinvestment in the sector has declined overthe past 15 years, particularly for the con-struction of new power stations. Investmentin the grid has also fallen. Figure 2.6 showstrends in gross investments in the electrici-ty supply system since 1980.

Employment in the electricity supplysector rose steadily during the 1980s andstabilised after 1989. The number of peopleemployed has declined in recent years.About 15 000 people worked in the electri-city supply sector in 2003.

3

District heating

Coal and coke

G J

Figure 3.1 Per capita energy use in OECD countries, 2002

Source: Energy balances of OECD countries, IEA/OECD Paris

Natural gas

Bioenergy

Canada

USA

Finland

Norway

Sweden

Denmark

Germany

France UK

Italy

OECD

Petroleum products

Electricity

3.1. Factors influencing energyuse trends

A country’s energy use and material livingconditions are normally closely related.Generally speaking, energy use rises witheconomic growth because the need forenergy increases as more goods and servi-ces are produced. Economic growth meanshigher household incomes which are devo-ted in part to expanding consumption, inclu-ding the direct and indirect use of energy.

The effect of economic growth on ener-gy use will depend on which sectors of theNorwegian economy are growing. Energyusage varies widely from one sector to anot-her in terms of both energy mix and energyintensity in production.

Considerable developments have occur-red with electrical products for private hou-seholds and industry. Falling product pricescombined with rising disposable incomeshave made new products available to morepeople. Many products once confined to thefew are now to be found in most homes.

Demographic factors such as populationsize, age structure, settlement patterns andthe number and size of households have animpact on energy demand. Populationgrowth leads to an increase in energy usebecause more houses, schools and com-mercial buildings are built, and these needheating and lighting. Population growthalso results in higher consumption of goodsand services produced with the aid of ener-gy.

Energy use will be higher for a givennumber of people living in many small hou-seholds rather than in fewer large house-holds. Over the past few years, the numberof Norwegian households has increased bymore than would be expected from popula-tion growth alone.

Energy use also depends on energy pri-ces. Higher energy prices boost productioncosts for industry as well as the cost to hou-seholds of using electricity and other ener-gy carriers. This usually constrains energyuse.

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3

3.2 Trends in energy use

Per capita energy use in Norway is somew-hat higher than the OECD average. Seefigure 3.1. However, the proportion of ener-gy use accounted for by electricity is consi-derably higher than in other countries. Themain reasons for the high proportion ofelectricity use are that Norway has hadaccess to plentiful supplies of relativelycheap hydropower, and that governmentinvestment has focused on hydropowerdevelopment. A large energy-intensive

industrial sector has developed as a result,and electricity is widely used to heat buil-dings and water.

Net domestic energy use in Norwayduring 2003 came to 787 PJ, correspondingto 219 TWh. From 1980 to 2003, net domes-tic energy use increased by an average of1.4 per cent per year. Figure 3.2 showsenergy use by carrier and consumer cate-gory in 2003.

Stationary energy use is defined as netdomestic energy use minus energy utilisedfor transport purposes. Stationary energy

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Gross and net energy useGross energy use represents domestic production plus imports minus exports. Whencalculating gross consumption of petroleum products, adjustments are also made forchanges in bunkers and stocks.

Net domestic energy use is defined as gross energy use minus the energy utilised toconvert and transport energy ready for the end user, energy carriers used as rawmaterials, and transmission losses.

Figure 3.2 Energy use by carrier and category in 2003

Source: Energy accounts, Statistics Norway

Coal, coke

Gas

District heating

Bioenergy

Petroleum products

Electricity

PJ

Energy-intensivemanufacturing

Pulp and paperindustry

Mining and othermanufacturing

Services, households, etc

Transport

3

31

use in Norway came to 588 PJ in 2003, cor-responding to 163 TWh. This was up by 3.4per cent from the year before. Figure 3.3shows trends in stationary energy use byenergy carrier from 1980 to 2001.

Electricity is the most important Norwe-gian energy carrier. Stationary electricityconsumption in 2003 totalled 103 TWh, cor-responding to 372 PJ. Oil products, woodand waste (bioenergy) are the next mostimportant stationary energy carriers in Nor-way. Stationary consumption of oil products

in 2003 totalled 94 PJ, corresponding to 26TWh, while consumption of various types ofgas came to 21 PJ, corresponding to almostsix TWh. Recorded use of bioenergy total-led 51 PJ, corresponding to 14 TWh. Dis-trict heating contributed seven PJ, corres-ponding to the consumption of almost twoTWh by end users – of which householdsand service sectors accounted for six PJ. Inaddition, some coal and coke are used.

A marked shift from oil products to elec-tricity has taken place over the past 20

Figure 3.3 Trends in stationary energy use


Coal and cokeNatural gas

Bioenergy

Electricity

PJ

Electricity

Fuel oil

NO

K/k

Wh

Figure 3.4 Price of utilised energy for households, including taxes. Fixed 2003 NOK

Sources: Statistics Norway and Ministry of Petroleum and Energy

Oil

3

years, with consumption of the latter up byabout 50 per cent since 1980. Stationary oilconsumption has declined by about 65 percent over the same period. Partly becauseof the effect of the water inflow shortfall onelectricity supplies, however, consumptionof heating oils increased relatively sharplyfrom 2002 to 2003. A normalisation of condi-tions in the power market will probably leadto a readjustment of stationary oil consump-tion.

The latter experienced its sharpestdecline up to the start of the 1990s, and hassince fluctuated somewhat from year toyear. Heavy heating oil has seen the big-gest fall in consumption. See chapter 3.4.1.Bioenergy consumption has shown a risingtrend since 1980.

The changeover from heating oils to elec-tricity took place primarily up to the start ofthe 1990s. Figure 3.4 shows price trends forheating oil and electricity to households.

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Other equipment 7%

Space heating 41%

Heating water 24%

Lighting 11%

Cooking/boiling 4%

Washing 3%

Cooling 8%Drying 2%

Figure 3.5 Electricity consumption in households by purpose

Source: Statistics Norway

Figure 3.6 Residential heating methods in Norway


1995

1988

1981

1973

Solid fuel stoves Liquid fuel stoves Fitted electricradiators

Portable electricradiators

Central heating/air conditioning

TWh

3That part of consumption used for tech-

nical purposes is called “electricity-speci-fic”, and can only be met by this form ofenergy. A large number of electricity-speci-fic products for operating technical equip-ment are found in all sectors. Most otherelectricity consumption is accounted for byspace and water heating. No regular statis-tics on electricity consumption for heatingare available. In its 1992 household survey,Statistics Norway looked how electricitywas used in Norwegian households. Thisstudy estimated that space heating accoun-ted for 41 per cent.

The consumer can use various energycarriers for heating purposes. The possibili-ty of alternating between different heatingmethods is crucial to the reliability of a sup-ply system based on hydropower. To beable to change energy carrier at short noti-ce, consumers must have installed severaltypes of heating equipment. Figure 3.6shows trends in the use of the most impor-tant methods of residential heating in Nor-way since 1973. Of the dwellings with twoor more heating systems in 1990, mostused a combination of wood-burning stoves

and electric radiators. This gives an indica-tion of the possibilities for substituting oneenergy carrier with another at short notice.

3.3 Energy use by sector

Studies of the distribution of stationaryenergy use between different consumergroups usually distinguish between manu-facturing and mining, private and publicservices and households. Manufacturing isusually sub-divided into energy-intensivemanufacturing, the pulp and paper industryand other manufacturing. Figure 3.7 showstrends in stationary energy use by sector.Electricity accounts for about three quar-ters of total stationary energy use in Nor-way.

Growth in energy use over the past 20years has been highest in the householdand service sectors. Energy use has risenby 70 per cent in the private services sectorand 25 per cent in households since 1980.

Stationary energy use in energy-intensi-ve industry and the pulp and paper sectorhas increased by 39 per cent since 1980.

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Figure 3.7 Stationary energy use by sector


Other manufacturing and miningPrivate households Energy intensiveindustry

PJ

Private servicesPulp and paperOther consumers

Public services

3

business and industry and in private house-holds when necessary. Rapid switching bet-ween different energy carriers is possible insystems utilising combined oil/electric boi-lers.

Oil is the principal fuel used in Norwe-gian water-based central heating systems.Renewable energy sources, heat pumps andwaste heat can also be used in such sys-tems.

3.4.2 Biomass Bioenergy can be produced by incineratingor fermenting biomass or by treating it che-mically. Biomass includes firewood, blackliquor3, bark and other forms of woodwaste, and waste from households andindustry used to provide district heating.Fuel such as gas, oil, pellets and briquettescan be produced from biomass.

Recorded use of bioenergy in 2003 total-led about 51 PJ, corresponding to 14 TWh.The pulp and paper industry used some 38per cent of this, with black liquor accoun-

ting for about two thirds and bark for onethird. Roughly six PJ/year of bark, chip-pings and other waste is processed to pro-duce other energy carriers. Other industri-es used wood and other biofuels equivalentto about 48 per cent of total bioenergy usein 2003. Firewood used to provide heatingaccounts for a substantial proportion of this.

The extent to which biofuel is used andits applications depend on factors such asavailable supplies and their quality andemission standards. Manufacturing ofpaper and pulp and of wood and wood pro-ducts requires large amounts of heat forvarious drying processes, so that the ener-gy in wood waste such as bark and chip-pings can be used without further proces-sing in large incineration plants. A proporti-on of the waste in large landfills can beincinerated, and the heat energy can beused directly or in thermal power generati-

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Figure 3.8 Consumption of oil for stationary combustion by product

Source: Norwegian Petroleum Institute

3 Black liquor is the residue from wood used to produce

chemical pulp.

0

1000

500

1500

2000

2500

3000

mill

litr

es

4000

73 75 77 79 81 83 85 87 89 91 93 95 97 99 01 03

3500

Heating oil

Light fuel oil

Heavy distillates

Heavy fuel oil < 1% sulphur

Heavy fuel oil < 2.5% sulphur

4500

3

36

Figure 3.9 Consumption of district heating by various consumer groups


on. Biofuel used in households and in smallincineration plants often requires more pro-cessing to be suitable for transport, storageand handling.

Processing of biofuel has increased inrecent years. Biofuel in the form of pelletsand briquettes is more suitable for storage,transport and use in automated incinerationplants.

3.4.3 Electricity The 1995 survey of living conditions by Sta-tistics Norway and the Norwegian BuildingResearch Institute showed that fitted andportable electric radiators were the mostimportant source of heating in 58 per centof dwellings. A major shift from heating oilto electricity as the primary source of heatoccurred in 1973-95. See figure 3.6.

Over half the dwellings with only onesource of heat use electricity for heating. Indwellings with two or more sources of heat,a combination of electricity and wood ismost common.

Studies for the Norwegian WaterResources and Energy Directorate (NVE)show that rather more than half of all ener-

gy use in commercial buildings is for hea-ting purposes, and that two thirds of theenergy used for heating is electricity.

3.4.4 District heating The technology used to supply hot water orsteam to households, commercial buildingsand other consumers from a central sourceis known as district heating. Heat transpor-ted through insulated pipes is mainly usedfor space heating and hot water.

District heating systems can utiliseenergy extracted from waste and sewage,or waste heat and gas from industrial sour-ces which would otherwise be lost. Hotwater or steam in district heating installati-ons can also be produced using heatpumps, electricity, gas, oil, chippings orcoal. About half of Norway’s net deliveriesof district heating derive from waste incine-ration plants.

Preliminary figures for 2003 show thatconsumption of district heating was aboutseven PJ, or roughly two TWh. Some two-thirds is used in service sectors, while hou-seholds and manufacturing/mining usedabout 15 per cent each.

0

600

800

1 200

GW

h

1 600

Agriculture

Manufacturing

and mining

Services

Households

1 400

200

400

1 000

1994 1995 1996 1997 1998 1999

3

37

District heating in OsloThe district heating system in Oslo is the largest in the country and accounts forabout half the total in Norway. Figure 3.10 shows trends in district heating for Oslo.

The Viken Energinett company distributed and sold about one TWh of district hea-ting in 2003. In the course of a year, production is split more or less evenly betweenwaste incineration and oil/electricity. Year-on-year variations in whether oil or electri-city is chosen depend on the relative prices of these energy carriers.

Development of the district heating system in central Oslo began in 1937, but onlyreally got going in the early 1980s in order to utilise heat from two waste incinerationplants. These are the main heat sources today. In addition, electric and oil-fired boilersare used to meet peak demand for power in winter. When the outdoor temperature islow, the hot water/steam is piped into the network at a temperature of about 120°C. It isdistributed to individual customers from substations normally located in customer cel-lars, and is returned to the central installation at a temperature of about 70°C. About 750large customers and 2 250 individual dwellings are linked to the district heating system.

Oslo’s district heating installations now meet about 15 per cent of its heatingneeds. These systems have been developed in the city centre and three other areas,and three of these areas have been linked together in a single network since 1998.The main campus of the University of Oslo and Ullevål University Hospital are twoexamples of large customers. The hospital’s boiler room is now used mainly to meetits special needs for steam, but it can also be used as part of the district heating sys-tem – either to help meet peak power demand or as a reserve source of heat. All thehospital’s heating needs have been met by district heating since the autumn of 1999.Most of the individual dwellings which use district heating are in one of Oslo’s newerresidential areas, where each is equipped with district heating via an individual substa-tion, and energy consumption is also metered individually.

By replacing small oil-fired boilers, district heating helps to eliminate emissionsimmediately above roof level in residential areas and the city centre. This helps toimprove air quality in Oslo.

0100200300400500600700800900

10001 000

900

800

700

600

500

400

300

200

100

0

GW

h

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

Oil

Electric boilers

Biofuel

Heat pumps

Waste

Figure 3.10 District heating in Oslo 1986–2001

Source: KanEnergi

4

Figure 4.1 Legislation governing licensing in the hydropower sector

Watercourse Regulation Act

Watercourse Regulation Act

Water Resources Act

Water Resources Act

Energy Act

Industrial Concession Act

Power Plant

Consumer

Compensation for the Expropriation of Real Property Act

Licensing provisions

Provisions on expropration

4.1 Introduction

This chapter describes the legislative andpolitical framework for the power sector.Chapter 10 discusses water resource mana-gement in more detail.

A developer must have a licence pursu-ant to the Watercourse Regulation Act tocarry out regulatory measures or divertwater in a watercourse. This Act also givesthe licensee the authority to expropriate thenecessary property and rights in order tocarry out regulatory measures. The Indus-trial Concession Act specifies that anyonewho acquires ownership or user rights to awaterfall must obtain a licence. Develop-ment of a waterfall and construction of apower station usually require an additionallicence pursuant to the Water ResourcesAct. The Energy Act requires licensing ofall installations to generate, transmit anddistribute electricity, from power station toconsumer. A licence pursuant to the Ener-gy Act is also required to trade electricity.

The legislation mentioned above is ofparticular importance for the energy andwater resources sector. Other general pro-visions relevant to the sector are discussedlater in this chapter.

Figure 4.1 shows which legislation appli-es to the different parts of the Norwegian

hydropower system, from impoundingwater in a regulation reservoir in the moun-tains until electricity is delivered to the con-sumer.

4.2 Special legal framework forhydropower development

When a watercourse is used for hydropo-wer development, conflicts may arise bet-ween a number of user groups and environ-mental interests. It has therefore beennecessary for the authorities to developextensive legislation relating to hydropo-wer, which lays down requirements forobtaining licences for various purposes.The most important elements in the fram-ework for hydropower development are theprotection plans for water resources, theMaster Plan for Water Resources, theIndustrial Concession Act, the WatercourseRegulation Act and the Water ResourcesAct. The water resource authorities areresponsible for managing water resourceswithin this framework.

The licensing authorities are the bodiesresponsible for processing licence applicati-ons and for issuing licences. They includethe Storting, the government, the Ministry

49

4

of Petroleum and Energy and the Norwe-gian Water Resources and Energy Directo-rate (NVE).

In cases where a licence is required pur-suant to the Industrial Concession Act, theWatercourse Regulation Act or the WaterResources Act, the NVE is responsible forcoordinating application procedures. Oncea project has been approved in the MasterPlan for Watercourses, the actual applicati-on process starts when the developer sendsnotification of the project to the NVE. Thisnotification is deposited for public inspecti-on and circulated to local authorities andorganisations for comment.

The NVE, in consultation with the localauthorities concerned and other authoriti-es, then decides whether an environmentalimpact assessment (EIA) must be carriedout in accordance with the provisions of thePlanning and Building Act. Even if notifica-tion is not required pursuant to the Plan-ning and Building Act, the consequences ofthe project must be described in detail aspart of the licence application.

If notification is required pursuant to thePlanning and Building Act, the NVE willdetermine the final content of the study pro-gramme after submitting this to the Minis-try of the Environment. The authorities and

50

TILTAKSHAVER FAGDEP./NVE BERØRT MYND. OFFENTLIGHET

Melding Behandling Høring Høring evt.Off.møter

Høring

ForeleggesMD

KU-programfastsettes

HøringOff. møte

HøringBehandling

OED/

Ev. vassdrags-konsesjon

Ev. Stortings-behandling

Søknadreg. lov/E-lov

Konsekvens-utredning

Behandlingsøknader/KU

KU-godkj.

Helhetsvurd./sluttbehandl.

Regjeringen

Figure 4.2 Administrative procedures involved in licensing hydropower developments (more than40 GWh/year) which require an EIA pursuant to the Planning and Building Act

For major projects and projects which satisfy specific criteria, the first stage is always notification and an EIA pursuant to thePlanning and Building Act. Projects which do not require an EIA pursuant to the Planning and Building Act begin with a appli-cation pursuant to the Watercourse Regulation Act and an application pursuant to the Energy Act for licences for electricalinstallations in connection with the power station, including power lines for connection to the existing grid. If the project mustbe licensed pursuant to the Watercourse Regulation Act, an EIA pursuant to this Act is required. Administrative procedures forelectrical installations are shown in Figure 4.3.

ProcessingNotificationPublic

consultationPublic

consultation andmeetings

Application(Watercourse

RegulationAct/Energy Act)----------------------

EIA

Study programmedetermined

Submitted toMinistry of the

Enviroment

Public consultation andpublic meeting

Public consultation

Processing ofapplication/EIA----------------------Approval of envi-ronmental impact

statement----------------------

Overall evaluation/

final processingof application

Licence

Processing byMPE/

goverment

Public consulation

Storting debate

DEVELOPER MINISTRY/NVE* OTHER AUTHORITIES GENERAL PUBLIC

4

4.3 The Energy Act

The 1990 Energy Act establishes the orga-nisational framework for Norway’s powersupply system. It encourages competitionin power generation and trading. By meansof various licensing arrangements, the Actregulates the construction and operation ofelectrical installations, district heating sys-tems, electricity trading, control of mono-poly operations, foreign trade in power,metering, settlements and invoicing, thephysical market for trade in power, systemcoordination, rationing, electricity supplyquality, energy planning and contingencyplanning for power supplies. Together withcertain other statutes, the Energy Act alsoimplements the EU’s electricity directive(96/92). See chapter 9.1.1.

The authority to make decisions pursu-ant to the Energy Act has largely been dele-gated to the NVE. The most important

exception is that the Ministry of Petroleumand Energy has retained the authority toissue electricity export and import permits.

The Ministry of Petroleum and Energyis the appeals instance for decisions madeby the NVE pursuant to the Energy Act. Asa general rule, the Ministry will thereforeonly consider matters involving an appealagainst a licensing decision made by theNVE. The King in Council is the appealsinstance for matters dealt with in the firstinstance by the Ministry, such as exportand import licences.

4.3.1 Administrative procedures pur-suant to the Energy ActIf an EIA pursuant to the Planning and Buil-ding Act is required for a project, the sameprocedures are followed both for projectslicensed under the Energy Act and forthose licensed under legislation relating towater resources (see figure 4.2).

54

TILTAKSHAVER FAGDEP./NVE BERØRT MYND. OFFENTLIGHET

Søknadenergilov Behandling

søknad

Helhetsvurd./sluttbehandl.

Vedtak NVE

Høring Evt. Off. møte/befaring

HøringKlagebehandl.OED

Evt. Off. møte/befaring

Evt. konsesjonenergilov

Evt. Klage/

Beh. NVE

Figure 4.3 Administrative procedures for licensing electrical installations pursuant to the EnergyAct (power lines, gas-fired power stations, wind farms, etc)

This figure shows administrative procedures for licensing projects which come under the Energy Act, and the most importantdifferences from the procedures pursuant to the water resources legislation, see figure 4.2.

Application (Energy Act) Processing of

application----------------

Overall evaluation/final

processing ofapplication----------------

Decision by NVE*

Public consultation

Public meeting/inspection of site

Appeal/Processing by

NVE*

Licence issuedpursuant to Energy Act

Processing ofappeal (MPE)

Public consultation Public meeting/inspection of site

DEVELOPER MINISTRY/NVE* OTHER AUTHORITIES GENERAL PUBLIC

5

Central government ownership is mana-ged through the Statnett SF and StatkraftSF state enterprises. For a company to beorganised as a state enterprise, the govern-ment must be the sole owner. The differen-ces between state enterprises and limitedcompanies are otherwise not great.

More and more energy utilities arebeing organised as groups. This applies toalmost 48 per cent of all holders of tradinglicences. About 60 per cent of parent com-panies are themselves involved in activitieswhich require licences. The others are pureholding companies.

At 1 January 2004, 46 groups had a total of134 subsidiaries. Subsidiary companieswhich intend to engage in activities whichrequire a licence must hold their own tradinglicences. The formation of groups according-ly increases the number of licensees.

5.2 Organisation and restructu-ring of the power supply sector

5.2.1 OrganisationThe power supply sector is organised invarious ways around electricity generation,trading and transmission activities. Depen-ding on which activity is being pursued,companies can be designated as genera-

ting, grid or trading enterprises, vertically-integrated utilities or industrial under-takings. In some cases, they are describedcollectively as energy utilities. Companieshave also been established solely to negoti-ate power contracts.

Everyone supplying or trading electrici-ty must hold a trading licence. Figure 5.2shows the number of energy utilities whichheld such licences at 1 January 2004 bytheir type of activity. The overlapping cir-cles indicate how far such utilities are invol-ved in several types of activity. Seventy-sixare engaged in electricity generation, tra-ding, and grid management and operation,for instance, while 46 are only involved ingrid management and operation. A total of320 companies hold trading licences.

Figure 5.3 presents trends in the variousoperating categories during 1998-2003. Thisshows that the number of vertically-integra-ted utilities has declined, partly as a resultof mergers which have formed larger verti-cally-integrated companies. The number oflegal entities engaged solely in operationssubject to competition has been rising since1998, with the exception of 2001. For thefirst time, the number of such licensees in2003 exceeded the total for vertically-inte-grated companies.

62

Limited companies

Limited liability

Cooperative societies

General partnerships

Local authorities, countiesor interauthority companies

Other

Figure 5.1 Forms of company organisation


73%

7%

6%

8%

1%

5%

5

5.2.2 Restructuring the power industryIn response to the deregulation of the ener-gy sector in Europe, a substantial restructu-ring of the power industry is taking place inmost European countries, also across natio-nal borders.

Many local authorities and counties inNorway have sold holdings in power com-panies. At the same time, larger regional

power companies have been established,partly by acquisition and partly throughmergers. Examples are Lyse Energi, AgderEnergi, BKK and Skagerrak Energi.

Statkraft has acquired a stake in severallarge Norwegian power companies, and inSweden’s Sydkraft. Investment by Norwe-gian companies in other countries hasotherwise been limited.

63

Grid managementand operation

Trading

Generation

Figure 5.2 Companies holding trading licences by activity


Operations exposed to competition

Monopoly operations (grid)

Verticaly-integrated companies

Nu

mb

er o

f co

mp

anie

s

Figure 5.3 Trends in the various operation categories 1998–2003


5

5.2.2 Restructuring the power industryIn response to the deregulation of the ener-gy sector in Europe, a substantial restructu-ring of the power industry is taking place inmost European countries, also across natio-nal borders.

Many local authorities and counties inNorway have sold holdings in power com-panies. At the same time, larger regional

power companies have been established,partly by acquisition and partly throughmergers. Examples are Lyse Energi, AgderEnergi, BKK and Skagerrak Energi.

Statkraft has acquired a stake in severallarge Norwegian power companies, and inSweden’s Sydkraft. Investment by Norwe-gian companies in other countries hasotherwise been limited.

63

Grid managementand operation

Trading

Generation

Figure 5.2 Companies holding trading licences by activity


Operations exposed to competition

Monopoly operations (grid)

Verticaly-integrated companiesN

um

ber

of c

om

pan

ies

Figure 5.3 Trends in the various operation categories 1998–2003


6

The grids are drawn as circles to indicate that they form a meshed network. This means that if one line is inope-rative, power can be supplied to customers using other parts of the grids. G stands for generation.

Figure 6.1. The power supply system

Central grid Localgrid

Localgrid

Regionalgrid

G

G

G

6.1 Introduction

Generation, transmission and sales are thethree basic functions of the power supplysystem.

The transmission grid is often dividedinto three levels, as shown in Figure 6.1.The high-tension central grid constitutesthe “motorway system” for power supply,linking generators with consumers in vari-ous parts of the country. It also embracestransmission lines to other countries. Thecentral grid usually carries a voltage of300–420 kV, but certain parts of the countryhave lines carrying 132 kV. Regional gridslink the central and distribution grids. Mostenergy-intensive industries and generatingcompanies are connected to the regionaland central grids. Distribution grids aregenerally used to distribute power to endusers – private households, services andindustry. A distribution grid normally carri-es a voltage of up to 22 kV, but this is redu-ced to 220 V for supply to ordinary consu-mers. A number of small generating compa-nies are connected to the local distribution

grid. Power lines in the Norwegian grid,including overhead high- and low-voltagelines as well as underground and submari-ne cables, extend for roughly 300 000 km,or more than seven times the circumferen-ce of the Earth.

The construction of transmission gridsis costly, but the average cost per kWhtransmitted drops as the level of grid utilisa-tion rises until capacity comes under pres-sure. This means it is socio-economicallyinefficient to build parallel transmissionlines if the existing lines provide sufficientcapacity. Parallel lines may also result inundesirable land use patterns and be unne-cessarily intrusive. Grid management andoperation have therefore been defined as anatural monopoly, and this sector has notbeen opened to competition.

The 1990 Energy Act with subsequentamendments provides the legal basis forregulating grid management and operation(regulation of monopoly operations). TheEnergy Act is discussed in more detail inChapter 4.3.

69

6

Transmission tariffs for consumptionvary from one grid company to another.This is because natural conditions and thusthe cost of distributing electricity to thecustomer differ widely around the country.Both difficult natural conditions and a dis-persed settlement pattern can boost trans-mission costs. In addition, the efficiency ofgrid companies varies considerably. Ineffici-ent operation of the grid also contributes tohigh transmission costs and thereby to hig-her tariffs.

Private households are connected to thelowest voltage level in the distributiongrids. The transmission tariff or chargethey pay normally consists only of a fixedcomponent and an energy component.Figure 6.2 shows average transmissiontariffs for private households in each countyat 1 June 2004, including VAT but exclu-ding electricity tax. The figures are basedon an average annual electricity consumpti-on of 20 000 kWh. The average transmissi-

on tariff for a household consuming thatamount per year was NOK 0.303 per kWhat 1 January 2004, including VAT.

With effect from 1 January 2004, thegrid companies took over responsibility forcollecting the electricity tax through gridcharges. This job was previously dischar-ged by the electricity suppliers via theirinvoicing. The electricity tax has been set atNOK 0.0967 per KWh for 2004, and comesto NOK 0.12 per kWh when VAT is added.The change has not increased the total costto customers.

In order to reduce differences betweentransmission tariffs for end users in diffe-rent parts of the country, a new grant sys-tem was introduced in 2000. It is intendedto reduce transmission tariffs for end usersconnected to distribution grids in parts ofthe country with the highest transmissioncosts. Funds are transferred to the appro-priate grid companies, which are thenrequired to reduce their tariffs.

73

County overview of transmission tariffs for households – national average

Weighted national average

NO

K/k

Wh

Figure 6.2 Transmission tariffs for private households at 1 June 2004, converted to a consumptionof 20 000 kWh per year and shown in NOK per kWh.


7party to all contracts traded on the powerexchange. In addition, Nord Pool Clearingoffers clearing of standardised contracts tra-ded off the exchange.

Nord Pool turnover in 2003Activity was reduced in Nord Pool’s mar-kets during 2003, primarily as a result ofthe tightness of electricity supplies in theearly part of that year.

The volume traded in the physical mar-ket declined by about five per cent from2002 to 2003. Traded volumes for 2003 and2002 were 119 and 124 TWh respectively.On the other hand, the value of traded volu-mes in the physical market rose by about34 per cent over the same period to reachabout NOK 36 billion in 2003. This valueincrease reflected higher spot pricesthroughout the year.

A decline of about 46 per cent in tradedvolume from 2002 to 2003 was registeredby the financial market. Trade volumestotalled 545 and 1 019 TWh in 2003 and

2002 respectively. The value of this volumedeclined from NOK 180 billion in 2002 toNOK 139 billion in 2003.

Clearing of both bilateral trades and inthe financial market has increased substan-tially over recent years, but declined byabout 43 per cent in 2003 compared withthe year before. It amounted to 1 764 and 3108 TWh in 2003 and 2002 respectively, cor-responding to NOK 369 billion and NOK434 billion.

7.2.2 Managing bottlenecks in thegrid

Nord Pool Spot sets a system price for eachhour which takes no account of any trans-mission restrictions in the Nordic grid.However, such restrictions may arise bet-ween geographical areas.

Restrictions in the Nordic transmissiongrid, often termed bottlenecks, are mana-ged by specifying price areas on either sideof the bottleneck. Nord Pool determinessuch price areas in addition to the system

79

Figure 7.1 Developments in the physical and financial markets and in clearing since 1996.

Source: Nord Pool

TWh

Physical market

Financial market

Clearing bilateral trading and financial market

3 000

2 800

2 600

2 400

2 200

2 000

1 800

1 600

1 400

1 200

1 000

800

600

400

200

0

7All end users must pay a transmission

tariff to the local grid company to whichthey are connected. See chapter 6.2.2. Iftransmission and electricity supply arehandled by different companies which arenot members of the same group, the enduser will normally receive two invoices -one from the grid company and one fromthe electricity supplier. However, most endusers buy their power from a company or agroup which embraces both functions.They usually therefore receive only oneinvoice which specifies the transmissiontariff and electricity price as separate items.

The electricity tax is charged on powerregardless of whether the latter is genera-ted domestically or imported, and stood atNOK 0.967 per kWh in 2004. See the pre-sentation of taxes and fees in chapter 2.5.

Large customers normally have meterswhich measure electricity use by the hour,so that a precise settlement can be made.Smaller consumers receive invoices based

on a predetermined load profile, but can optto be metered by the hour.

Household customers can also choosebetween different types of contracts for pur-chasing electricity. The commonest kind isbased on a variable price, which means thatthe supplier can change the price after noti-fying the customer. In the first quarter of2004, 67.5 per cent of all households hadsuch contracts. Elspot-based contracts,such as ones which charge the Elspot priceplus a fixed mark-up, were held by 10.7 percent. The remaining household customershad various types of fixed-price contracts. Afixed price, for example for one year, meansthat the supplier cannot alter the priceduring the contract period, even if marketprices change. The percentage of house-holds with such contracts has increased inrecent years, largely as a result of electrici-ty price developments in the winter of2002–03, and stood at 28.1 per cent in thefirst quarter of 2004.

81

Figure 7.2 Electricity prices for households 1985–2003. NOK per kWh in fixed 2003 NOK


Transmission tarrifs

Electricity prices

Total with taxes

Total without taxes

NO

K/k

Wh

7

Some 24 per cent of household custo-mers, including cabins and holiday homes,had a different electricity supplier than themain one for their area in the fourth quarterof 2003.

Figure 7.2 shows trends in average pri-ces for households from 1985 to 2003. Theelectricity price and transmission tariff wereseparated in 1993. The figure also shows thetotal end user price, including VAT and elec-tricity tax. Prices for private householdswere relatively stable from 1986 to 2001.However, the cold winter in 1995-1996,combined with low inflow in 1996, resultedin a sharp rise in wholesale prices which ledin turn to an increase in prices charged tohouseholds. These accordingly rose from1996 to 1997. Precipitation was above normalfor every year in the 1997-2000 period, withrelatively high hydropower output. This wasreflected in a general decline in prices overthe whole period. Inflow to the reservoirsdeclined substantially in the winter of 2002-03. This led to a considerable rise in house-hold prices for many consumers. See appen-dix 2 on the 2002–03 dry year.

7.3 Price formation Norwegian electricity prices are determi-ned by supply and demand in the Nordicpower market and to some extent by themarket balance in countries outside thisregion. Figure 7.3 provides a simplified out-line of how electricity generating costs inthe Nordic region influence electricity pri-ces. The rising curve shows the availabilityof power capacity in the Nordic region asshort-term generating costs rise. The fallingcurve shows the demand for power in theNordic region. Generating costs are lowestfor hydropower and nuclear energy. Preci-pitation and inflow to reservoirs determinehow much hydropower can be generated,and are therefore also important for theoverall output potential and for prices.Generating costs are higher at thermalpower facilities, such as coal- and gas-firedstations. Given the current level of demand,coal-based facilities often serve as the swinggenerator to balance the market, and there-fore determine the price. In a year with ave-rage hydropower output, electricity priceswill therefore be largely determined by the

82

øre/kWh Etterspørsel

Tilbud

TWh

Figure 7.3 Principles for short-term variable costs of power generation in the Nordic region

Source: Ministry of Petroleum and Energy

TWh

SupplyDemandNOK/kWh

7

cost of generating electricity from coal. Inperiods of increased demand, power stati-ons with higher generating costs – such asoil condensate or pure gas turbine units –will determine the price. These peak-loadstations are used only to generate electrici-ty for short periods at a time. In Figure 7.3,they would lie on the steeply rising part ofthe supply curve. Temperature and generaleconomic activity are among the factorswhich help to determine demand.

Figure 7.4 shows variations in the nomi-nal Elspot price for 1992–04.

7.4 International power trading

Norway was traditionally a net exporter ofpower. But it has been a net importer sincethe late 1990s because consumption contin-ues to rise while hydropower developmenthas been limited in recent times. In certainyears, however, high precipitation andinflow to reservoirs mean that the hydropo-wer utilities can help exports to exceedimports. Net Norwegian power exports in

2002 totalled 9.7 TWh, for instance, whilenet imports came to 7.8 TWh in the follo-wing year. Figure 7.5 shows imports andexports of power by Norway from 1970 to2003.

International power trading is determi-ned by generating and consumption pat-terns in each country, in addition to thecapacity of the transmission grid linkingcountries and the conditions for its use.One basis for power trading is the opportu-nities it offers countries to derive mutualbenefit from differences in national genera-ting systems.

Exchanging power in this way is impor-tant for Norway because it reduces thecountry’s vulnerability to variations in preci-pitation and inflow and makes use of theregulatory capacity of hydropower. Goodopportunities for power exchange moderatethe need to maintain a large domestic reser-ve capacity as an insurance against dryyears.

Most of the countries with connectionsto Norway base their power output largelyon thermal sources – coal, oil, gas and

83

Figure 7.4 Prices in Nord Pool’s spot market 1992–2004

Source: Nord Pool

NO

K/k

Wh

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

7

nuclear. This normally ensures stable ener-gy supplies. The opportunity to import elec-tricity in dry years provides a reserve forthe Norwegian system. In years when waterinflow is good, the transmission grids makeit possible to export power from Norway. Inthis way, opportunities for power exchangewill damp down price fluctuations in theNorwegian energy supply system. In a clo-sed Norwegian system, electricity priceswould be much more sensitive to variationsin climate.

Power exchange between Norway andother countries exploits the advantages ofinterconnecting hydro and thermal powersystems. In countries based on thermalsources, power station capacity determineshow much electricity can be generated,while the limiting factor in Norway today isthe amount of energy available in the formof water in reservoirs. The energy sourcesused in thermal power countries – oil, coal,natural gas and uranium – can generally beacquired in whatever quantities are neededand accordingly impose no restrictions onoutput.

Building new thermal capacity to meetshort-term peaks in demand in countries

with thermal-based systems is expensive,and adjusting output up and down in exis-ting generating facilities is both time-consu-ming and costly. But thermal power stati-ons can deliver relatively inexpensive elec-tricity outside peak consumption periods –in other words, at night and on weekends.

Capacity in Norway’s hydropower stati-ons exceeds the level normally required tomeet domestic daytime consumption. Out-put from such facilities can be adjusted upand down rapidly and at low cost to meetfluctuations in consumption or unexpectedshort-term changes in power supplies.

Interconnecting a hydropower-basedsystem with ones based on thermal poweralso makes it possible to reduce the needfor new power stations and multi-annualreservoirs in Norway. When the Norwegianelectricity price rises sufficiently above themarginal cost of thermal power output, itbecomes profitable for neighbouring coun-tries to export to Norway. Conversely, it isprofitable for Norway to export power whenthe price at home is lower than in neigh-bouring countries.

Norway has transmission connectionswith Sweden, Denmark, Finland and Rus-

84

Figure 7.5 Norway’s imports and exports of power in 1970–2003

Source: Ministry of Petroleum and Energy

TWh

Imports Exports

2003

108

The drop in inflow led to a substantial decli-ne in hydropower output. For the Nordicregion as a whole, this was about 96 TWh inthe second half of 2002 – roughly sevenTWh lower than in the same period of theyear before. Hydropower output in the firsthalf of 2003 was only 84 TWh, about 26 TWhbelow the same period of 2002.

Big adjustments in the Nordic markethelped to reduce the impact of the inflowdecline. These occurred without govern-ment intervention to deal with the position.

Four factors in particular were significant:• hydropower reservoirs were very impor-

tant as buffers between output and con-sumption

• spare thermal generating capacity inother Nordic countries was eventuallytaken into use

• electricity imports from countries outsidethe Nordic region eventually became sub-stantial

• consumption of electricity declined, parti-cularly because of a shift to other energycarriers.

The loss of hydropower output was off-

set to a great extent by increasing thermalpower generation. Nordic oil-, gas- and coal-fired electricity output in the second half of2002 totalled 45 TWh, about nine TWh hig-her than in the same period of the yearbefore. These power sources accounted forabout 57 TWh in the first half of 2003, up by18 TWh from the same period of 2002.Nuclear energy output in the autumn andwinter of 2002-03 was roughly unchangedfrom the previous winter.

Net Nordic electricity imports increasedgradually from the summer of 2002 untilthe end of the year, and totalled 4.6 TWhfor the second half of 2002. This figurecame to 10.2 TWh in the first half of 2003,as opposed to 0.8 TWh in the first half ofthe year before. Russia was a particularsource of these Nordic imports.

Norway’s net exports were high untilthe beginning of October 2002, when theybegan to decline gradually. But the countryremained a net exporter until the beginningof December. Throughout the winter andspring of 2003, net Norwegian electricityimports were substantial. Purchases fromabroad were particularly high from mid-

Appendix 2

Figure 1 Inflow August–December 1931–2002

Norway Sweden

Appendix 2

March until the beginning of May. Thepower exchange fluctuated between netimports and exports during the summer of2003. Taken as a whole, Norway had highnet exports of more than six TWh in thesecond half of 2002. This was reversed tonet imports on a corresponding scaleduring the first half of 2003.

Electricity prices reached very highlevels as a result of the tightness of thepower market, adding to costs for Norwe-gian industry and householders in the win-ter of 2002-03. Electricity bills became avery burdensome expense for some.

The spot price for electricity in 2002 ave-raged NOK 0.201 per kWh, but varied con-siderably over the year. Power prices werelow during the first half, but the gradualtightening of supply during the second sixmonths eventually yielded substantial incre-ases. Towards the end of the year, pricesrose sharply over a very short period. From30 November 2002 to 31 January 2003, theNordic power market was characterised byhigh and fluctuating electricity prices. Theaverage daily spot price ranged in this peri-od from about NOK 0.5 per kWh to roughly

NOK 0.8 per kWh. At its peak, the averagedaily price reached NOK 0.831 per kWh.Prices also remained high during January2003, when the electricity spot price avera-ged NOK 0.524 per kWh. And prices in therest of the winter and spring of 2003 remai-ned far above the normal level for recentyears. The average price in the first half of2003 was NOK 0.317 per kWh.

Nordic electricity consumption was twoper cent higher in the second half of 2002than in the same period of the year before.During the first half of 2003, it was 0.5 percent lower than in the first six months of2002. Total Nordic consumption from July2002 to June 2003 came to 388 TWh, anincrease of 0.7 per cent from the preceding12-month period. The growth in consumpti-on was highest in Finland, while Swedenand Denmark experienced a modest increa-se and Norway showed a decline.

Total electricity consumption in thesecond half of 2002 was roughly on a parwith the same period of the year before.During the first half of 2003, it was lowerthan in January-June 2002. A particulardecline in consumption compared with the

Figure 2 Reservoir levels, Nordic region

2002

2003

Minimum (1990–99)

Median (1990–99)

Maximum (1990–99)

Jan Feb Mar Apr May Jun Jul Aug Sept Oct

Per

cen

t

109

110

Appendix 2

Jul–Dec

Jan–Jun

Jul–Dec

Jan–Jun

Hydropower

Norway Denmark Sweden Finland

Jul–Dec

Jan–Jun

Jul–Dec

Jan–Jun

Oil-, gas- and coal-fired

Jul–Dec

Jan–Jun

Jul–Dec

Jan–Jun

Nuclear

Figure 4 Spot prices for electricity, Nord Pool

2003

Jan Feb Mar Apr May Jun

2002

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

OsloTromsøSwedenFinlandWest DenmarkSystem

NO

K/k

Wh

previous year was recorded from January toApril 2003. Total consumption for the firsthalf of 2003 was about four TWh lower thanin the same period of 2002. A particulardecline was recorded for power-intensiveindustry and electrical boilers.

Gross domestic consumption of electri-city over the 12 months from July 2002 toJune 2003 totalled 117 TWh, a decline of 3.8TWh or roughly three per cent from theprevious 12-month period.

The inflow decline put the Nordic powermarket to a hard test. A well-functioningpower market helped Norway to emergefrom the winter of 2002–03 without a supplycrisis. The power system accordingly mana-ged to cover an unusually dry autumn. Esti-mates indicate that conditions of this kindwill recur every 100-200 years in Norway,50–100 years in Sweden and 100–200 yearsfor these two countries combined.

Figure 3 Composition of Nordic power generation, July 2001–June 2003

Transmission capacity in the Nordic region (MW)

NORWAY

SWEDEN

DENMARK

FINLAND

POLAND

GERMANYNETHERLANDS

RUSSIA

Total of existing lines

Total of planned lines

Total of existing submarine cables

Appendix 3

111

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