Select Committee on Trade and Industry Second Report


GLOSSARY OF TERMS IN ENERGY SYSTEMS

Access Charge   

A charge for a power supplier, or its customer, for access to a Utility's transmission or distribution system. It is a charge for the right to send electricity over another's wires.

AGR       

Advanced gas-cooled reactor, a British design of nuclear reactor

Aggregation   

The process of organising small groups, businesses or residential customer into a larger, more effective bargaining unit that strengthens their purchasing power with utilities.

Ampere     

Unit that measures electrical current in a circuit

Base Load     

The minimum load experienced by an electric Utility system over a given period of time.

Base Load Unit   

A generating unit that normally operates at a constant output to take all or part of the base load of a system.

Baseload Capacity

Generating equipment operated to serve loads 24 hours per day.

Bilateral Contract

A direct contract between the power producer and user or broker outside of a centralised power pool.

Biomass     

Plant materials and animal waste used as a source of fuel.

Capacitor     

This is a device that helps improve the efficiency of the flow of electricity through distribution lines by reducing energy losses. It is installed in substations and on poles. Usually it is installed to correct an unwanted condition in an electrical system

Capacity     

The maximum load a generating unit, generating station, or other electrical apparatus is rated to carry by the user or the manufacturer or can actually carry under existing service conditions.

Capacity Charge   

An assessment on the amount of capacity being purchased.

Cogeneration   

Production of heat energy and electrical or mechanical power from the same fuel in the same facility. A typical cogeneration facility produces electricity and steam for industrial process use.

Combined Cycle   

Similar to the combustion turbine simple cycle, but includes a heat recovery steam generator that extracts heat from the combustion turbine exhaust flow to produce steam. This steam in turn powers a steam turbine engine.

Combined Cycle Plant

An electric generating station that uses waste heat from its gas turbines to produce steam for conventional steam turbines.

Decommissioning   

The process of removing a nuclear reactor from service and dismantling.

Dispatchability   

This is the ability of a generating unit to increase or decrease generation, or to be brought on line or shut down at the request of a Utility's system operator.

Distributed Generation

A distributed generation system involves small amounts of generation located on a Utility's distribution system for the purpose of meeting local (substation level) peak loads and/or displacing the need to build additional (or upgrade) local distribution lines.

Distribution     

The system of wires, switches, and transformers that serve neighbourhoods and business, typically lower than 69,000 volts. A distribution system reduces or downgrades power from high voltage transmission lines to a level that can be used in homes or businesses.

Distribution Line   

This is a line or system for distributing power from a transmission system to a customer. It is any line operating at less than 69,000 volts.

Distribution Network Operator (DNO)

Refers to the regulated owner/operator of the distribution system which serves retail customers.

Distribution System

That part of the electric system that delivers electric energy to consumers.

Forced Outage   

An outage that results from emergency conditions and requires a component to be taken out of service automatically or as soon as switching operations can be performed. The forced outage can be caused by improper operation of equipment or by human error. If it is possible to defer the outage, the outage becomes a scheduled outage.

Fuel cell     

A device that converts energy from chemical reactions directly into electrical energy. The simplest fuel cell 'burns' hydrogen in a flameless chemical reaction to produce electricity. In order to 'burn' the hydrogen a fuel cell needs a source of oxygen and this is usually obtained from air. The only by-product from this type of fuel cell is water.

Gasification     

A process that exposes a solid fuel to heat in the presence of limited oxygen to produce a gaseous fuel. This fuel contains hydrogen but also other gases such as carbon monoxide, carbon dioxide, nitrogen, and methane. Under suitable circumstances, gasification can produce synthesis gas, a mixture of just hydrogen and carbon monoxide.

Gigawatt     

This is a unit of electric power equal to one billion watts, or one thousand megawatts enough power to supply the needs of a medium sized city.

Grid Operator

Refers to the regulated owner/operator of the transmission system only.

Intermittent Resources

Resources whose output depends on some other factor that cannot be controlled by the Utility e.g. wind or sun. Thus, the capacity varies by day and by hour.

Interruptible Power

This refers to power whose delivery can be curtailed by the supplier, usually under some sort of agreement by the parties involved.

Interruptible Rates

These provide power at a lower rate to large industrial and commercial customers who agree to reduce their electricity use in times of peak demand.

Kilowatt (kW)

The electrical unit of power equal to 1,000 watts.

Kilowatt-Hour (kWh)

The basic unit of electric energy equal to one kilowatt of power supplied to or taken from an electric circuit for one hour.

Losses       

The general term applied to energy (kWh) and capacity (kW) lost in the operation of an electric system. Losses occur principally as energy transformations from kWh to waste heat in electrical conductors and apparatus. This power expended without accomplishing useful work occurs primarily on the transmission and distribution system.

Magnox     

Early British type of reactor so-called after its magnesium alloy fuel cans.

Megawatt     

One million watts.

Megawatt hour (MWh)

One thousand kilowatt-hours or one million watt hours.

Municipal Solid Waste

A Biomass resource that can be used to produce energy by the process of incineration.

Non Dispatchable

This refers to non-predictable energy sources, where there is little or no ability of a generating unit to increase or decrease generation, or to be brought on line or shut down at the request of a Utility's system operator.

Ofgem     

Office of the electricity and gas regulator (markets).

Outage   

Time during which service is unavailable from a generating unit, transmission line, or other facility.

PWR     

Pressurised water reactor.

Photovoltaic (PV) cells.

(Also known as solar cells.) A photovoltaic cell is made of thin wafers of two slightly different types of silicon, which, when exposed to light, will produce an electric current. Photovoltaic cells thus convert light energy into electrical energy.

Pyrolysis   

A process which involves heating biomass to drive off the volatile matter, leaving behind the black residue we know as charcoal. More sophisticated pyrolysis techniques have been developed recently to collect volatile gaseous compounds that are otherwise lost to the system. The collected volatiles produce a gas rich in hydrogen and carbon monoxide.

Renewable Energy

Energy that is capable of being renewed by the natural ecological cycle.

Reserve Capacity

Capacity in excess of that required to carry peak load.

Reserve Generating Capacity

The amount of power that can be produced at a given point in time by generating units that are kept available in case of special need. This capacity may be used when unusually high power demand occurs, or when other generating units are offline for maintenance, repair or refuelling.

Spinning Reserve   

Reserve generating capacity running at zero load.

Standby Facility   

A facility that supports a system and generally running under no load.

Terawatt    

A million million watts.

Transformer   

A device for changing the voltage of alternating current.

Transmission and Distribution (T&D) Losses

Losses in energy between the generation facility and the customer.

Transmission and Distribution (T&D) System

An interconnected group of electric transmission lines and associated equipment for the movement or transfer or electric energy in bulk between points of supply and points at which it is transformed for delivery to the ultimate customers.

Volt     

A unit of electrical pressure. It measures the force or push of electricity. Volts represent pressure, correspondent to the pressure of water in a pipe.

  

Volt-amperes  

The volt-amperes of an electric circuit are the mathematical products of the volts and amperes of the client.

Waste-to-Energy

This is a technology that uses refuse to generate electricity. In mass burn plants, untreated waste is burned to produce steam, which is used to drive a steam turbine generator. In refuse derived fuel plants, refuse is pre-treated, partially to enhance its energy content prior to burning.

Watt     

The basic unit of power (the rate at which energy is used) in the metric system is the watt (W); a kilowatt is 1000 watts. A watt is a very small amount of power and in most mechanical applications we count power in kilowatts. A car engine typically produces 50 to 100 kilowatts. One horsepower is equivalent to approximately 746 watts.

Watt-Hour   

One watt of power expended for one hour.

Wholesale Power Market

The purchase and sale of electricity from generators to resellers (who sell to retail customers) along with the ancillary services needed to maintain reliability and power quality at the transmission level.

The UK Gas Industry in the Long-term: and the Liberalisation of European Markets

An alternative analysis by Professor PR Odell

A  Introduction

1  This note seeks to clarify some of the issues in this Report relating to the future of natural gas, in general, and to paragraphs 91-96 on the liberalisation of European gas markets, in particular. The Report argues that "there is considerable uncertainty about gas imports in the long-term" (para 91) and that the UK's security of energy supply would best be achieved if left to market forces and that these "would not operate effectively without greater liberalisation of continental European markets". (para 92)

2  As gas reserves/ resources potentially available for use in Europe (including the UK) constitute about 70% of the global total, while Europe is responsible for only 18% of current world use — with this share more likely to decrease than to increase over the next 20 years — there can be no uncertainty over supply per se. Potential suppliers are, indeed, gathered around Europe like proverbial "wasps around the jam jar", containing, in this case, high value gas markets and a set of consumers ready, willing and able to pay for the commodity in steadily increasing volumes.

3  Presumably, therefore, the "uncertainties" to which the Report refers must be related specifically to the questions of how soon and how much the UK will need to import — and from which specific sources of supply such requirements can be most securely and cheaply obtained?

B  The UK's future gas import needs will be limited

4  The Minister of State for Energy has suggested that the UK is likely to be up to 50% dependent on gas imports by 2010 and some 90% dependent by 2020. These forecasts emerge, however, from inappropriate values attached, first, to gas demand developments; and second, to UK gas production potential.

5  According to the PIU Scoping Note the rate of expansion of UK energy demand will be of the order of 2% per annum, viz from 226 million tons oil equivalent in 2000 to 275 million tons in 2010 and 335 million tons in 2020. In reality, this has a very low probability of being achieved. Even with a continuation of the very modest energy conservation and efficiency efforts to date, it seems unlikely that incremental energy demand over the next 20 years will be almost five times that of the last 20 years (viz 110 mtoe compares with 23 mtoe). Given energy use objectives which are now orientated much more strongly to demand constraints, the probability of such future levels of energy use is close to zero.

6  It is much more realistic to predicate that future demand growth will continue to expand at no more than the 0.5% rate of the past 20 years; to about 238 mtoe in 2010 and just over 250 mtoe in 2020. Within this framework, certain or planned supplies of oil, coal, nuclear and renewables will deliver some 138 mtoe by 2010 and 145 by 2020, thus indicating a demand for gas of about 110 Bcm in 2010; and about 115 Bcm by 2020. Gas demand in 2000 was 96 Bcm (with indigenous production significantly higher at 108 Bcm, indicating a net export from the UK of about 12 Bcm).

7  Even if indigenous gas production were to fall dramatically from its present level — to some 82 Bcm in 2010 and to 58 Bcm by 2020 (that is, by roughly the decline expected by UKOOA from the depletion of presently discovered reserves), then net import requirements for gas would be only 28Bcm in 2010 and 58 Bcm in 2020 (= 25% of gas demand in 2010 and 50% in 2020). Additional recoverable reserves of UKCS gas are, in the meantime, however, virtually certain to emerge from re-evaluated fields and from new discoveries — as a consequence of the industry's intensified efforts to achieve such an objective — based on the DTI's current mid-range estimate of 2100 Bcm of remaining discoverable gas. In the absence of adverse regulatory constraints on the industry's propensity to invest, production will be some 25 Bcm per year greater than the 82 Bcm and 58 Bcm in 2010 and 2020, respectively (as indicated above). Thus, the UK's net gas import needs could fall to near zero in 2010 and to no more than 33 Bcm in 2020.

C  An Accord with Norway will solve the "problem".

8  The security of UK gas supply for the next 20 years is thus at worst an issue of relatively minor dimensions: at best, it will be non-existent. In any case, net imports sufficient to meet the reasoned estimated shortfall can be virtually guaranteed from the exploitation of the massive additional gas reserves of Norway. In 2000, Norway exported 49 Bcm (all to mainland European countries). An additional 20 Bcm per year are already contracted, largely to the same set of purchasers, for delivery by 2004/5. Thereafter, however, another 50 Bcm per year are predicated for development, but with most of this gas not yet contracted for sale: though note that BP has already negotiated modest purchases for delivery to the UK from 2004 for a 25 year period under take-or-pay conditions.

9  Technical discussions between the UK and Norwegian authorities on possible joint developments have already been scheduled for the very near future (possibly by March this year). These preliminary moves need to be expanded into a major Anglo- Norwegian politico-economic agreement, whereby the best interests of both countries can be achieved. This would seek to ensure a maximised net-back value at the well-head from Norway's large potential additional production, on the one hand; and, for the UK, guaranteed volumes of required imports of new Norwegian gas, plus benefits from a joint venture for the transit of the remaining gas via the UK to the mainland of Europe. Ironically, the principal barrier to such a mutually beneficial agreement for the two countries could well be the incompatibility of OFGEM's stance on "competitive" pricing for gas delivered to the UK, with Norway's preference for long-term take-or-pay contracts whereby the high levels of investments for the large-scale gas production in its Northern waters can be justified.

D  Other "guaranteed" sources.

10  In the context of such an Anglo-Norwegian accord, the UK's needs for gas imports from other sources would thus be minimised — or even eliminated, except for seasonal requirements for high winter demand. Such relatively minor import volumes will be readily available — albeit at higher prices, given the seasonality of demand — from alternative sources. Either as pipelined imports from the Netherlands, where significant seasonal flexibility of supply is built into its gas production, transport and storage systems, and for which more than adequate capacity for moving the gas to the UK through the inter-connector from Zeebrugge (currently being expanded to handle 24 Bcm of gas per year) will be in place. Or as LNG imports (to terminals with relatively short lead-times for development) from an increasing number of possible suppliers within relatively short sea distances from the UK, viz, Algeria, Egypt, Nigeria, Trinidad, Venezuela and even Norway's Barents Sea Snøvit field, currently under development as an LNG export facility.

E   The UK and the non-liberalised mainland European gas industry

11  In the demand/ supply prospects as set out above, the UK seems unlikely to be required to depend much, if at all, prior to 2020 on any other external suppliers of gas to Europe, viz Russia and Algeria as existing suppliers or Libya, Turkmenistan and Iran as potential suppliers before 2020. Under such conditions, the concerns expressed in this Report and elsewhere (notably the PIU scoping note) for the slow process of gas liberalisation in most other EU member countries is misplaced. The UK's demands on the use of the transmission system already in place will be minuscule in the context of the system's existing capacity to move some 300 Bcm of gas per year from the exporting to the importing countries. The UK's suppliers lack of guaranteed third-party access rights to the system and the absence of price transparency would, at worst, thus be a minor inconvenience.

12  Meanwhile, the mainland European gas transmission system is not only being increasingly reticulated and geographically extended, it is also being opened up to regulated or negotiated third-party access — with published tariffs — in ways which suit the needs of both exporting and importing countries.

13  The antecedents to the evolution of the mainland gas transmission network and the trading mechanisms for the gas itself have been very different from those that have emerged in the UK (following the UK's decision in 1972 not to allow gas exports to the rest of Europe and thus preventing integration). While supply-side competition for gas in the UK did not effectively emerge until the early 1990s, competition between the suppliers of gas to mainland European markets started as early as 1971 (with the entry of Russian gas to the market). By 1990 this competition had become so intense that prices dipped well below crude oil equivalents and enabled European consumers (in all sectors except residential in which UK prices were held to an artificially low level through government intervention) to enjoy much lower (pre-tax) prices. This situation persisted until as recently as 1999, when European pre-tax prices generally rose above those in the UK as a consequence of the strong upward price movements of crude oil. But UK consumers' new-found price advantages from that situation have already proved very temporary, so that differentials have largely disappeared.

14  Meanwhile, moreover, the generally high downstream profits in gas distribution in most mainland European countries — arising from monopolistic conditions — are now being brought under severe downward pressure through governments'- induced interventions requiring structural changes in the national systems — though not necessarily in the highly-regulated "laissez-faire" manner chosen to ensure price reductions in the UK. This UK approach is very widely non-acceptable in many other European countries in the context of a continuing belief in the public service nature of the gas (and electricity) supply industries, often under municipal control; with gas and electricity revenues used to subsidise other public sector services. This constraint on UK-style liberalisation remains highly pertinent.

15   There is a yet more significant constraint on the ability and willingness of other EU countries to switch their gas purchasing arrangements from long-term take-or-pay contracts to short-term trading. This reflects these countries' status already as major gas importers -- and as even more import-dependent gas users in the future. (Only Denmark and the Netherlands are self-sufficient). Their 'dash-to-gas' has hardly begun, with gas still accounting for only 19% of total energy used (compared with 38% in the UK): by 2010 gas dependence is expected to increase to about 24% and by 2020 to 30%, involving 315 Bcm of gas imports in 2010 and 390 Bcm in 2020. Given these expectations, guaranteed long-term arrangements for imported supplies are of the essence and it may be assumed that they will continue, irrespective of what are seen as the irresponsible demands of the EU's Competition Directorate for a switch to short-term competitive markets.

F  The views and requirements of the countries exporting gas to Europe

16  The gas importing countries' motivations for the continuation of long-term contracts for gas imports are already powerful enough to ensure the sustenance of the 30 year old system, except for minor changes relating to joint sales (as by the Norwegian GSU), destination clauses and resale procedures. The importers' concerns are, however, greatly strengthened by the views and requirements of the external suppliers -- most notably Russia and Algeria, but also involving both Norway and also potential new suppliers, all of which have participated in recent gas suppliers' summits. At these meetings exporters expressed their 'indignation' at the EU's attempts to undermine the supply system on grounds of 'restraints on trade' -- even to the extent of declaring existing contracts as unacceptable under EU competition law.

17  The exporters argue that ending long-term take-or-pay contracts will mean that both volumetric and pricing risks will be moved to the producer, compared with the current sharing of those risks between exporters and importers (with the latter guaranteeing volumes). Liberalisation, the exporters say, does not take account of their needs and, moreover, they have not been consulted on the changes. Gazprom summarised the evolving situation as one in which it would be unable to conclude new contracts. Both Gaz de France (given France's 90% dependence on imports now and over 95% by 2010) and Ruhrgas (given Germany's 80% import dependence) are giving strong support to the exporters' arguments.

18   The French, German and other countries' concern for the adverse impact of liberalisation on prospects for gas supply and price is taken even further by their fears that the alienation and provocation of the external suppliers of gas to Europe will lead to the creation of a formal oligopoly of suppliers (viz. An Organisation of Gas Exporters to Europe -- OGEE) through which supply constraints and consequential higher prices will be the end result -- to the disadvantage of all gas users in Europe (note that neither Russia nor Algeria -- nor Libya, Egypt and Iran -- have signed and/or ratified the European Energy Charter which requires a free-trading regime).

19  In light of such formidable opposition to gas trade liberalisation it is not very surprising that a mid-2001 ruling by the EU that a 'prioritised' infrastructure-connector for electricity between Germany and Poland involves such a large investment that those investing need 25 years of exclusive rights to use the line (in order fully to cover their costs) and that this requirement should 'supercede competition issues'. This appears to establish a precedent for treating infrastructural connectors for gas movements between states in a like manner. Coincidentally, an EU Report on Energy Infrastructure has recently been published and has designated a set of five prioritised requirements for the gas industry. These include the connection of networks between the UK, Netherlands, Germany and Russia; likewise, between Algeria, Spain and France; underground gas storage construction in Spain, Portugal and Germany; and the development of pipeline systems between the EU and both the Middle East and the Caspian basin (plus LNG facilities in France, Spain, Portugal and Italy) with the collective object of guaranteeing at least 20% of peak daily demand for all parts of the EU. Should such EU-prioritised gas infrastructure developments be given exemption from competition rules -- through the protection of investments made in the facilities against 'required' TPA for 25 years, then gas market liberalisation objectives would be well and truly thwarted for the whole of the period to 2020.

G  Optimal Policy for the UK

20  Given the prospect outlined above, then the development of the UK's gas industry would seem likely to be best effected by a combination of maximum efforts to maintain the volumes of indigenous production (as suggested above in para 7); by an accord with Norway to make-up most of any shortfall in the context of a broad, mutually beneficial agreement (paras 8 and 9 above); and by the development of LNG peak sharing facilities (para 10). The use of the interconnector with the European mainland would remain as an optional (emergency) extra.

21  None of these proposals should create any great concern as to their practicality: and neither in respect of the level of costs involved. In the context, that is, of realistic forecasts of future levels of energy demand, in general, and of gas demand, in particular (as argued in paras 6 and 7).

22  The UK's security of gas supply for the next two decades is certainly not a problem of accessing large volumes of gas from distant sources, separated from the UK by many intervening complexities. On the contrary, supply security is, in essence, a matter of good and mutually beneficial relations with Norway as a complement to the establishment of a number of nationally achievable aims, viz much higher efficiencies in gas use, especially in the domestic sector (responsible for one-third of total consumption) through measures including fiscal ones; favourable policies for maximising indigenous gas exploration and exploitation; and the abolition of regulatory practices which undermine investments in gas production, new terminals and extended transmission systems -- with particular, but not exclusive, reference to the UK as a transit country for large volumes of Norwegian gas en route to mainland Europe.

Notes on Combined Heat and Power (CHP) by Professor Bert Whittington

Definition

All fossil-fuelled electrical generating equipment is less than 100% efficient. The proportion of the energy in the input fuel which is not converted to electricity is discharged as waste heat - more than half the energy is lost in this way. In a CHP installation, both this heat and electricity are used: the heat (usually as process steam or hot water) generated is used in industrial processes, community heating and space heating. The ratio of heat-to-electricity can be tailored for each installation by the designer.

Efficiency

Because the waste heat from electricity generation is used and transmission losses are avoided, CHP typically achieves a 35 % reduction in primary energy usage compared with power stations and heat-only boilers. Used prudently, CHP can deliver significant improvements in efficiency and in cost reduction compared with traditional installations.

Environmental gains

The current CHP installations are estimated to achieve a reduction of over 30 % in CO2 emissions in comparison with generation from coal-fired power stations, and over 10 % in comparison with gas-fired combined-cycle gas turbines. The newest installations achieve a reduction of over 50 % compared with generation from coal-fired power stations

The matching process: selecting the electricity-heat ratio of plant

(often termed "sizing" plant)

The design of a CHP system is straightforward, providing that the electricity-heat ratio is constant or varies only over a limited range: otherwise the choice of appropriate CHP is a compromise and theoretical efficiency gains are not obtained.

One of the most important issues is seasonal variation in the electricity-heat ratio. To illustrate this, consider an installation for providing heat and electricity to a commercial premises. Nowadays electricity demand for air conditioning is high in summer and is accompanied by a low heat demand for space heating: in winter, the heat demand rises considerably, but not the demand for electricity. Thus, an installation designed for optimised summer operation could be ill-equipped for winter operation and vice versa.

Note from Professor Bert Whittington on Quality of Supply

Voltage

Except for exceptional circumstances, the Electricity Supply Regulations permit variations of voltage not exceeding 10% above and below the nominal at 400kV, 275kV and 132kV and not exceeding 6% at lower voltages. Customers may expect voltage to remain within these limits, except under abnormal conditions e.g. a system fault outside of planning and operating standards.

Voltage sag describes reduction in voltage of 10s of percent which can persist for up to a minute and is usually caused by a fault on the network. Voltage swell describes a short-term rise in voltage, usually caused by a switching operation on the network, and is much less common than sag. Voltage flicker describes rapid variations in system voltage, caused by such activities as arc furnaces striking and taking rapidly-varying quantities of power.

Normal operational limits are agreed and monitored individually at connection points with customers to ensure that voltage limits are not exceeded, following the specified fault events described in the Licence Security Standard Operation Memorandum No. 3. The criteria for reporting variations in excess of those permitted by the Electricity Supply Regulations are: Voltage excursions for more than 15 minutes.

Frequency

The Electricity Supply Regulations permit variations in frequency not exceeding 1% above and below 50Hz, a range of 49.5 to 50.5 Hz.

The system is normally managed such that frequency is maintained within operational limits of 49.8 and 50.2Hz. Frequency may, however, move outside of these limits under fault conditions, or when abnormal changes to operating conditions occur. Losses of generation between 1000 and 1320MW are abnormal and a maximum frequency change of 0.8Hz may occur, although operation is managed so that the frequency should return within the lower statutory limit of 49.5Hz within 60 seconds. The criteria for reporting variations in excess of those permitted by the Electricity Supply Regulations are: Frequency excursions for more than 60 seconds.

Harmonics

Harmonics are electrical frequencies which are 'harmonically' linked to the main or fundamental frequency. Thus, the third harmonic, for example, is three times the fundamental, i.e. 3 x 50 = 150Hz. They are caused by specific types of equipment, such as electronic power supplies for computers or television sets. All of the above are found in the present electricity supply network. Harmonic distortion is a measure of how 'unsmooth' the voltage and current waveforms have become by the presence of waveforms of different frequencies.

A standard has been developed for recommended harmonic voltage and current limits by the electricity industry. This standard is Engineering Recommendation G5/3, (Limits for Harmonics in the United Kingdom Electricity Supply System), published by the Electricity Association. ER G5/3 sets limits for both voltage and current distortion produced by a customer. This will soon be superseded by G5/4 which will extend the range of harmonics that require monitoring. Customers must then be concerned with harmonics up to 2500Hz, both voltage and current, and total harmonic distortion. The European Technical Standard is EN 50160.


 
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Prepared 7 February 2002