Case No: CO/4397/2017
Neutral Citation Number: [2018] EWHC 1583 (Admin)

IN THE HIGH COURT OF JUSTICE
QUEEN'S BENCH DIVISION
ADMINISTRATIVE COURT
Royal Courts of Justice
Strand, London, WC2A 2LL

Date: 22/06/2018

Before:

MR JUSTICE LAVENDER

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Between:

	The Queen
on the application of
Peak Gen Top Co Limited and others

Claimant	
	- and -		
	The Gas and Electricity Markets Authority
- and -
(1)	National Grid Electricity Transmission Plc
(2)	SSE Plc	Defendant

Interested Parties	

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Nigel Pleming QC and Robert Palmer (instructed by Osborne Clarke LLP) for the Claimants 
Kassie Smith QC and Ligia Osepciu (instructed by Steve Gee and Mark Mills of the Gas and Electricity Markets Authority) for the Defendant
Kieron Beal QC (instructed by Addleshaw Goddard) for the Second Interested Party

Hearing dates: 25-27 April 2018

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JUDGMENT
Mr Justice Lavender: 
(1) Introduction
1.	This is an application for judicial review by eight companies who carry on business generating and supplying electricity as what are known as “small embedded generators”.  For most of the Claimants, this activity represents all, or a large part, of their business.  However, the Seventh Claimant, E.ON UK plc (“E.ON”), is a very large business which plays a number of different roles in the electricity industry, both generating and supplying electricity.
2.	The Claimants have applied for judicial review of a decision (“the Decision”) taken by the Defendant (“Ofgem”) in June 2017 and announced on 20 June 2017.  The reasons for the Decision are contained in a document (“the Decision Notice”) published on 22 June 2017 entitled “Impact Assessment and Decision on industry proposals (CMP264 and CMP265) to change electricity transmission charging arrangements for Embedded Generators”. 
3.	The Claimants were given permission to rely on two grounds for seeking judicial review.  They contend that:
(1)	the Decision was contrary to the EU principle of non-discrimination; and
(2)	in taking the Decision, Ofgem failed to take account of material considerations and/or facts.
4.	The Claimants were refused permission to seek judicial review of the Decision on the ground that it was irrational.
5.	The Claimants’ application was resisted by Ofgem and by the Second Interested Party, SSE LLP (“SSE”).  SSE is a company whose subsidiaries: (1) generate electricity, both as transmission-connected generators and as small embedded generators; (2) operate two electricity distribution networks; and (3) supply electricity to customers.  The First Interested Party, National Grid Electricity Transmission Plc (“National Grid”), has taken no part in these proceedings.
6.	The parties have produced over 280 pages of witness statements, with about 5,500 pages of exhibits.  The witness statements were made by: 
(1)	Mark Robert Draper (2 statements), the chief executive and co-founder of the First Claimant, Peak Gen Top Co Ltd (“Peak Gen”).  
(2)	Nick Sillito (2 statements), the commercial director of Peak Gen. 
(3)	Matthew Tucker, the finance director of the Third Claimant, Welsh Power Group Ltd (“Welsh Power”).
(4)	Laurence Barrett, the Upstream Market Rules Manager for E.ON.
(5)	Simon Henry Hobday, a partner in Osborne Clarke, the Claimants’ solicitors.
(6)	Frances Warburton (2 statements), a civil servant with the Defendant and its partner for Energy Systems Integration.
(7)	Andrew Self, a civil servant with the Defendant and the head of its Targeted Charging Review (to which I will return).
(8)	Daniel Roberts (2 statements) of Frontier Economics Ltd, a firm of consultants retained by the Defendant.
(9)	Angus Neil MacRae of SSE.
(2) Electricity Generation, Transmission, Distribution and Supply
7.	To understand the Decision, it is necessary to say a little about the system for the generation, transmission, distribution and supply of electricity in Great Britain and the regulation of that system.  Much electricity is generated in large power stations, transmitted via the transmission network (also known as the national grid) to regional distribution networks and transmitted by those networks to domestic, industrial and commercial customers.  However, in recent years this arrangement has been supplemented in a number of ways and to an increasing extent.
8.	The electricity market is very large.  According to their consolidated segmental statements, the six largest electricity suppliers (who include E.ON and SSE) had an aggregate revenue in 2016 of over £24billion from the supply of electricity. 
(2)(a) The Transmission Network
9.	There is a single transmission network in Great Britain, which is a network of underground, overhead and subsea lines and cables and substations transmitting electricity at extra high voltage.  The largest part of the transmission network is owned by National Grid.  Others own those parts of the transmission network which are situated in Scotland or offshore.  The entire transmission network is operated by National Grid on behalf of itself and the other transmission network owners.  For the sake of convenience, I will refer simply to National Grid as the representative of all of the transmission network owners (who were sometimes referred to as the “TOs”).
10.	The transmission network is connected to:
(1)	Electricity generators.  Most large conventional coal- and gas-fired power stations and an increasing number of large wind farms are connected directly to the transmission system.  
(2)	Regional distribution networks. The point at which the transmission network connects to a distribution network is known as a grid supply point or “GSP”.  On the whole, the transmission network transmits electricity from the transmission-connected generators to the distribution networks.  But distribution networks can and do “export” electricity onto the transmission network for transmission to other distribution networks.
(3)	A few very large customers, such as steel plants.
11.	Overall, the flow of electricity on the transmission network is from generators to GSPs.  But the network is a complex one and should not be thought of as purely linear.  Subject to local variations, there is generally an excess of supply of electricity over demand in the north of Great Britain and an excess of demand over supply in the south.  This has an impact on the work which the transmission network is required to do.
(2)(b) The Distribution Networks
12.	There are 14 regional distribution networks.  Each consists of a network of underground and overhead lines and cables and substations transmitting electricity at lower voltage.  With the exception of those few customers connected directly to the transmission network, all customers receive their electricity supply from a distribution network.  
(2)(c) Electricity Generators
13.	The generation of electricity takes places at various locations.  It can be connected: (1) to the transmission network; (2) to a distribution network; or (3) directly to the customer’s premises.
14.	Electricity generators who are connected directly to the transmission network are referred to as transmission-connected generators or “TG”.  There are currently about 210 transmission-connected generators.  At peak times, they generate about 87% of Great Britain’s demand for electricity. 
15.	Electricity generators who are connected to distribution networks are referred to as “distributed generators”, “embedded generators” or “EG”.  These generators are divided into:
(1)	Large embedded generators, i.e. those with a capacity of 100MW or more.
(2)	Small embedded generators or “SEG”, i.e. those with a capacity of less than 100MW.   
16.	This distinction between large and small embedded generators is drawn, inter alia, in the licensing arrangements for electricity generators.  Small embedded generators are granted exemption from the requirement in section 4(1)(a) of the Electricity Act 1989 to have a licence to generate electricity.  There are class exemptions in paragraph 3(1) of, and Classes A and C in Schedule 2 to, the Electricity (Class Exemptions from the Requirement for a Licence) Order 2001.  Individual exemptions can also be granted.  The Secretary of State’s policy has broadly been to only consider applications for individual exemptions from generators of less than 100MW capacity:
 “because such plants will generally have a low impact on the total electricity system and it is considered appropriate therefore that, subject to consultation, such stations should be exempted from the same degree of system regulation (and costs) as imposed by standard licensing conditions.”
17.	There has been considerable growth in the number of small embedded generators in recent years.  Their total capacity has grown from about 10GW in 2012 to about 30GW in 2018, with the Claimants accounting for about 1.4GW of that capacity.  Different small embedded generators use different technology, ranging from solar energy (about 15GW in capacity) and wind energy (about 5.5GW in capacity) to gas-powered generators.  For example, Peak Gen uses container-sized units.  
18.	Generation equipment which is connected directly to the customer’s premises is known as behind the meter generation or “BTMG”.  This includes, for example, back-up diesel generators at commercial premises or solar panels on the roof of a consumer’s home.  For some larger customers, the BTMG generator may consist of a commercially-operated power plant (such as the container-sized units used by Peak Gen) which could instead have been connected directly to the relevant distribution network, in which case it would have constituted a small embedded generator.
(2)(d) Electricity Suppliers
19.	Electricity suppliers are companies who supply electricity to customers.  They enter into contracts: with generators, for the purchase of electricity; with the operators of the transmission and distribution networks, for the transmission of electricity from generator to customer; and with customers, for the sale of electricity.
(2)(e) Customers
20.	Consumers and other customers generally buy their electricity from an electricity supplier, who arranges for it to be supplied through the relevant distribution network.  As I have said:
(1)	A few very large customers are connected directly to the transmission network.
(2)	Some customers make use of BTMG.  This reduces their demand for electricity from electricity suppliers.
21.	Customers’ demand for electricity can also be affected by what is known as demand side response or “DSR”.  At its widest, this term covers any technique for reducing a customer’s electricity consumption.  Thus, BTMG is a form of DSR.  However, DSR can also include customers using technology supplied by a commercial provider and installed in or connected to the customer’s property to enable the customer to manage their use of electricity and to limit their use of electricity at specified times.  I will refer to this as “commercial DSR”.
(3) Regulation
22.	This system is regulated pursuant to relevant national and EU legislation, notably the Electricity Act 1989 and the Third Internal Market Electricity Directive (“IMED3”).  Ofgem is the national regulatory authority for the purposes of IMED3.  It is established under section 1 of the Utilities Act 2000.  
23.	It is not disputed that, in carrying out its regulatory functions, Ofgem is subject to the duty imposed by EU law not to discriminate.  There are many references to non-discrimination in IMED3 and the associated Regulation (EC) No. 714/2009 on conditions for access to the network for cross border exchanges.  I need not cite all of them.  It is appropriate to cite recital (36) to IMED3, which is in the following terms:
“National regulatory authorities should be able to fix or approve tariffs, or the methodologies underlying the calculation of the tariffs, on the basis of a proposal by the transmission system operator or distribution system operator(s), or on the basis of a proposal agreed between those operator(s) and the users of the network. In carrying out those tasks, national regulatory authorities should ensure that transmission and distribution tariffs are non-discriminatory and cost-reflective, and should take account of the long-term, marginal, avoided network costs from distributed generation and demand-side management measures.”
24.	It is also appropriate to note article 36(d), which contains specific reference to the objective of promoting the integration of distributed generation in distribution networks:
“In carrying out the regulatory tasks specified in this Directive, the regulatory authority shall take all reasonable measures in pursuit of the following objectives within the framework of their duties and powers as laid down in Article 37, in close consultation with other relevant national authorities including competition authorities, as appropriate, and without prejudice to their competencies:
…
(d)  helping to achieve, in the most cost-effective way, the development of secure, reliable and efficient non-discriminatory systems that are consumer oriented, and promoting system adequacy and, in line with general energy policy objectives, energy efficiency as well as the integration of large and small-scale production of electricity from renewable energy sources and distributed generation in both transmission and distribution networks;”
25.	Many participants in the electricity market are licensed.  That includes the owners of the transmission network.  I will refer to their licences as “the Transmission Licences”.  Those licenses are subject to conditions. 
26.	Standard Condition C5 of the Transmission Licences requires the transmission network owners to establish and maintain a “use of system charging methodology” in accordance with certain “relevant objectives” (set out in Standard Condition C5(5)), which include the following:
“(a) that compliance with the use of system charging methodology facilitates effective competition in the generation and supply of electricity and (so far as is consistent therewith) facilitates competition in the sale, distribution and purchase of electricity;
(b) that compliance with the use of system charging methodology results in charges which reflect, as far as is reasonably practicable, the costs (excluding any payments between transmission licensees which are made under and in accordance with the STC) incurred by transmission licensees in their transmission businesses and which are compatible with standard condition C26 (Requirements of a connect and manage connection);
(c) that, so far as is consistent with sub-paragraphs (a) and (b), the use of system charging methodology, as far as is reasonably practicable, properly takes account of the developments in transmission licensees' transmission businesses;
(d) compliance with the Electricity Regulation and any relevant legally binding decisions of the European Commission and/or the Agency; and
(e) promoting efficiency in the implementation and administration of the system charging methodology.”
27.	I will refer to these as “the CUSC Objectives”, as the use of system charging methodology is contained in the Connection and Use of System Code (“the CUSC”), which is maintained and administered by National Grid.  Amongst other things, the CUSC regulates the charges which may be levied by National Grid for the use of the transmission network.  I will say more in due course about how changes can be made to the CUSC.  Another code, known as the Distribution Connection and Use of System Agreement (“the DCUSA”), governs the charges which may be levied by operators of distribution networks.
28.	A further code, known as the Security and Quality of Supply Standard (“the SQSS”), sets out criteria and methodologies to be used in planning and operating the transmission network.  This code is relevant when decisions are taken as to how much investment needs to be made into the transmission network.
(4) Relevant Charges
29.	It will be necessary for me to go in some detail into aspects of the charging arrangements relevant to this case.  Even so, in what follows there will inevitably be some simplification of what is a complex and detailed system.
30.	National Grid recoups its expenditure on the transmission network by means of three sets of charges.  These are:
(1)	Transmission network use of system (or “TNUoS”) charges.  These are the principal charges at issue in this case.  They are the principal means by which National Grid recoups the cost of constructing, developing, maintaining and operating the transmission network.  
(2)	Transmission network connection charges.  
(3)	Balancing services use of system (or “BSUoS”) charges.  These charges relate to the costs of the day-to-day operation of the transmission system and, primarily, to the balancing of the electricity system, including the costs of constraining generation.  It is unnecessary for me to say any more about these charges. 
31.	Distribution network operators also raise charges.  These include:
(1)	Distribution use of system (or “DUoS”) charges.  DUoS charges are paid by suppliers and by embedded generators.   It is unnecessary for the purposes of this judgment to look in detail at how DUoS charges are calculated.  
(2)	Distribution network connection charges.  These are paid by embedded generators (and others connected to the distribution network).  
32.	Charges are calculated annually.  Charging years run from 1 April of each year to 31 March of the following year.   It is unnecessary for the purposes of this judgment to consider the methods by which the charges are collected.  It is relevant to note that network costs account for a significant proportion of customers’ electricity bills.  The average annual electricity bill in 2016 was £554.  Network costs accounted for £152.85, or 27.6%, of that bill. 
(4)(a) Allowed Revenue
33.	Ofgem sets a cap on the total revenue which National Grid or a distribution network operator can recover in any year by way of TNUoS or DUoS charges.  This cap is known as the “Allowed Revenue”.  It is calculated by Ofgem pursuant to system known as “RIIO”, which stands for “Revenue = Incentives + Innovation + Outputs”.  
34.	One of the Claimants’ arguments is that the increase in recent years in small embedded generators has falsified one of the assumptions underlying the calculation of National Grid’s Allowed Revenue, namely the demand for transmission network assets.    This is an issue which was considered by Ofgem, as can be seen from paragraphs 4.26 and 4.27 of the Decision Notice, to which I will refer. 
(4)(b) TNUoS Charges
35.	There are five types of TNUoS charge:
(1)	Transmission-connected generators and, save in the case of the TNUoS local charge, large embedded generators (but not small embedded generators) pay three types of charge, known collectively as TNUoS Generation charges:
(a)	The TNUoS local charge.  
(b)	The Transmission Generation Locational (or “TGL”) charge.  
(c)	The Transmission Generation Residual or (“TGR”) charge.  
(2)	Suppliers and other “demand users” pay two types of charge, known collectively as TNUoS Demand charges:
(a)	The Transmission Demand Locational or “TDL” charge.
(b)	The Transmission Demand Residual or “TDR” charge.  
36.	The total amount raised by the TNUoS charges in 2017/18 was £2,631.5million.  This is forecast to increase to over £3,400million by 2022/23.  Of the total of £2,631.5million in 2017/18:
(1)	£390.3million was raised by the TNUoS Generation charges;
(2)	the TDL charge resulted in a net credit to suppliers of £12.4million; and
(3)	£2,253.6million was raised by the TDR charge.
37.	It will be noted that small embedded generators do not pay any of the TNUoS charges:
(1)	There was a debate in correspondence after the hearing as to the reason for this.  TNUoS Generation charges are only paid by generators who have a licence and, as I have mentioned, small embedded generators are exempt from the requirement to have a licence.   The Claimants contended that the rationale for these exemptions supported their submissions.  I will address this issue later.
(2)	As I will explain, until 1 April 2018 some small embedded generators benefited indirectly, but significantly, from the way in which the TDL and, in particular, TDR charges were calculated.  The Decision concerned the calculation of the TDL and TDR charges.
 (4)(c) TNUoS Generation Charges: The TNUoS Local Charge
38.	This charge, which has two components, covers the cost of specific local circuits and substations which are required and/or built to facilitate a transmission-connected generator’s connection to the transmission system.  This charge is only paid by (or to, if the charge is negative) transmission-connected generators, and not by large embedded generators, since they are not connected directly to the transmission network.  This charge was the subject of the Competition and Markets Authority’s decision of 26 February 2018 in EDF Energy (Thermal Generation) Ltd v. Gas and Electricity Markets Authority.  In 2018/19, it is forecast that this charge will range from a positive charge of £9.27 to a negative charge of £0.91 per kW.
(4)(d) TNUoS Generation Charges: the TGL Charge
39.	This charge is paid by transmission-connected generators and by large embedded generators.  It is intended to reflect the marginal cost of a generator connecting at a particular location on the transmission network, i.e. the long term increase or reduction in the cost of the transmission network attributable to a generator connecting in that location.
40.	The TGL charge has three components.  Its principal elements, however, are the generator’s capacity and a rate per kW of the generator’s capacity.   The rate paid by a generator depends on the zone in which the generator’s plant is located.  A separate rate is set each year for each of 27 zones.  
41.	The rate is set using the Direct Current Load Flow Investment Cost Related Pricing transport model (“the Transport Model”).  Generally, the rate is higher the further the plant is situated from the location of demand.  For example, the rate is generally higher for zones in Scotland than in England and Wales.  Depending on the zone, the TGL charge may be positive (a cost to the generator) or negative (a credit to the generator). In 2018-19 it is forecast that the rate of the TGL charge will range from a positive charge of £29.58 per kW to a negative charge of £9.58 per kW.
(4)(e) TNUoS Generation Charges: The TGR Charge
42.	This charge is intended to cover the remainder of the transmission network construction, development and maintenance costs which are to be borne by generators rather than suppliers.  However, EC Regulation 838/2010 imposes a cap of €2.50 per MWh on the average TNUoS charges which may be imposed on generators.  (This cap does not include the TNUoS Local Charge.  That was the effect of the Competition and Markets Authority’s recent decision.)  The consequence of this cap is that in recent years the TGR charge has been negative.  Instead of paying National Grid, it is forecast that transmission-connected generators and large embedded generators will receive a credit of about £2.52 per kW by way of the TGR charge in 2018/19.
(4)(f) TNUoS Demand Charges: The TDL Charge
43.	The TDL charge is also calculated using the Transport Model.  The principal elements in the calculation are the supplier’s demand for electricity and a rate per kW.  A different rate is set each year for each of 14 zones.  The rate of the TDL charge applicable to a particular zone may be positive or negative, depending on the location of the supplier’s demand relative to the location of generation on the transmission network.  
44.	On the whole:
(1)	Suppliers pay a positive TDL charge in zones in the south of Great Britain, since their demand is located at a greater distance from most electricity generators, and in an area where the demand for electricity exceeds the local supply.  
(2)	Suppliers receive the benefit of a negative TDL charge in zones in the north of Great Britain, since their demand is located in an area where the local supply of electricity exceeds demand.
45.	The range is considerable.  In 2018/19, it is forecast that the rate of the TDL will range from a positive charge of £7.38 per kW to a negative charge of £21.22 per kW.  Overall, the positive and negative charges tend largely to balance one another out, so that the net amount raised by the TDL charge is small in the context of the TNUoS charges as a whole.
(4)(f)(i) Suppliers’ Net Demand
46.	The TDL charge (and the TDR charge) was calculated before 1 April 2018 on the supplier’s net demand in the relevant zone.  For this purpose:
(1)	A supplier’s gross demand is the gross demand for electricity from that supplier of that supplier’s customers within the relevant zone.  This is assessed in three half-hour periods (referred to as the “triad”) during peak periods of demand between November and February in the relevant charging year.
(2)	Any electricity provided to that supplier in that zone during the triad by a small embedded generator was treated as “negative demand” and was deducted from the gross demand to give the net demand.  As to this:
(a)	Some embedded generators, such as those using solar power, do not generate any electricity during the triad.  
(b)	Others make a focused effort to ensure that they are generating electricity during the triad.  As the Claimants submitted, “SEG built to address peak demand is typically gas plant that does not build in remote areas.”  Overall, National Grid estimated that small embedded generators generated electricity at a capacity of about 7.5GW during the triad.
(c)	Any BTMG generator which was exporting energy to the distribution network during the triad would be treated as a small embedded generator for this purpose.
47.	The relevant output of small embedded generators was also treated as negative demand for the purposes of the SQSS.  (I am told that this is to be changed as a result of a decision taken by Ofgem since the hearing.)
(4)(f)(ii) The Transport Model
48.	Paragraph 14.15.4 of the CUSC summarises what the Transport Model is intended to achieve, as follows:
“The DCLF ICRP transport model calculated the marginal costs of investment in the transmission system which would be required as a consequence of an increase in demand or generation at each connection point or node on the transmission system, based on a study of peak demand conditions using both Peak Security and Year Round generation backgrounds on the transmission system.  One measure of the investment costs is in terms of MWkm.  This is the concept that ICRP uses to calculate marginal costs of investment.  Hence, marginal costs are estimated initially in terms of increases or decreases in units of kilometres (km) of the transmission system for a 1 MW injection to the system.”
49.	It will be seen that the Transport Model looks at an increase in either demand for, or generation of, electricity at each connection point or node on the transmission network.  In each case, this is compared to a corresponding demand for electricity across all nodes, distributed to each node in accordance with each node’s share of the total demand for electricity, as set out in paragraph 14.15.27 of the CUSC.  
50.	Paragraphs 14.15.59-60 of the CUSC summarise how the MWkm value calculated by the Transport Model is converted into the TDL charge, as follows:
“14.15.59  The expansion constant, expressed in £/MWkm, represents the annuitised value of the transmission infrastructure capital investment required to transport 1 MW over 1 km.  Its magnitude is derived from the projected cost of 400kV overhead line, including an estimate of the cost of capital, to provide for future system expansion.
14.15.60  In the methodology, the expansion constant is used to convert the marginal km figure derived from the transport model into a £/MW signal.  ….” 
51.	In broad terms, therefore, the Transport Model and associated calculations seek to estimate:
(1)	the average cost of an additional kilometre of transmission network; and
(2)	the increase (or decrease) in the size of the transmission network (measured in km) which is likely to flow from an additional 1MW of generation or demand in a particular location.
52.	Those two estimates are then used to calculate the TDL charge for each zone.
(4)(f)(iii) Issues concerning the TDL Charge 
53.	There was considerable dispute about the nature and effect of the TDL charge.  In summary:
(1)	Ofgem’s view is that the TDL charge reflects the marginal cost of a unit of demand either increasing or decreasing at a particular location on the transmission network, i.e. the long term increase or reduction in the cost of the transmission network associated with a change in demand in that location.  
(2)	The Claimants’ case was that the TDL charge did not adequately reflect the savings in the costs of the transmission network resulting from an increase in small embedded generation.
54.	The Claimants’ submissions appeared at certain points to amount to an argument that the TDL charge was inappropriate for the purposes of reflecting costs because it was based on a model, but in the context of a complex market such as the electricity market the use of models is most likely inevitable, and certainly unobjectionable.  Mr Pleming did not contend that the use of a model in itself made the Decision unlawful.  Nor does it amount to an error of law for the Claimants to point out that the model, and consequently the TDL charge, could be improved.  
55.	The Claimants submitted that the TDL charge did not reflect actual costs, but only relative costs, and relied on the fact that the TDL charge is a “signal” and that the net amount raised by the TDL charge is near to zero.  However, this submission has to be seen in context.  In particular:
(1)	On the whole, transmission-connected generators are located at a greater distance from the demand for electricity.  
(2)	By contrast, “SEG built to address peak demand is typically gas plant that does not build in remote areas.”  
(3)	In theory, the direction of the signal could change, but there was no evidence that in practice it was likely that the market would change so significantly that small embedded generators operated by the Claimants and others like them would cease to be in locations where there was a net demand for electricity.
56.	It is true that the TDL charge is not calculated by identifying a set of transmission network costs and dividing those costs between suppliers.  On the other hand, as can be seen from the passages from the CUSC which I have quoted, it is calculated by reference to potential savings (or increases) in the costs of the transmission network.  Whilst there was much debate about the use of the term “cost-reflective” to describe the TDL charge, it is important not to be distracted by semantics:
(1)	Since the TDL charge was calculated on the basis of net demand, small embedded generators which generated electricity during the triad and which were (as was usually the case) located in areas where the demand for electricity exceeded supply were able to assist suppliers to reduce the amount they paid in TDL charges.
(2)	The amount of that reduction was intended to reflect the marginal increase or decrease in the costs of the transmission network associated with an increase in electricity generation (or reduction in electricity demand) at a particular location.  To that extent, the TDL charge was “cost-reflective”.  
(3)	The Claimants contended that the TDL charge was not “cost-reflective” insofar as it did not reflect what they alleged were additional costs savings caused by the use of small embedded generators.  As will be seen, Ofgem accepted that that was the case in relation to GSP costs, but not otherwise.   
(4)(g) TNUoS Demand Charges: The TDR Charge
57.	The effect of the TDR charge is to allocate between suppliers the residual amount of National Grid’s relevant expenditure (up to the Allowed Revenue), i.e. the amount not covered by the other four TNUoS charges.  As with the TDL charge, prior to 1 April 2018 the TDR charge was assessed by reference to the supplier’s net demand for electricity.
58.	The TDR charge is charged at a rate per kW.  There is a single rate, rather than a different rate for different zones.  This rate has grown considerably in recent years.  As recently as 2011/12 it was about £20 per kW.  In 2017/18 the rate was £47.26 per kW.  If the Decision had not been made, it is forecast that the rate of the TDR charge would have risen to:
(1)	£48.97 per kW in 2018/19;
(2)	£55.70 per kW in 2019/20; and
(3)	£61.65 per kW in 2020/21.
59.	Since it is a residual charge, the TDR charge recovers the residual amount necessary to cover the cost incurred by National Grid in constructing, developing, maintaining and operating the transmission network, after allowing for the other TNUoS charges (and excluding those matters covered by the BSUoS charges).  Much of this cost is “sunk” cost, i.e. the cost of past investment, but some of it reflects investment in, for instance, new or replacement assets.  A central part of the Claimants’ case was their contention that the increased use of small embedded generators would reduce the need for such investment as a result of reducing the demands on the transmission network as a whole.  They contend that the use of small embedded generators will, in the long term, cause an overall reduction in the cost of the transmission network.
(4)(h) TDR (and TDL) Payments
60.	Because the TDR (and TDL) charge was calculated on the basis of net demand, small electricity generators which generated electricity during the triad were able to assist suppliers to reduce their liability for the TDR (and TDL) charge.  Moreover, by making what are known as TDR (and TDL) payments to the relevant small electricity generators, suppliers tended in practice to pass on 90% or more of this reduction. 
61.	TDR payments have increased in recent years.  Unless action was taken, they were expected to amount to about £350million in 2017/18 and to rise considerably thereafter. 
62.	It will be noted that, when one supplier’s net demand is reduced by the electricity generated by small embedded generators, that increases the amount which must be paid by other suppliers so that all of National Grid’s relevant expenditure is recouped.  Since suppliers tend to pass their costs on to their customers, Ofgem’s view was (as will be seen) that the effect of TDR payments made by suppliers to small embedded generators was to increase the cost of electricity to customers.  As I will explain, the Claimants contend that it is not as simple as that.  In particular, they contend that Ofgem has ignored the benefits which small embedded generators can bring by reducing the overall need for, and therefore costs of, the transmission network.
(4)(i) BTMG and DSR
63.	Customers who make use of BTMG and/or DSR reduce their demand for electricity from their supplier, and therefore reduce their electricity bills from their supplier below what they would have been in the absence of the BTMG or DSR.  This reduces the supplier’s gross demand for electricity and, if it does so during the triad, reduces the TDR (and TDL) charge payable by the supplier.  
64.	Providers of BTMG and commercial DSR are able to assist their customers to avoid buying from their suppliers at least some of the electricity which they need.  The potential saving to a customer is the whole of the price which would have been charged for that electricity by the supplier.  That price includes allowance for all of the supplier’s costs, of which TNUoS charges form part.  
65.	It may be that more sophisticated arrangements are in place in some cases, including for large industrial or commercial customers who are able to minimise their demand for electricity from their supplier.   However, there was little, if any, evidence before me as to the nature of any such arrangements or as to the remuneration of providers of BTMG or commercial DSR.  In particular, there was no evidence that providers of BTMG or commercial DSR generally receive the equivalent of TDR payments.  
(4)(j) Connection Charges
66.	Transmission connected generators and embedded generators (whether small or large) pay connection charges.  However, there are differences between the two types of connection charge, i.e.:
(1)	Transmission connection charges.  These are paid by transmission connected generators (and by those few very large customers connected directly to the transmission network).  They are designed to cover the cost of the new connection assets needed to connect the generator’s (or customer’s) installation to the transmission network.  They do not cover any of the wider costs of reinforcing the transmission system to deal with increased usage from the additional connection.  They can be spread over 40 to 50 years, and a generator which ceases to operate its plant during that period can cease paying the connection charge.
(2)	Distribution connection charges.  These charges are paid by large and small embedded generators.  They are intended to reflect the cost of both: (a) the new connection assets needed to connect the embedded generator’s installation to the distribution network; and (b) a proportion of any network reinforcement required up to the next voltage level.   The level of the charges is affected by factors such as (i) where on the distribution network a small embedded generator connects (with the charge being lower in locations where there is spare capacity); and (ii) whether the small embedded generator is able to engage in what are known as “smart grid solutions” to reduce its connection cost. 
67.	The Claimants drew attention to the fact that, in this way, the distribution connection charges which they pay are “deeper” than the transmission connection charges paid by transmission-connected generators.   However, there was no evidence to quantify this difference, nor to quantify the difference between:
(1)	the distribution connection charges actually paid by small embedded generators; and
(2)	the aggregate of (a) the transmission connection charges and (b) the TNUoS local charges actually paid by transmission-connected generators.
68.	The Claimants argued, in effect, that one of the consequences of the TDR payments was to make up for the disadvantage which faced small embedded generators as a result of paying deeper connection charges than transmission-connected generators.  However, not only was this disadvantage not quantified, but there was no evidence to suggest:
(1)	that those small embedded generators who received TDR payments faced any greater connection charges than:
(a)	small embedded generators who did not receive TDR payments; or
(b)	large embedded generators, who not only did not receive TDR payments, they also had to pay TGL and TGR charges; or
(2)	that any large or small embedded generators had proposed amendments to, or otherwise sought to challenge, the distribution connection charges on the basis that they were discriminatory.
(4)(k) Embedded Benefits
69.	The phrase “embedded benefits” is commonly used to described various differences in treatment between small embedded generators on the one hand and transmission-connected generators on the other hand.  The TDR Payments were the largest of the embedded benefits.  However, as has been seen in relation to connection charges, and notwithstanding the use of the word “benefits”, these differences in treatment were not necessarily more favourable for the small embedded generators.   
(5) The Decision
70.	By the Decision, Ofgem has approved changes to the CUSC whose effect is as follows:
(1)	The electricity generated by small embedded generators will no longer be taken into account when calculating the TDL and TDR charges payable by suppliers.  Those charges will be calculated on the basis of the supplier’s gross demand for electricity in the relevant zone during the triad.  This means that the TDR charge will be lower than it would otherwise have been.  The current forecast is that the TDR charge will be:
(a)	£46.93 (rather than £48.97) per kW in 2018/19;
(b)	£50.30 (rather than £55.70) per kW in 2019/20; and
(c)	£55.54 (rather than £61.65) per kW in 2020/21.
(2)	However, suppliers will receive a new payment, known as the Embedded Export Tariff (“the EET”), in the expectation that this payment will (largely, if not entirely) be passed on to small embedded generators.  The EET consists of two parts, each of which is calculated at a rate which is applied to the amount of electricity generated by small embedded generators for the relevant supplier in the relevant zone during the triad.
(a)	The first part of the EET is a payment which is intended to reflect the amount by which the use of small embedded generators avoids the need for expenditure on reinforcing GSPs. This is referred to as the Avoided GSP Infrastructure Costs or “AGIC”.  This credit is forecast to amount to £3.22/kW in 2018/19.
(b)	The second part of the EET is a payment by National Grid which is calculated at the same rate as the supplier’s TDL charge for the relevant distribution zone.  I will refer to this as the “Reverse TDL charge”.  Thus:
(i)	If the supplier’s TDL charge is positive (i.e. the supplier pays an amount to National Grid), then the Reverse TDL charge is also positive (i.e. a payment by National Grid).  So the EET includes a payment by National Grid to the supplier (for the benefit of small embedded generators) in cases where small embedded generators are located in zones (usually in the south of Great Britain) which are at a greater distance from most electricity generators, and in an area where the demand for electricity exceeds the local supply.  
(ii)	If the supplier’s TDL charge is negative, then the Reverse TDL charge is also negative, but subject to the “floor-at-zero” mechanism.  So the EET paid by National Grid is reduced below the amount of the AGIC in cases where small embedded generators are located in zones (usually in the north of Great Britain) where the local supply of electricity exceeds demand.  Of course, the prospect of small embedded generators such as the Claimants being located in areas where the TDL is negative are small, since, as the Claimants themselves submitted, “SEG built to address peak demand is typically gas plant that does not build in remote areas.”  
(c)	The “floor at zero” mechanism means that the EET is never less than zero.  Consequently, if the supplier’s TDL charge in a particular zone is negative, the EET in that zone will be less than the AGIC, and might be reduced to zero, but will never become a negative charge (i.e. an amount due to National Grid).  
(3)	The net effect is that it is forecast that the EET will amount to between £11.80 and zero per kW in 2020/21 (after the transitional provisions have ceased to apply).  
(4)	The EET will be paid in full with effect from 1 April 2018.  However, the move from net to gross demand as a basis for calculating the TDR charge will be phased in over three charging years.  The net effect of the transitional provisions is that:
(a)	The TDR charge payable by suppliers in the year 2018/19 will continue to be reduced in respect of the “negative demand” attributable to small embedded generators, but at only two thirds of the rate. 
(b)	This will reduce by a further third in the year 2019/20
(c)	The “negative demand” attributable to small embedded generators will cease to affect the calculation of the TDR charged to suppliers in 2020/21.
71.	Although the Decision does not affect a charge paid by small embedded generators, it will have a significant indirect effect on some small embedded generators, i.e. those who generate electricity during the triad, since suppliers will no longer make TDR payments to them.  Instead, they will receive the (smaller) EET.
(6) The Consultation
72.	There were many issues raised in the evidence about aspects of the process which led to the Decision.  Indeed, the Claimants asserted that the process itself was skewed in favour of others.  However, that process is not itself the subject of an application for judicial review.  Accordingly, it is only relevant if and insofar as it shows that Ofgem did, or did not, take account of material considerations.
(6)(a) Powers and Procedures
73.	Standard Condition C5(2) of the Transmission Licences provides for the use of system charging methodology to be modified in accordance with Standard Condition C10, which concerns the establishment and maintenance of the CUSC.  That condition provides for three means by which the CUSC can be amended.  These are known as:
(1)	The “Open Governance Route”: see Standard Condition C10(6)(b) & (7).  This is the route which was used in the present case.   Amendments are proposed by members of the electricity industry.  Ofgem’s role is limited either to approving one of the proposed amendments (and directing that it be made) or rejecting all of them.
(2)	The “Fast Track Self-Governance Route”: see Standard Condition C10(13A) to (13D).  This is not relevant to the present case.
(3)	The “Significant Code Review” or “SCR” process: see Standard Condition C10(6A) to (6H).  Under this process, Ofgem can initiate a review which covers the contents of more than one code.  
74.	The Claimants would have preferred to see a significant code review initiated before any change was made to the TDR charge.  However, that was not done and Ofgem’s decision not to initiate such a review before making the Decision is not the subject of an application for judicial review.  (As I will explain, Ofgem has subsequently initiated a significant code review.)   
(6)(b) The CMPs and the Open Letter
75.	In May 2016 two transmission-connected generators (Scottish Power and EDF) made two alternative proposals for amending the CUSC so as to change the calculation of the TDR charge.  These were referred to as CUSC Modification Proposals (“CMPs”) and were identified as CMP 264 and CMP 265 respectively.
76.	On 6 June 2016 Frontier Economics produced a report (“the 2016 Frontier Report”) for Ofgem entitled “Transmission Charging Arrangements for Embedded Generators”.  This report had been commissioned in January 2016.  It supported Ofgem’s view that the TDR payments introduced significant distortions into the market.  The Executive Summary stated, inter alia, as follows:
“Under the current regime however, the total charges avoided through embedded generation do not reflect their incremental impact on network costs, but a measure of sunk costs, which are by definition unalterable.  The result is a system of inefficient signals that distorts behaviour.”
77.	 The Conclusion stated, inter alia, as follows:
“At the heart of the inefficiencies identified through this work is a mismatch between embedded generators’ incremental impact on power system costs and the charges and revenues facing them.  In particular, net charging of suppliers means that embedded generators are currently in receipt of significant payments for behaviour that amounts to the avoidance of charges to recover historic network costs …”
78.	On 29 July 2016 Ofgem published an open letter (“the Open Letter”) in which it discussed the issue of embedded benefits and, in particular TDR payments.  It said that it was concerned that the size and increase of the TDR payments was distorting the market in a number of ways.  It requested comments and evidence by 23 September 2016 to inform its consideration of the CMPs.  It stated as follows in section 3.5:

“3.5  Does EG provide any other benefit?
The locational element of the demand TNUoS charging arrangements should broadly reflect the costs and benefits that EG brings to the wider transmission system, in a similar way to wider generation transmission locational charges.  However, we think that in addition to the benefits captured by the demand locational signal, EG (independent of their location) will also benefit the transmission system by avoiding investment at the importing GSPs (or increase costs if it drives investment at exporting GSPs).  We note that National Grid over the years have estimated the likely size of this benefit to be between £1/kw and £6/kw.  We have seen other attempts to estimate the additional benefit that EG provide to the transmission system beyond that captured in the locational element of TNUoS charges but are currently not convinced by the rationale presented thus far and propose that industry considers how to calculate such a number and the justification for the approach taken.”
79.	This was a clear indication by Ofgem that it wished to see evidence of the benefits caused by the use of small embedded generators.  Ofgem received and considered 145 responses to the Open Letter and met many interested parties, including representatives of some of the Claimants.  
(6)(c) The Workgroup
80.	CMP 264 and 265 were considered by a Workgroup (“the Workgroup”).  It consisted of representatives from 23 companies, together with National Grid and Ofgem.  The companies represented on the Workgroup included Peak Gen (for whom Mr Draper attended as an alternative), Welsh Power (represented by Mr Tucker), Alkane Energy Limited (the Fourth Claimant: “Alkane”); and SSE.
81.	On 2 August 2016 the Workgroup published a consultation document.  This document ran to 120 pages and invited responses to 19 questions.  It set out various matters which had been considered by the Workgroup, including the following (at paragraph 2.3.23(e)):
“System peak is lower today due to a number of factors, including embedded generation, and therefore some argued that embedded generation has resulted in a smaller transmission network and hence lower cost than otherwise may have been ( … ).  Others pointed out that additional embedded generation in constrained areas of the system, for example Scotland, has contributed to a need for more transmission circuits to be constructed, to allow their power to be exported from these areas.”
82.	Members of the Workgroup were able to propose alternatives to address the same perceived defects as CMP 264 and/or 265.  Over 80 alternatives were proposed.  23 were formal proposals known as Workgroup Alternative CUSC Modifications or “WACMs”.    These included WACM4, which was proposed by SSE.  All of the WACMs proposed calculating the TDR charge on the basis of suppliers’ gross, rather than net, demand.  
83.	The Workgroup submitted a report to the CUSC Panel.  No consensus was reached within the Workgroup.  A range of views were expressed within the Workgroup (as set out in section 12 of the FMR, to which I will refer):
(1)	Some members of the Workgroup expressed the following view:
“Understanding the residual.  Further, the notion that the D-TNUoS charge can be split into the locational element of the charge that is cost-reflective, and the residual charge that represents a charge to recover the “fixed/sunk” costs of the network is entirely unjustified.  The locational element of the charge is only designed to signal differences in the cost demand imposes across different locations, not the absolute level of transmission cost that demand imposes.  Whilst the total locational charge only accounts for 10% of the allowed transmission revenue, the demand locational charge nets to a £0 recovery.  This therefore implies either that there is no capital investment, maintenance or operational costs incurred on the transmission system as a result of demand or, more likely, that this signal is in fact, not cost-reflective.”
(2)	Other members of the Workgroup expressed the following view:
“… evidence has been presented to the working group and contained in this report that demonstrated that:
•	Flows on the transmission system are identical following the connection of an equal volume of distribution or transmission connected generation at the same location.
•	The size of the transmission system (and hence the cost) is effected by the location of the connection point and is independent of the how the generation is connected i.e. distribution and transmission connected generation have the same effect on the transmission system.
•	In general a larger transmission system will be needed to accommodate generation if it is connected independently of a locational signal.  It is recognised that the current embedded benefit regime does not provide a strong locational signal.
•	Demand customers pay an additional premium above the cost required to fund available TNUoS to pay embedded benefits to distribution connected generation”
84.	It can be seen from passages such as this that the issues raised on this application were discussed by the members of the Workgroup.
(6)(d) The NERA Report
85.	One of the responses to the Open Letter was made by the Association for Decentralised Energy.  It submitted to Ofgem a report dated 23 September 2016 (“the NERA Report”) prepared by individuals from NERA Economic Consulting and from Imperial College.  The Overall Conclusion of the NERA Report was as follows:
“The logical basis for the changes in the TNUoS methodology that Ofgem’s Open Letter seems to be contemplating is extremely weak.  In particular, the notion that the D-TNUoS charge can be split into the locational element of the charge that is cost-reflective, and the residual charge that represents a charge to recover the “fixed/sunk” costs of the network is entirely unjustified.  The locational element of the charge is only designed to signal differences in the cost that demand imposes across different locations, not the absolute level of transmission cost that demand imposes.  The ratio between the two depends on regulatory decisions regarding what share of costs generation and demand should bear, and the arbitrary choice of reference node in the charging methodology.
In fact, rather than a problem with the residual charge, there are a range of flaws associated with the locational element of the charge.  If these flaws were rectified, the locational element of the charge would recover a larger amount of revenue, and the expected growth in the demand residual could be moderated.
In fact, the range of reforms to TNUoS arrangements put forward through the CMP264/5 working group process also introduce a range of new distortions that would detrimentally affect welfare.  Any new reform aimed at addressing existing distortions would need to examine carefully the trade-off between the new distortions that the modifications would create.”
86.	It will be seen that the words of the NERA Report were adopted in the summary in the FMR, which I have already quoted, of the issues discussed by the Workgroup.  
87.	Mr Pleming placed considerable emphasis on the NERA Report as indicating, in his submission, a fundamental mistake in Ofgem’s thinking.  The NERA Report:
(1)	was critical of the TDL charge, and proposed both that it should be reformed and that it should be reformed “before any reform of the residual”, i.e. before making any charges to the way the TDR charge was calculated;
(2)	used modelling carried out by Imperial College to illustrate how the TDL charge could be modified; and
(3)	argued that a number of the proposals made to the Workgroup would introduce new distortions to competition.
88.	On the other hand, as Miss Smith pointed out, the NERA Report did not identify any specific costs of the transmission network which were avoided by the use of small embedded generators.  In relation to the issue of the effect of small embedded generators on transmission network costs, paragraph 4.2.1 of the NERA Report stated as follows:
“The current method for setting the locational element of the TNUoS charges fails to recognise that two (otherwise identical) generators impose the same cost on the transmission system, irrespective of whether they are embedded within distribution systems or connected to the transmission system.  There should also be no difference between the transmission costs imposed on the system (per kW of generation capacity) by embedded generators with capacities above or below 100MW, if they are designed and operated in an identical way in other respects.  The current approach of setting different charges for different types of generation depending on whether they are embedded or not and depending on size does not reflect the fact that they impose the same costs on the transmission system.”
89.	This passage was consistent with Ofgem’s views.   However, Mr Pleming drew attention to footnote 57, which stated as follows:
“Ofgem’s references to “fixed” and “sunk costs” also appear misleading.  Transmission network capacity is built to serve network users.  Once provided, the costs of providing that transmission are sunk, but at the point of provision the investment was avoidable.  Hence, it is economically efficient to signal these costs through TNUoS charges.  The vast majority of transmission costs could also be described “fixed” in the sense that they are capital costs that do not vary with output (eg. MWh transported) and cannot be avoided in the very short-term.  However, transmission investment requirements vary with the behaviour of network users, and as such are not fixed in the medium to long-term.”
90.	The Decision Notice was to contain, in paragraph 3.8, a statement that “We note that NERA also state that up to 90% of the costs of networks are fixed.”  It transpired that this was not based on anything published by NERA, but on something said in a meeting between Ofgem representatives and the authors of the NERA Report.   
 (6)(e) The Panel
91.	On 25 November 2016 the CUSC Panel met.  It consisted of 9 members.  It considered CMPs 264 and 265 and 23 WACMs.  8 of those 23 WACMs were referred to the CUSC Panel as a result of a vote by the Workgroup.  The remaining 15 WACMs (including WACM4) were referred to the CUSC Panel by decision of the chair of the Workgroup.  
92.	The members of the CUSC Panel voted on: 
(1)	whether each WACM was better than the baseline (i.e. the status quo) in comparison with CMP 264 and, separately, CMP 265; and
(2)	which option (CMP or WACM) they considered best in relation to CMP 264 and, separately, CMP 265.
93.	One member abstained throughout, so only 8 members voted.  WACM4 received:
(1)	7 votes that it was better than the baseline in relation to CMP 264; and
(2)	6 votes that it was better than the baseline in relation to CMP 265; but 
(3)	no votes that it was the best in relation to either CMP.
94.	On 28 November 2016 National Grid produced a Final CUSC Modification Report (“the FMR”) which reported on the consideration of CMP 264 and 265 by the Workgroup and the Panel.  The FMR was 131 pages long, with 63 pages of annexes.  It included details of the voting by the members of the Panel and the reasons which they gave for their votes.  Those reasons included the following:
(1)	 “The avoided GSP investment is the only embedded benefit which was demonstrated to exist under National Grid’s analysis for the review of charging for embedded generation in 2013/4 and its inclusion would improve cost reflectively.”  (Paul Jones.)
(2)	“Analysis undertaken with the Full Transport and Tariff Model demonstrates that regardless of whether generation is connected to the transmission or distribution network there is a similar impact on the transmission network.  As such the Demand Locational Tariff broadly reflects the incremental costs or benefits of embedded generation to the transmission network.”  (Cem Suleyman.)
95.	These are merely examples.  They demonstrate that, as one would expect, the question raised by Ofgem in section 3.5 of the Open Letter was considered by members of the Panel. 
96.	On 2 December 2016 Ofgem published an update letter, outlining the developments since July 2016, providing an update on its views and setting out the proposed future timetable.
(6)(f) The “Minded to” Letter
97.	In March 2017 Frontier Economics and LCP produced a revised report (“the 2017 Frontier Report”) on “Transmission Charging Arrangements for Embedded Generation”.  The 2017 Frontier Report presented the results of Frontier Economics’ analysis of three scenarios, compared to the status quo.  Of those three scenarios, Scenario 3 was closest to WACM4.  Frontier Economics concluded that moving to Scenario 3 would result in substantial savings in the period to 2034, i.e.:
(1)	£2.1billion in savings in system costs; and
(2)	£7.4billion in savings in consumer costs.  
98.	On 1 March 2017 Ofgem published a “Minded to decision and draft Impact Assessment” (“the “Minded to” Letter”).  This document was 118 pages long, including 11 appendices.  It was accompanied by the 2017 Frontier Report.  It set out the reasons for Ofgem’s decision that it was minded to direct that WACM4 be made.  It invited views by 18 April 2017.   
99.	The questions on which views were sought included the following:
“Question 7: Do you agree with our assessment that the value of the avoided GSP investment cost best facilitates the applicable CUSC objectives?”
“Question 9: Please provide evidence to show if there are other cost savings which small EG drive in comparison to larger (over 100MW) EG on the distribution system.
Question 10: Is there other evidence that payment above avoided GSP/generation residual would better facilitate the applicable objectives?”
100.	Ofgem was still giving consultees such as the Claimants the opportunity to identify cost savings (other than avoided GSP costs) caused by small embedded generators.
(6)(g) The Targeted Charging Review
101.	On 13 March 2017 Ofgem published a consultation on a proposed significant code review, known as the Targeted Charging Review.  The Targeted Charging Review was subsequently launched on 2 August 2017.  Its scope includes all embedded benefits.
(6)(h) The Summary of Arguments
102.	Some of the Claimants (including at least Peak Gen, Welsh Power and Alkane) submitted views in response to the “Minded to” Letter.   In June 2017 Ofgem prepared for internal consideration a “Summary of arguments raised by respondents and Ofgem’s policy response” (“the Summary of Arguments”). 
(6)(h)(i) The Summary of Arguments: The NERA Report
103.	The Summary of Arguments referred to the NERA Report and the arguments based on it.  It said, inter alia, as follows:
	“We have also received the argument that over time, by reducing the requirement for infrastructure investment, EG can be used to avoid the need to expand a network, and possibly not to replace elements of it.  The suggestion is that over time a network can evolve to be smaller with EG than it otherwise would have been.  There are a number of reasons why this doesn’t really work.
Firstly, a reduction would only take place if the EG was sited in the right place.  If in the wrong place, the EG may drive additional reinforcement costs.  This is therefore achieved by using correctly sized locational signals.  Secondly, with the exception of the GSP costs and possibly some distribution costs, transmission connected generation in the same location would have the same impact, and so also either reduce or increase the network in the same way as the EG.  If sited in an exporting GSP, an EG may actually lead to more customer cost than a transmission connected generator located nearby as the power would need to be transported over additional parts of the network (the distribution network and the GSP).  Thirdly, the transmission charges already account for the costs of using methods other than infrastructure investment in the charges to ensure that the most efficient network option is pursued.  This manifests in the Year Round elements of the locational charges, which aim to represent the balance of infrastructure investment and constraint costs (EG in many cases cause these year round costs, especially in the case of renewables).  Finally, the life of a network is significantly longer than the life of a generator, so detailed analysis would be needed to assess whether any real savings could be made from paying a generator on an ongoing basis rather than investing in the infrastructure.  It would also be highly dependent on the situation at hand.  We therefore think any suggestion that EG should receive a set benefit for avoiding future transmission costs is flawed.  This mechanism is already achieved by the locational signals set out by project Transmit, and is equally applicable to Transmission connected and Embedded generation, rather than something unique to EG.”
(6)(h)(ii) The Summary of Arguments: Welsh Power’s Argument
104.	The Summary of Arguments also stated as follows:
	“Welsh Power’s argument
Welsh Power argue that by building embedded generation on the distribution network, you reduce the need for the transmission system upgrades described above, and this is demonstrated by the underspend of the TOs on transmission system upgrades.  Welsh Power use values from the connections volume driver and demand related infrastructure driver - £27/kW and £3.9 million – which the TOs get for over/underspend, and turn this into a per kW figure by dividing the value by the capacity the reinforcements deliver.  They then annuitize these figures over 40 years (the life of the assets) to show that, in addition to the avoided GSP cost, there is a real saving driven by embedded generators.  The value of this ‘benefit’ ranges from £1.34/kW to £10+ depending on the capacity delivered.
Welsh Power argue that we cannot accept a WACM which has a lower ‘value of x’ than this, and cannot accept a WACM if there is a saving, which we are aware of, above the level we set out in our minded-to impact assessment (the avoided GSP).
Our questions
There are three main points which go against Welsh Power’s argument.
1.	The RIIO forecasts are set out against a ‘Gone Green’ Future Energy Scenario background, and therefore required a large amount of build out that has not materialised.  It is not generally the increase in embedded generation which has led to a reduced build out, rather it is changes in policy, renewables growth (against Gone Green) and other external factors.
2.	To pay an embedded generator the same as what the TOs receive for over/underspend, you would have to prove that those embedded generators are the only ones driving that cost saving, rather than it being other factors (the fact that National Grid forecast against Gone Green or true demand reduction etc).
3.	There is a disconnect between the values the TOs get under a regulated revenue stream and the competitive market in which the embedded generators are operating under.  It does not necessarily follow that the payment is a 1:1 saving on the transmission system.
Having discussed the arguments above with our networks and RIIO team, they have stated that linking regulated revenues and an embedded benefit may not be beneficial or accurate.  They also state that the RIIO revenue drivers will take other factors into account when determining the costs, such as network stability, which may inflate the allowed revenues for upgrades and would not be a saving driven by embedded generation.”
(6)(h)(iii) The Summary of Arguments: The SQSS
105.	The Summary of Arguments also addressed at some length submissions which were made to Ofgem by Peak Gen and others that the SQSS showed how small embedded generators reduced the costs of the transmission network.  The Summary of Arguments stated, inter alia, as follows:
“However, one thing that is treated differently is embedded generation when it is treated as negative demand.  Instead of being scaled, removing the generators capacity from the demand (effectively netting off their output with the demand from the area) will have a full, unscaled impact on the system, so in an area where demand reduction or generation can reduce the MWkm on the system, EG (when treated as negative demand) has a bigger positive impact on the system because that demand reduction “goes further” than the corresponding generation increase which is scaled if that same EG was treated as demand.  In an area where demand reduction or additional generation increases the MWkm on the system, the impact of the EG would again be greater as unscaled.  Effectively this is as much an administrative choice as anything but it is important to note that it is correct to state that EG is different in the SQSS.
All this means that EG does currently, when treated as negative demand rather than generation (i.e. when its capacity is subtracted from the demand rather than its capacity used to feed into the generation locational tariff models), appear different than other generation.  We have argued, and still stand by the claim that embedded generation has the same impact on the transmission system, and that it is the differential treatment that leads to the different result.”
106.	Ofgem noted an argument made by the Association for Decentralised Energy that a number of small distributed generators should be treated differently from a single large generator.  As to this, the Summary of Arguments stated:
“We agree that small and large generators may have different impacts on the system but it is not clears how a given number of small transmission connected generators of a given capacity would cause different requirements to the same number of embedded generators of that same given capacity.  This is an argument for multiple small generators having lower risk of starting or stopping production than large ones, and, not of any advantage to having a distribution connection rather than a transmission connection.  This again has nothing to do with the efficient recovery of costs that do not vary with and need to be received in the most non-distortive way possible.”
(7) The Reasons for the Decision
107.	On 22 June 2017 Ofgem took the Decision.  It decided that WACM4 best facilitated the CUSC objectives and Ofgem’s statutory duties.  It directed that WACM4 be made.  Its reasons were set out in the Decision Notice.  This document is 143 pages long, including 7 appendices.  The document has, of course, to be read as a whole, but the following aspects are worthy of particular notice.
(7)(a) Problem Definition
108.	Paragraphs 2.7 to 2.13 of the Decision Notice are headed “Problem Definition”.  Having identified the increasing levels of the TDR charge and the TDR payments, Ofgem stated as follows in paragraphs 2.10 to 2.13:
“2.10. The payment of the TDR to smaller EG provides a strong incentive for generators to connect on the distribution system, instead of the transmission system. As an increasing number of smaller EG locate on the distribution system and generate at triad periods, net demand from the transmission system is reduced at triad periods. This leads to revenues that need to be recovered via the transmission charges being recovered over a smaller charging base. This increases the level of the TDR charge, increasing charges to those who cannot take the same action and also increasing the TDR payments to smaller EG, further escalating the problem. It also increases the cost to consumers, as suppliers have to recover more from their customers to pay those smaller EG generators who generate at triad periods.  
2.11. We believe the size and increase in the TDR payment is leading to the following distortions and outcomes: 
•	Wholesale price – By running out of merit, the wholesale market price is distorted and artificially dampened at peak times; 
•	The Capacity Market – Smaller EG have a competitive advantage when bidding into the CM, reducing their possible bid prices; 
•	Dispatch – Increasing amounts of smaller EG generate out of merit to ensure they hit the triad periods; 
•	Inefficient investment in generation capacity – A large financial incentive to locate on the distribution system even in circumstances where it is not the most efficient place to locate, and to build generation capacity that may not have been efficient to build under a regime without these distortions; 
•	Ancillary services – Smaller EG may be at a competitive advantage in the ancillary services market.  
2.12. We believe the distortions outlined above lead to higher consumer costs. More efficient generators could be pushed out of the market, while consumers have to pay additional money to allow suppliers to ‘offset’ their transmission residual charges. As the amount of money recovered through TNUoS residual charges is largely fixed over the short to medium term, where these charges are avoided, they will have to be picked up by other users.  In addition, TDR payments could lead to inefficient investment in network capacity. Inefficient investment in generation connected to either the transmission or distribution networks would lead to inefficient additional network investment, raising costs to consumers.
2.13. Suppliers recover both the TNUoS charges and the cost of TDR payments to smaller EG from consumers, which increases the total costs recovered from consumers. We have received a significant number of responses to our consultation, though none lead us to believe that the current TDR payments are cost-reflective, sustainable or equitable.”
109.	Mr Pleming did not argue that Ofgem was wrong to see the TDR payments as distorting the market.  Rather, he focused on Ofgem’s consideration of the alternatives as to what should replace the TDR payments.  
(7)(b) Available Options
110.	In section 3 of the Decision Notice, Ofgem analysed the 25 modification proposals (i.e. 2 CMPs and 23 WACMs).  It noted that:
(1)	All of the proposals involved moving from net to gross demand as a basis for calculating the TDR charge.  However, most of them involved introducing a different credit, referable to the amount of electricity generated by small embedded generators during the triad.  The amount of this credit was referred to by Ofgem as “the value of “x””.  There were a range of different proposals for the value of “x”, of which the AGIC was one.
(2)	Most of the proposals involved introducing the “floor-at-zero” mechanism.
(3)	The proposals involved a range of transitional provisions, including:
(a)	no transitional provision;
(b)	phasing in the change over 3 years; and
(c)	various kinds of “grandfathering” arrangements.
111.	No issue arises in this case as to the nature of the transitional provisions preferred by Ofgem.
112.	Ofgem identified that it could: 
(1)	accept any of the modifications;
(2)	reject all of them; 
(3)	send them back for further consideration; or
(4)	implement one of them with a year’s delay.
(7)(c) Assessment of Options
113.	Ofgem assessed each of the options against the CUSC Objectives and Ofgem’s statutory duties.  In substance, this was an assessment of which value of “x” best reflected the costs saved by the use of small embedded generators.  Ofgem’s conclusion on this issue was set out as follows in paragraph 4.12 of the Decision Notice:
“Our final assessment is that avoided GSP costs are the only benefits to the transmission system that have been robustly demonstrated to flow from smaller EG.  A value of ‘x’ equivalent to avoided GSP costs would reduce the TDR payment to one which reflects long run cost savings achievable on the system from the reduced need to reinforce the points where the distribution system meets the transmissions system.”
114.	At the heart of this case is the simple fact that the Claimants disagree with this conclusion.  However, that in itself is not a ground for judicial review.  
115.	Ofgem gave a number of reasons for the conclusion expressed in paragraph 4.12 of the Decision Notice.  These addressed some of the arguments made by the Claimants and others.  For instance, paragraphs 4.17 and 4.18 said as follows in relation to the arguments relating to the SQSS:
“4.17. When treated as negative demand rather than generation, EG is not scaled by a scaling factor (as set out in the SQSS) as other generation would be. This means that removing the generators’ capacity from demand by netting off their output with the demand from the area will have a full, unscaled impact on the system. This can have a bigger impact on the modelled system because that demand reduction “goes further” than the corresponding generation increase, as it is not scaled. We disagree this is evidence of EG’s benefits, and note that it is no different than other generation. It is the differential treatment via the model that leads to the different result. 
4.18. The locational charges have a broad relationship with the investment needs that underpin the system and are defined in the SQSS. The SQSS is not concerned with how residual costs should be recovered or charged. These should be recovered on economic principles in a way that reduces distortions.”
116.	Ofgem’s reasons also included the following, in paragraphs 4.26 and 4.27 of the Decision Notice:
“4.26	It was also noted that load-related volume drivers within RIIO provide £/kW values for the cost of infrastructure build.  Some respondents have suggested the embedded generators can prevent the requirement for these transmission upgrades, therefore, they should be paid an annuitized value of those infrastructure upgrade costs.
4.27	We would note that while the TOs, so far, have outperformed their load-related volume drivers, having not built the level of generation/demand connections forecast in their RIIO baseline, we are only 3 years into the price control and it is difficult to link the underspend directly with increased embedded generation.  We therefore think that there is not currently sufficient evidence of a direct causative link between embedded generation and reduced expenditure on transmission assets beyond that of the GSP infrastructure savings.”
117.	The final sentence of paragraph 4.27 implied that Ofgem remained open to persuasion in the light of further evidence that the use of small embedded generation caused further savings in addition to saved GSP costs.  Miss Smith confirmed that that was indeed Ofgem’s position.
118.	The Decision Notice set out the results of quantitative modelling carried out by LCP/Frontier for some of the WACMs.  That modelling did not lead Ofgem to a different conclusion.  In relation to the consequences of adopting WACM4, Ofgem concluded (in paragraph 6.36 of the Decision Notice) that:
“WACM4 leads to a consumer saving in the years to 2024 of £2.2bn, and £7.5bn in the years to 2034.”
119.	Taking account of its conclusions on the appropriate value of “x” and on the appropriate transitional provisions, Ofgem concluded that the adoption and implementation of WACM4 would best facilitate the CUSC Objectives and Ofgem’s statutory duties.
(8) The Claimants’ Grounds
120.	As I have said, the Claimants contend that:
(1)	the Decision was contrary to the EU principle of non-discrimination; and
(2)	in taking the Decision, Ofgem failed to take account of material considerations and/or facts.
121.	There are two alleged breaches of the EU principle of non-discrimination.  The Claimants contend that the effect of the Decision was:
(1)	to treat small embedded generators differently from providers of BTMG and DSR, when they are in fact equivalent; and/or
(2)	to treat small embedded generators as equivalent to transmission-connected generators, when they are materially different.
122.	It was originally alleged that Ofgem failed to consider two material considerations.  However, Mr Pleming did not pursue the first of these alleged failures, i.e. an alleged failure to consider the issue of non-discrimination.  The second alleged failure was an alleged failure to consider “the impact of [small embedded generators] on long-term avoided marginal costs”.   I will deal with this ground first before turning to the two alleged instances of unlawful discrimination.
123.	Before turning to the grounds, it is worth noting three points:
(1)	Ofgem is an expert body charged with making decisions on complex, technical issues.  The Courts will be slow to interfere with the judgments of such a body on such issues.
(2)	The Claimants clearly disagree with the Decision, but they did not have permission to, and did not, contend that the Decision was irrational or perverse.
(3)	I have already referred to two issues where the Claimants voiced complaints in their evidence about matters which are not the subject of applications for judicial review, i.e. the process leading to the Decision and Ofgem’s decision not to initiate a significant code review before making the Decision.  
(9) Alleged Failure to Take Account of a Material Consideration
124.	The Claimants’ case on what was referred to as ground 2 changed somewhat during the course of the proceedings.  As set out in the Claimants’ Statement of Facts and Grounds of Claim (especially in paragraphs 54 to 59), the focus of this ground was on the allegation that Ofgem failed to consider what the Claimants alleged was the impact of small embedded generators on the long-term avoided marginal costs of the transmission network.  This allegation is not made out.  Ofgem did consider whether the use of small embedded generators resulted in long-term avoided marginal costs of the transmission network.  One of the central issues considered in the Decision Notice was where to fix the appropriate value of “x”.   Ofgem decided that the appropriate amount was what became the EET, which reflected both avoided GSP costs and the amount of the TDL charge, but Ofgem did not consider that there were any other benefits to the transmission network flowing from the use of small embedded generators.
125.	In effect, the Claimants’ case as originally pleaded asserted as a fact that small embedded generators produce larger savings in transmission network costs than are reflected in the EET, and then complained that Ofgem had failed to take that asserted fact into consideration.  But Ofgem had considered whether that asserted fact was actually true, and had decided that it was not.  That was the assessment of the expert regulator.  This court cannot simply assume the existence of asserted facts which the expert regulator has concluded are untrue.  Ofgem’s assessment could be challenged on the grounds of irrationality, but the Claimants are not bringing such a challenge.
126.	At the hearing, Mr Pleming’s primary submission was that Ofgem made an error of law because it misunderstood the arguments made to it by the Claimants and others, particularly in the NERA Report, to the effect that what became the EET (i.e. a combination of the AGIC and the Reverse TDL charge) would not adequately reflect all of the savings in the costs of the transmission network which resulted from the use of small embedded generators.  Although Ofgem purported to address those arguments, Mr Pleming submitted that Ofgem did not truly take account of them because Ofgem misunderstood them.  Mr Pleming acknowledged that he needed to demonstrate a misunderstanding on Ofgem’s part, and not merely an error of judgment, in order to be able to argue that Ofgem made an error of law which was amenable to judicial review.
127.	A further argument advanced by Mr Pleming was that Ofgem did not adequately investigate the issue of the impact of small embedded generators on what the Claimants alleged were the long-term avoided marginal costs of the transmission network.  Finally, in his reply submissions, Mr Pleming developed an argument that the provisions of the SQSS meant that small embedded generators placed less demand on, and therefore created opportunities for savings in the costs of, the transmission network. 
128.	The Claimants confirmed, in paragraph 50 of the Statement of Facts and Grounds of Claim, that no criticism was made of weight attached by Ofgem to material considerations which were actually considered by Ofgem.
(9)(a) Ofgem’s Alleged Misunderstanding 
129.	I asked Mr Pleming to summarise the alleged misunderstanding.  He identified what he submitted were three key points which Ofgem misunderstood, i.e.:
(1)	The TDL charge is not cost reflective, but creates a relative and temporary locational signal.
(2)	The TDL charge, either by design or as a consequence of the model on which it is based, nets to zero.
(3)	The transmission network costs saved or avoided by the use of small embedded generators are to be found in the TDR charge.
130.	I am not persuaded that there was any such misunderstanding by Ofgem.  It seems to me that Ofgem adequately understood the points which were being made to it by the Claimants and others.  The simple fact is that Ofgem did not agree with those points.  
131.	Ofgem identified in the Open Letter as an important question for consultation the question of what transmission network costs were saved or avoided by the use of small embedded generators.  The Claimants’ argument that the use of small embedded generators produces savings in the cost of the transmission network which are not reflected by the EET was summarised as follows in paragraph 11 of their skeleton argument:
“If, hypothetically, all generators were embedded and matched to the local demand they are serving, there would be no need for the [transmission network], and hence the costs of the transmission network would be zero.  More realistically, given that [transmission-connected generation] was providing 87% of peak demand based on the most recent data available, if there were no [embedded generation] then the [transmission network] would have to be commensurably larger.” 
132.	I see no reason to conclude that Ofgem failed to appreciate this argument.  On the contrary, as the passages which I have quoted show, the argument that small embedded generators resulted in reduced transmission costs which were not captured by the Reverse TDL charge was considered by the Workgroup, by the Panel and by Ofgem itself (in both the Summary of Arguments and the Decision Notice).  
133.	Nor is there any reason to believe that Ofgem misunderstood the nature of the TDL charge.  Ofgem referred to the TDL charge as a locational signal in the Decision Notice.  More importantly, Ofgem demonstrated by including the AGIC in the EET that it was willing to adjust the use of system charging methodology in ways which went beyond the scope of the TDL charge if it considered that it was necessary to do so in order to make the charging methodology reflective of costs savings achieved by the use of small embedded generators.  
134.	Moreover, paragraphs 4.26 and 4.27 of the Decision Notice demonstrate that Ofgem was open to the suggestion that the use of small embedded generators resulted in savings which were not reflected by the EET.  It follows that the Claimants were not justified in asserting that the cost reflectivity of the TDL charge was simply assumed to be correct by Ofgem or that Ofgem incorrectly assumed that the TDR charge only related to sunk costs or that neither the presence of small embedded generators nor any increase or decrease in small embedded generators could ever impact the size of the transmission network or future investment therein.   
135.	The Claimants do not agree with the conclusion reached in paragraphs 4.26 and 4.27 of the Decision Notice, but that was an assessment which it was open to Ofgem, as the specialist regulator, to make.  I am not persuaded that Ofgem’s decision was the result of a failure to take account of a material consideration, rather than simply Ofgem’s assessment of the position after consideration of the arguments advanced to it.
(9)(b) Ofgem’s alleged Failure to Investigate
136.	Relying, in particular, on paragraph 4.27 of the Decision Notice, Mr Pleming submitted that Ofgem had put the burden on the Claimants of providing evidence that the use of small embedded generators results in additional savings in the costs of the transmission network.  He submitted that Ofgem was wrong to do so.   
137.	Ofgem had identified as a material consideration whether there was evidence which showed that the use of small embedded generators resulted in additional savings in the costs of the transmission network.  Ofgem considered the evidence which was available to it, as can be seen from the Decision Notice, including paragraphs 4.26 and 4.27.  Ofgem also invited interested parties to submit evidence on this issue, both in the Open Letter and in the “Minded to” Letter.  Ofgem considered the submissions which were made to it, together with any supporting material, such as the NERA Report.
138.	Mr Pleming submitted, in effect, that it was an error of law for Ofgem to put the burden of proof on small embedded generators and not to conduct its own investigations, arguing that Ofgem was better equipped to do so than the Claimants.  This submission falls foul of the principle that it is for the decision-maker to decide upon the manner and intensity of any inquiry to be undertaken into any material consideration: see R. (Khatun) v Newham LBC [2005] QB 37, at paragraph 35.   Once again, while in theory a decision by Ofgem not to conduct further investigations into a material consideration could be challenged on the grounds of irrationality, the Claimants did not have permission to challenge the Decision on the grounds of irrationality.
(9)(c) The SQSS Argument
139.	In her submissions, Miss Smith produced a number of diagrams which were intended to illustrate the proposition, made in paragraph 4.2.1 of the NERA Report, that two (otherwise identical) generators impose the same cost on the transmission network, irrespective of whether they are embedded within distribution networks or connected to the transmission network.  In his reply submissions, Mr Pleming produced diagrams in response and sought to develop (for the first time at the hearing) an argument that the different requirements of the SQSS for different types of generators demonstrated why small embedded generators imposed smaller demands on, and were therefore were able to achieve greater savings in the cost of, the transmission network than transmission-connected generators.  The Claimants contended that their position on this issue was supported by the reasons given by the Secretary of State for his policy of exempting small embedded generators from the requirement to obtain a licence (and therefore from the obligation to pay TNUoS Generation charges), i.e. that small embedded generators “generally have a low impact on the total electricity system”.   
140.	Having been raised so late, this issue generated a certain amount of correspondence after the hearing.  That was unsatisfactory.  Had the issue been raised at the outset, there would have been more focus on relevant parts of the evidence, such as those passages of the Summary of Arguments and the Decision Notice which addressed the arguments made by Peak Gen and others based on the SQSS, and there might have been more evidence on the underlying rationale for treating large and small embedded generators differently.
141.	In any event, however, I am not persuaded that these submissions demonstrated any error of law on the part of Ofgem.  In particular, Ofgem did not fail to take account of a material consideration.  Paragraphs 4.17 and 4.18 of the Decision Notice and the section of the Summary of Arguments to which I have referred demonstrate that the arguments advanced by Peak Gen and others concerning the SQSS were considered by Ofgem.  The fact that the Claimants do not agree with Ofgem’s assessment is not a ground for judicial review.
(10) Unlawful Discrimination
142.	As I have said, it was accepted that Ofgem was subject to the duty imposed by EU law not to discriminate.  The EU principle of non-discrimination requires that comparable situations are not to be treated differently, or different situations treated in the same way, without objective justification: see R. (on the application of RWE Generation UK Plc) v Gas and Electricity Markets Authority [2015] EWHC 2164 (Admin); [2016] 1 C.M.L.R. 17, at paragraph 44, per Lewis J.
143.	The application of this principle was considered by Lord Sumption in paragraph 27 of his judgment in R. (on the application of Rotherham MBC) v Secretary of State for Business, Innovation and Skills [2015] UKSC 6; [2015] 3 C.M.L.R. 20:
“The two-stage process by which courts in discrimination cases distinguish between comparability and objective justification is a useful tool of analysis and probably indispensable in dealing with allegations of discrimination on ground of gender, race or other personal characteristics. More generally, a rigid distinction between the two stages was implicit in the four-stage test proposed by Brooke LJ in Wandsworth London Borough Council v Michalak [2003] 1 WLR 617, para 20, for cases arising under article 14 of the European Convention on Human Rights. But a tool of analysis should not be transformed into a rule of law. As Lord Hoffmann pointed out in R (Carson) v Secretary of State for Work and Pensions [2006] 1 AC 173, paras 29-31, the question whether two situations are comparable will often overlap with the question whether the distinction is objectively justifiable: 
“If an “analogous situation”… means that the two cases are not relevantly different (no two cases will ever be exactly the same) then a relevant difference may be the justification for the difference in treatment … [T]his division of the reasoning into two stages is artificial. People don't think that way. There is a single question: is there enough of a relevant difference between X and Y to justify different treatment? … [T]he invocation of the ‘rational and fair-minded person’ (who is, of course, the judge) suggests that the decision as to whether the differences are sufficient to justify a difference in treatment will always be a matter for the judge.””
144.	For the purposes of considering the Claimants’ discrimination arguments, I assume that the Decision was in all other respects lawful, i.e. that Ofgem took account of all material considerations in arriving at its decision that eliminating TDR payments would prevent significant distortions in the electricity market and significantly reduce customers’ electricity bills.
145.	There was debate as to:
(1)	whether and, if so, to what extent the court, when considering whether there has been unjustified discrimination, could or should afford respect to the views of the expert regulator on that issue (as to which I was referred to: R. v Director General for Telecommunications (ex parte Cellcom) [1999] E.C.C. 314, at paragraph 26; Everything Everywhere Ltd v Competititon Commission [2013] EWCA Civ 154, at paragraphs 35-39; and R. (Gallaher Group Ltd) v Competition and Markets Authority [2016] EWCA Civ 719, at paragraph 42); and
(2)	the question whether the EU principle of non-discrimination can be relied on by a claimant to contend that he should continue to receive an unjustified benefit because others continue to receive that benefit (as to which I was referred to: Commissioners for Customs and Excise v National Westminster Bank Plc [2003] STC 1072; [2003] EWHC 1822 (Ch), at paragraphs 63-67; Distribution Casino France SAS (Cases C-266/04 to C-270/04, C-276/04 and C-321/04 to 325/04) [2005] ECR I-9481, at paragraphs 40-42; Revenue and Customs Commissioners v Rank Group Plc [2011] ECR I-10947, at paragraphs 59-64; and R. (Gallaher Group Ltd) v Competititon and Markets Authority [2016] EWCA Civ 719, at paragraphs 52-59).
146.	I have not found it necessary to resolve these issues.  
(10)(a) Discrimination: Context
147.	The market for electricity generators is a broad one, with a range of different participants, and the charging arrangements are complex.   The Decision affects some, but by no means all, small embedded generators.  It affects them because they, unlike any other participant in the market, were the recipients of payments which Ofgem considered to be distorting the market and significantly increasing the cost of electricity to consumers.
 (10)(b) Discrimination: BTMG and Commercial DSR
148.	The Claimants contended that small embedded generators are materially the same as providers of BTMG and commercial DSR because all three reduce the amount of a supplier’s net demand for electricity. This, however, is only part of the picture.  
149.	Commercial DSR is not a form of electricity generation at all.  It is a means of assisting customers to reduce their demand for electricity, as is BTMG.  To the extent that a customer makes use of commercial DSR or BTMG, the customer does not buy electricity which it would otherwise have bought from its supplier.  This reduces the supplier’s gross demand for electricity.  Small embedded generators do not reduce suppliers’ gross demand for electricity.  They help suppliers to meet that demand.
150.	Providers of commercial DSR and BTMG did not receive TDR payments from suppliers.  Indeed, as I have said, there was no evidence as to how they were remunerated.  They will not benefit from the EET.  Moreover:
(1)	Because providers of commercial DSR and BTMG supply their services to customers, they need to identify and enter into contracts with individual customers who are in a position to benefit from their services.   Those customers will presumably only be willing to contract with them if they can reduce the customers’ overall electricity bills.  
(2)	Because they supply electricity to suppliers rather than to customers, small electricity generators do not need to identify and enter into contracts with individual customers.   Instead, it is the suppliers who make arrangements for the electricity which is generated by small embedded generators to be supplied to the suppliers’ customers.  
(3)	Supposing (although there was no evidence about this) that providers of commercial DSR and BTMG are able to charge more for their electricity than small embedded generators, that may be no more than a function of the fact that they occupy different places in the market.  For instance, providers of BTMG supply electricity “retail” to individual customers, whereas small embedded generators supply electricity “wholesale” to suppliers for on-sale to customers.   
(4)	The Decision concerned charges paid by suppliers and payments made by suppliers (i.e. the TDR payments).  Since providers of commercial DSR and BTMG do not supply electricity to suppliers and do not receive payments from suppliers, it is difficult to see how the Decision, or any equivalent of the Decision, could be applied to them.
151.	Some small embedded generators did not receive TDR payments and they will not benefit from the EET.  Other small embedded generators, such as the Claimants, generate electricity during the triad, so that they affected the calculation of their suppliers’ net (but not gross) demand for electricity.  They used to receive TDR payments, which, in Ofgem’s view, distorted the market and greatly increased the cost of electricity to customers. As a result of the Decision, they will no longer receive TDR payments, but they will benefit from the EET.  Those small embedded generators who received TDR payments were receiving payments which Ofgem considered significantly increased the cost of electricity to customers.  Whatever payments are made by customers to providers of commercial DSR or BTMG, those payments will presumably only be made if they reduce the cost of electricity to those customers.
152.	Looking in the round at the similarities and differences between providers of BTMG and commercial DSR on the one hand and small embedded generators on the other hand, I am satisfied that there is enough of a relevant difference between them to justify their different treatment after the Decision.  
(10)(c) Discrimination: Transmission-connected Generators
153.	Mr Pleming submitted that the Decision was unlawfully discriminatory because the effect of the Decision was to treat small embedded generators as if they were in a comparable situation to transmission-connected generators, when there are material differences between them.  In particular, he submitted that:
(1)	the purpose of the Decision was to put small embedded generators in an economically equivalent position to transmission-connected generators with respect to the costs of using of the transmission network; but
(2)	small embedded generators are in a different position to transmission connected generators because they pay deeper connection charges.
154.	There are a number of similarities and differences between small embedded generators on the one hand and  transmission-connected generators on the other hand:  
(1)	Both generate electricity and supply that electricity to suppliers.
(a)	Before the Decision:
(i)	Suppliers did not pay TNUoS charges to the extent that they satisfied their demand for electricity during the triad with electricity generated by small embedded generators.
(ii)	Some small embedded generators received TDR payments, which, in Ofgem’s view, distorted the market and greatly increased the costs of electricity to customers.  Transmission-connected generators did not receive these payments.
(b)	Following the Decision:
(i)	Suppliers pay TNUoS charges on their demand for electricity during the triad, whether that demand is satisfied by transmission-connected generators, large embedded generators or small embedded generators. 
(ii)	Those small embedded generators who used to receive TDR payments receive the EET, which includes the AGIC, which is intended to reflect the costs savings attributable to the fact that they are not connected directly to the transmission network.  Transmission-connected generators do not receive any equivalent to the AGIC.  Nor do those small embedded generators who did not receive TDR payments.
(2)	Transmission-connected generators pay TNUoS Generation charges, including TNUoS local charges, whereas small embedded generators do not.  
(3)	Both transmission-connected generators and small embedded generators pay the connection charges appropriate to the network to which they are connected.  Small embedded generators pay deeper connection charges than transmission-connected generators.  As I have said, the difference between the two has not been quantified.  Moreover:
(a)	This is the case for all embedded generators, large or small, and whether or not they used to receive TDR payments.  
(b)	It does not appear that the difference has hitherto prompted any large or small embedded generators to propose amendments to, or otherwise to challenge, the distribution connection charges on the grounds of discrimination.
(c)	It was not the purpose of TDR payments to compensate their recipients for this difference.
(d)	It is not the case that any perceived unfairness is incapable of remedy.  It can be addressed, for example, in the context of the Targeted Charging Review. 
155.	Again, looking in the round at the similarities and differences between transmission-connected generators on the one hand and small embedded generators on the other hand, I am satisfied that there is enough of a relevant difference between them to justify their different treatment after the Decision. 
(11) Summary
156.	For the reasons which I have given, this application for judicial review is dismissed.
157.	I repeat my thanks, which I expressed at the end of the hearing, to all solicitors and counsel involved in this case for their assistance in dealing with a considerable volume of material.