Written evidence submitted by the UK Demand Response Association (UKDRA) (EDM0014)

The UKDRA represents the Demand-Side Response (DSR) industry of the UK. Our members identify the flexibility in electricity-consuming and generating processes at industrial and commercial (I&C) sites, and aggregate this to provide real-time reserve services to the GB Transmission System Operator, National Grid, and distribution network operators.

Using this model, DSR has grown from a negligible volume in 2008 to a resource large enough to displace at least one major coal power station in 2014.  Around 20% of FTSE100 companies are involved in DSR, mostly through UKDRA members. 

Executive summary

• Demand-Side Response (DSR) is a low-carbon, diverse and highly flexible resource with multi-gigawatt potential.  Given full market access, DSR can substantially reduce customer bills, increase networks security and reduce carbon dioxide emissions.  By reducing Capacity Market (CM) auction prices by only £1/kW, DSR would save consumers £50m each year.
• Despite progress made since 2008, DSR faces barriers in current market arrangements.  Both Demand-Side Balancing Reserve (DSBR) and the CM will fail to deliver the full potential of DSR due to problems in the detailed design of the schemes.
• DSBR suffers from payment restrictions which will hold back investment, and is at risk of delivering a poor quality of resource due to the ineffective testing regime.  Many DSR resources are ruled out of the programme.  DSBR is adversely affected by competitive advantages bestowed on fossil-fuelled power stations.
• The laudable intentions of the Capacity Market with respect to DSR are undermined by the details of the scheme.  In particular:
• DSR is restricted to one-year contracts, while power stations can access longer contracts;
• The Transitional Arrangements (TA) are exclusive, preventing DSR from accessing other contract types which are essential for investment;
• DECC’s method for recovering CM cost from consumers removes a powerful additional price signal which could stimulate much wider growth in DSR, and instead stimulates long periods of running of diesel generators regardless of stress in the electricity system;
• The CM fails to recognise the vital importance to the security of today’s electricity network of DSR’s role in reducing winter peak demand, and instead provides a perverse incentive which will reduce, not increase, system security;
• The CM completely excludes combined heat and power (CHP) generators below 2MW in size, a resource of several hundreds of MW.
• We are concerned that the problems in the CM will affect the crucial early auctions to such an extent that electricity consumers will be forced to pay for fossil-fuelled power stations which they do not need.  This will lead to higher bills, unnecessary CO2 emissions and stifled innovation.  Rapid action by DECC could reverse this situation, resulting in lower bills, less pollution and a benign environment for innovation.

Potential of DSR

1. There is a clear role for the demand side to contribute more to system security.  Demand flexibility provided by industrial and commercial (I&C) customers is particularly valuable as intermittent renewable generation grows and new nuclear stations are constructed in large, inflexible units.  DSR is a cheaper and lower-carbon source of reserve and frequency response than fossil-fuelled power stations[1]. It is also possible for I&C customers to increase consumption at times of oversupply of renewable generation by moving production processes to different time periods.
2. DSR aggregators currently use a mixture of combined heat and power (CHP) generators, flexible load and standby generators to provide services such as Short Term Operating Reserve (STOR[2]).  Small hydro generators and energy storage also play a minor part.  Despite operating restrictions, CHP sites are regularly used by National Grid to fine-tune demand, and provide the largest volume of DSR in terms of energy delivered.  The total capacity potential for such active use of CHP is close to 1GW[3].  Standby generators are generally used only for the periods of highest stress, but their capacity potential is in excess of 10GW – far more than National Grid needs in this category.  Flexible load is a less mature resource, but estimates of its potential range from 1–3GW.

Are the Government’s and Ofgem’s current proposals for incentivising the development of demand reduction measures enough to ensure the potential energy savings outlined in the 2012 Energy Efficiency Strategy are achieved?

3. We draw a distinction between permanent beneficial demand reduction, and active management of demand to reduce short-term stress.  The former is energy efficiency, and includes the Electricity Demand Reduction (EDR) pilot.  The latter is DSR.  The UKDRA concentrates on DSR, but our members have strong experience in energy efficiency. 
4. Energy efficiency and DSR go hand-in-hand, for three reasons:
1. Control technologies that improve energy efficiency in industrial and commercial operations can also deliver DSR, and vice-versa.  This double business case supports investment in energy projects.
2. DSR makes energy consumption an active process, increasing awareness of energy spend in an organisation and kick-starting energy efficiency projects.  Some industrial customers have used DSR revenue to fund investment in energy efficiency.
3. DSR increases efficiency in the electricity generation sector, by reducing the need for wasteful part-loading and hot standby at fossil-fuelled plant, helping the system to absorb renewable generation, and reducing distribution losses.
5. Our answer to the question posed is “no” – the potential for demand reduction, estimated at the equivalent of 22 power stations, will not be delivered by current proposals.  As a DSR organisation, we restrict our specific comments to DSR; these are given below.  In general, despite our members’ engagement with energy managers across the UK, we do not see substantial take-up of the various energy efficiency schemes.

How will National Grid’s new Demand Side Balancing Reserve (DSBR) enable demand-side response (DSR) to play a positive role in avoiding capacity shortfalls in the coming years?  What improvements to the scheme are required?

6. DSBR is temporary, and as it bears no similarity to the capacity market (CM), it cannot be seen as a transitional phase into the CM.  DSR resources require investment, which requires continuity in the programmes which generate the return.  Starting the transitional arrangements (TA) for the CM one year earlier, or simply extending National Grid’s existing STOR programme, would support DSR investment far more effectively than DSBR.

7. DSBR will run first as a small pilot and then competitively alongside Supplemental Balancing Reserve (SBR), which is exclusively for existing power stations.  The competitive phase will be largely contracted before the pilot has operated, which limits the potential for learning from the pilot.

8. We do not believe that the current design of DSBR will achieve either the capacity or the quality of delivery which a better-designed scheme could deliver.  We are also concerned that large power stations are favoured over DSR in the design of the DSBR and SBR schemes.  We believe the following modifications are necessary:

1. The balance between set-up (availability) fees and utilisation fees should be adjusted towards the former, following evidence from international demand response markets[4]. Utilisation revenue is contingent on unlikely events, so utilisation fees are not a bankable proposition and will not unlock investment.  Set-up fees are bankable but are low in the context of a temporary scheme with uncertain longevity.  Lower utilisation fees and higher set-up fees would improve the investment signal.

2. The lowest DSBR utilisation prices are above the current market, and the highest are in ranges beyond any recent experience.  There will therefore be few if any utilisations.  Since National Grid intends to test only a sample of DSBR sites, there is a substantial risk of unreliable or impractical resources achieving DSBR contracts, receiving payments, yet providing no system security.  This consideration favours the rebalancing of payments mentioned above.

3. There are significant competition issues in DSBR and SBR.  DSBR resources must opt for either no set-up fee, or a fixed fee.  The former has no value (because utilisation fees are unlikely to be paid) while the latter could make DSBR uncompetitive with SBR, in which providers have freedom to tender any price.  In fact, aggregated DSR is now capable of meeting all of the essential technical requirements of SBR, but is nevertheless excluded from it.  These anomalies are anti-competitive, and should be removed from the two schemes.

4. The proposed baseline method excludes new sites, sites that have invested in new processes, and potentially some generation.  It will also tend to exclude sites that have previously offered flexible STOR, as STOR calls tend to fall on high demand periods, giving a zero baseline.  National Grid has cited no precedent in selecting this baseline method.  However, methods such as the “X of Y” approach used in Low Carbon London[5] and various US demand response markets[6], have a long history and substantial historical analysis to support their validity and guide their application.

DSBR excludes sites practising triad management from DSBR.  Triad management is where users reduce their demand in winter peak periods in order to reduce the charges they pay for the use of the electricity transmission system. It is a long-established and well-understood programme which reduces national winter peak demand by at least 1.2GW. 

National Grid excludes triad management as it wishes to encourage “new” resources.  Disregarding the question of how many resources would genuinely prefer the lower value of DSBR, it does not benefit the consumer to create mutually exclusive programmes (DSBR versus triads, or indeed CM versus triads).  Lowest cost to the consumer is achieved by removing restrictions to participation in programmes, allowing more versatile resources to create compound business plans from multiple revenue sources.  This drives investment towards most cost-effective DSR overall.  UKDRA members are aware of industrial consumers which are presently contemplating the relative merits of triad management and DSBR.  If DSBR draws resources away from triad management, it will have the perverse effect of raising winter peaks above the level they would otherwise have reached.  This will cost the consumer more without increasing security.

The obvious alternative is to select a baseline method which permits triad management.  Coupled with greater freedom to select DSBR set-up fees, this would maximise the efficiency of procurement of system adequacy in the coming winters.

What problems (if any) are there with the proposed Capacity Mechanism (CM) Transitional Arrangements (TA) in relation to DSR? To what extent does participation in the TA limit the future potential of DSR in the CM?

9. We applaud the Government for recognising the importance of a transitional mechanism that will better position DSR for competitive participation in the CM.  There is precedent for this approach: transitional mechanisms in other markets[7] have led to robust participation of DSR in enduring capacity markets.  We support the Government's objectives for the TA: providing additional energy security in the crucial years before new generation can be built, and helping the market to gain more familiarity with DSR in the UK.
10. However, DECC's plan for transitioning between the TA and the CM is flawed by an exclusionary barrier that nullifies the benefits of the TA to the industry and to GB consumers.  This will increase electricity bills, and will increase the proportion of CM revenue going to fossil-fuelled power stations.  The reasons are as follows:
1. DSR gaining a contract in the main (T-4) capacity auction[8] this December (for capacity delivered in 2018/2019) cannot participate in the TA.  The same exclusion is repeated for the second main auction (and would be repeated thereafter if the TA were to be extended).   
2. Because every successful bidder is paid the same price, every megawatt participating in the CM auction below the cost of new power stations reduces the cost to consumers.  DSR is an extremely economic resource with multi-gigawatt scale potential, and can thus displace several power stations.  However, the exclusion means that fewer DSR providers will participate in the first two main auctions, forcing consumers to pay for more new-build power stations than are actually needed.
3. DECC's approach for transitioning DSR from the TA into the CM is via much smaller “top-up” (T-1) auctions.  However, as most capacity will be procured in the main (T-4) auctions, consumers will already be locked into unnecessary capital expenditure over long periods.  For each £1/kW by which DSR reduces the main auction clearing price, consumers will save approximately £50m per annum.  In contrast, reducing the top-up auction clearing price by £1/kW will save only £1.5m. 
4. Additionally, by locking consumers into paying for high-carbon power stations over long periods in those first two main auctions, DECC is preventing the emergence of innovative consumer demand solutions.
11. In summary, preventing demand response providers from participating in both the TA and the main (T-4) CM auctions will increase consumer costs, reduce energy market competition and slow the move to the smart grid. This restriction should be removed from the Capacity Market Rules as soon as possible.
12. DSR faces an additional barrier: it is only able to bid for a one-year contract in any auction, unlike power stations, which may offer up to 15 years.  This is a clear case of different treatment.  Clearly, DSR which could amortise its costs over longer periods could bid a lower price.  This would increase the proportion of DSR accepted and reduce costs to consumers. 

How can the Government ensure that new technology which facilitates DSR is deployed in a timely manner, now and in future, to reduce peak demand for electricity?

13. Encouraging innovation requires recognition that Government does not hold all the answers, but it has a clear role to play in ensuring a level playing field for new entrants.  Creating markets with open access to new technologies is crucial to delivering cost-effective policy results. DSR is a new technology which can solve existing challenges at lower cost and lower carbon. Other technologies, including energy storage, may also emerge given adequate opportunities.  Ensuring that incumbent, more costly solutions are not allowed to freeze out competition through regulatory or size barriers should be a clear policy objective.
14. The CM as it currently stands supports entrenchment of traditional fossil-fuelled power stations.  Addressing the issues cited herein would reverse the situation, allowing substantial innovation in DSR and other areas to generate economic and environmental benefits for consumers.
15. Innovation in electricity technologies has been hindered by structural problems in energy markets for decades.  Government and regulators should continue to address the level of competiveness and liquidity in electricity markets.  Government should not rely on vertically-integrated energy companies to deliver or even facilitate innovation, but should instead look to those sectors where innovation has occurred, and seek to facilitate its emergence into the mainstream.

What problems (if any) are there with the proposed Energy Demand Reduction (EDR) pilot scheme? How should the Government ensure that the pilot provides sufficient evidence to assess the viability of a long-term EDR scheme (including in the forthcoming CM)?

16. We support the inclusion of permanent reductions in electricity use in the CM, although we believe that there are significant risks in EDR.  The greatest are the verification of the reduction in demand actually achieved, and the danger of demand destruction.  For this reason we support the use of a pilot scheme. 
17. Like DSR, EDR is a highly technical area, and success depends on proper understanding of details and of the practicalities of industrial energy use.  DECC must consult fully and openly as EDR develops, and pay heed to the experience and advice of organisations working directly with industrial and commercial energy users.  Such an approach applied earlier would have reduced the barriers to DSR, and it is important that DECC learns this lesson as it considers EDR.

How will the Government’s latest detailed design proposals for the forthcoming CM help to develop an enduring regime for demand reduction measures? 

18. The CM as it presently stands will fail to deliver the full potential for energy efficiency or DSR.  The following improvements would enable it to do so:

1. Contract duration: DSR, large power stations, EDR and energy storage should all be able to tender for long-duration contracts if the providers wish to do so.  Artificial limits, such as per-kW capital spend thresholds, or direct exclusion such as applies to DSR, distort competition and lead to higher auction clearing prices.  These should be removed.
2. Transitional arrangements: DSR should be allowed to participate in all auctions without exclusion.  The TA will bring forward capacity much earlier than can be achieved by new-build power stations. From a consumer benefit perspective, the objective should be to make use of this early investment in DSR, as this will be more cost-effective than moving back to traditional power stations – which could happen unless the main auctions are fully open to DSR. Furthermore, it is a design principle of the CM that allowing different capacity resources to gain revenue from multiple sources (reserve services, energy markets, CM, etc) will result in the most efficient procurement overall and the lowest ultimate cost for consumers.  DSR is already largely excluded from energy markets by competition and liquidity issues; further exclusions add to the barriers and lead to higher consumer bills.
3. Cost recovery: DECC should revert to its original method of cost recovery, which was based on the well-proven triad system.  This preserves a strong price signal for winter peak reduction without subsidising excessive running of diesel generators.
4. Transmission and distribution costs: DSR reduces energy losses in electricity networks and, by reducing peaks, also reduces the capital and operational cost of such networks.  The capacity market does not recognise these additional benefits which DSR can bring but which large power stations cannot.  By ensuring that baseline methods do not prevent triad management, and by preserving the triad price signal in the cost recovery method, DSR would be incentivised to further improve the efficiency and cost-effectiveness of electricity networks.
5. Combined Heat and Power (CHP): Small CHP generators cannot participate in the capacity market, as the baseline methodology excludes them from aggregation, and the 2MW size threshold excludes most CHPs at hospitals, hotels, universities, leisure centres and district heating schemes.  This should be addressed as a matter of urgency.

We would be happy to present evidence at a verbal inquiry and should you have any questions on this submission please do not hesitate to contact us.

Annex: Environmental benefits of using DSR to provide reserve and frequency response services – selected references

1. Security and Quality of Supply Standard Amendment, GSR007 - National Grid, February 2009

http://www.nationalgrid.com/NR/rdonlyres/EEEB8EDB-6AA5-4D44-BFDC-763ECE251E73/31739/SQSS1320Reportfinalv10_040209_.pdf

Example calculation on page 51 estimates additional CO2 for holding of frequency reserve by considering inefficiency of de-loading power stations.  De-loading is used to provide response, reserve and margin from large power stations. 

2. The carbon costs of system balancing – Flexitricity

http://www.flexitricity.com/docLibrary/30041-04%20Carbon%20costs%20of%20system%20balancing%201-1.pdf

Simple explanation of the effect of providing reserve using fossil-fuelled powers stations versus DSR.

3. Reducing the costs of system intermittency by using Demand side control measures – DTI, 2006

http://www.flexitricity.com/file/56721004-01%20DTI%20Demand%20Side%20Flexibility%20DTI%20format.pdf 

Study for the DTI by Flexitricity, IPA Economics and Econnect estimating the potential and CO2 reduction benefit of providing operating reserve from various demand-side resources.

4. DYNAMIC DEMAND Government Response to Clause 18 of the Climate Change and Sustainable Energy Act – BERR, August 2007

              http://webarchive.nationalarchives.gov.uk/+/http://www.berr.gov.uk/files/file41011.pdf

Estimates potential CO2 reduction for dynamic demand in the UK is around 2m tonnes, not including all types of reserve.

5. NGC Experience With Frequency Control In England And Wales - Provision Of Frequency Response By Generators – Erminez, IA, Bickers, DO, Wood, GF, Hung WW, 1998

http://ieeexplore.ieee.org/xpl/login.jsp?tp=&arnumber=747521&url=http%3A%2F%2Fieeexplore.ieee.org%2Fiel4%2F6033%2F16105%2F00747521.pdf%3Farnumber%3D747521 

“The costs of the frequency control services are additional costs based on additional inefficiency losses and maintenance/ageing effects incurred when providing the service. A typical inefficiency cost on conventional steam plant, due to heat-rate changes resulting from throttling steam pressure across governor valves and additional auxiliaries, is shown by Figure 6. These efficiency losses were confirmed by discussions with plant efficiency engineers and in reference 8.”

July 2014