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England and Wales High Court (Administrative Court) Decisions
You are here: BAILII >> Databases >> England and Wales High Court (Administrative Court) Decisions >> Peak Gen Top Co Ltd & Ors, R (on the application of) v The Gas And Electricity Markets Authority & Anor  EWHC 1583 (Admin) (22 June 2018)
Cite as:  EWHC 1583 (Admin)
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QUEEN'S BENCH DIVISION
Strand, London, WC2A 2LL
B e f o r e :
| The Queen
on the application of
Peak Gen Top Co Limited and others
|- and -
|The Gas and Electricity Markets Authority
- and -
National Grid Electricity Transmission Plc
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
Crown Copyright ©
Mr Justice Lavender:
(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.
(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
(2)(a) The Transmission Network
(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.
(2)(b) The Distribution Networks
(2)(c) Electricity Generators
(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.
"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."
(2)(d) Electricity Suppliers
(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.
"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."
"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;"
"(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."
(4) Relevant Charges
(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.
(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).
(4)(a) Allowed Revenue
(4)(b) TNUoS Charges
(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.
(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.
(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
(4)(d) TNUoS Generation Charges: the TGL Charge
(4)(e) TNUoS Generation Charges: The TGR Charge
(4)(f) TNUoS Demand Charges: The TDL Charge
(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.
(4)(f)(i) Suppliers' Net Demand
(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.
(4)(f)(ii) The Transport Model
"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."
"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. …."
(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.
(4)(f)(iii) Issues concerning the TDL Charge
(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.
(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.
(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
(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.
(4)(h) TDR (and TDL) Payments
(4)(i) BTMG and DSR
(4)(j) Connection Charges
(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.
(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.
(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
(5) The Decision
(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.
(6) The Consultation
(6)(a) Powers and Procedures
(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.
(6)(b) The CMPs and the Open Letter
"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."
"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 …"
"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."
(6)(c) The Workgroup
"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."
(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"
(6)(d) The NERA Report
"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."
(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.
"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."
"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."
(6)(e) The Panel
(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.
- 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.
(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.)
(6)(f) The "Minded to" Letter
(1) £2.1billion in savings in system costs; and
(2) £7.4billion in savings in consumer costs.
"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?"
(6)(g) The Targeted Charging Review
(6)(h) The Summary of Arguments
(6)(h)(i) The Summary of Arguments: The NERA Report
"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
"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).
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
"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."
"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
(7)(a) Problem Definition
"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."
(7)(b) Available Options
(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.
(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
"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."
"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."
"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."
"WACM4 leads to a consumer saving in the years to 2024 of £2.2bn, and £7.5bn in the years to 2034."
(8) The Claimants' Grounds
(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.
(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.
(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
(9)(a) Ofgem's Alleged Misunderstanding
(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.
"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."
(9)(b) Ofgem's alleged Failure to Investigate
(9)(c) The SQSS Argument
(10) Unlawful Discrimination
"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  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  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.""
(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)  E.C.C. 314, at paragraph 26; Everything Everywhere Ltd v Competititon Commission  EWCA Civ 154, at paragraphs 35-39; and R. (Gallaher Group Ltd) v Competition and Markets Authority  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  STC 1072;  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)  ECR I-9481, at paragraphs 40-42; Revenue and Customs Commissioners v Rank Group Plc  ECR I-10947, at paragraphs 59-64; and R. (Gallaher Group Ltd) v Competititon and Markets Authority  EWCA Civ 719, at paragraphs 52-59).
(10)(a) Discrimination: Context
(10)(b) Discrimination: BTMG and Commercial DSR
(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.
(10)(c) Discrimination: Transmission-connected Generators
(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.
(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.