Energy Storage Application definitions and how these relate to the South African EDI policy, legislation and regulation:

Transcription

1 Energy Storage Application definitions and how these relate to the South African EDI policy, legislation and regulation: by Paul Vermeulen, City Power and Chairman, SAESA Policy and Regulation Work Group Electicity is unlike any other product in the world it is consumed at the instant it is created. In order to maintain stability, its supply must have a reserve margin and be perfectly matched to the demand at all times. This statement has been valid for over 100 years and remained unchallenged because of the common knowledge that electricity simply cannot be stored in the volumes that are required to service the grid. Until now, that is Energy Storage has arrived Energy storage has certainly come of age. The technology has reached a level of maturity that enables deployment at utility scale, the success of the Tesla battery in Australia (Renew Economy, 2017) is testament to this. Capable of delivering 100 MW with a capacity of 129 MWh, the system cost A$ 90 million. Based on Eskom s 11 kv Megaflex tariff, the value to a municipal distributor of having just one kilowatthour s worth of energy storage to use for tariff arbitrage is R1,57 per day. If the system works for the next 15 years shifting just that 1 kwh of demand from peak to off-peak excluding Sundays, it will save at total of R7395 in today s money terms. The savings will increase at the same rate that Eskom s prices increase, which will most likely be above inflation for several years to come. This means that any storage system that costs below US $400 per kwh already makes business sense to on arbitrage alone and any additional benefits realized are a bonus to the basic business case. The problem is that the concept is so new that the EDI in South Africa is yet to imagine the benefits it can bring and see how it fits into the evolution of the local distribution business. The IRP2018 modeling has unfortunately not taken into account the true value of distributed energy storage, particularly when it is deployed on a municipal distributor s network. New things do need new policies and regulation and these are things that do not yet exist in SA. A later look at the parameters that are used as inputs to the IRP modeling reveals that several of them are affected by distributed energystorage and all of them in a positive way Firstly, does it need a generating license from NERSA? Is it generation or is it DSM? While a storage system is designed to generate when it is in its discharge mode, it requires energy from a primary source when it is in its charging mode. It is rather a consumer of primary energy and not an energy source in itself. It simply changes the time that the primary energy generated is drawn from the system, put into storage and the time when it is released back into the system again - a very useful DSM feature indeed. Technically, when storage systems release energy back into the system, they are equivalent to generation. Within the context of the IRP, storage appears to be a direct alternative to gas peaking power. Storage technologies must logically be considered to be equivalent in that they serve the same need as peaking power. The extent to which they compare economically to gas generation must be examined. Where they are found to compare favorably using re-charge energy from other cheaper primary energy sources, the IRP should permit the reduction of the allocation of gas peaking plant in favor of energy storage. An energy storage system does have round trip losses typically around 15 % for lithium ion technologies. As generation, how is this to be valued? As equivalent to the cost of peaking plant? Or is it valued at the cost of the lowest cost available surplus plus an efficiency factor to account for the round trip losses? It seems

2 storage is a bit of a shape shifter, capable of taking on the identity of the cheapest available form of whatever primary energy source may be available, and that is its true generation value. Until the LCOE of wind or photovoltaics power drops below the cost of Eskom off peak power, energy storage would typically draw recharge power from the lowest off-peak tariff period and release the energy in the high cost periods. Large scale energy storage will for the foreseeable future utilize coal based energy to re-charge during off peak periods. A consequence of this is that an element of base-load coal (or other lower cost primary sources) will need to be retained for the recharging of the distributed energy storage fleet. It is only when a really high penetration of renewable energy is finally seen on our grids, that we will see zero cost or negative energy prices for renewable energy and will need to re-program the systems to store this energy. So, let s assume for now that energy storage is generation, and it is valued at whatever is the lowest cost charging source available plus the round trip losses of the system. Licensing Rrequirements The draft IRP2018 has a new category for embedded generation, with an allocation of 200 MW a year for the next 13 years a total of 2300 MW by The category includes both privately and municipal owned renewable energy systems, distributed gas powered generation and energy storage systems. At first glance, the allocation is far too small to cater for all of this. However, the point is that the systems in this category are to be covered by the Schedule 2 amendments of the Electricity Regulation Act, promulgated last November. In terms of the amendments, all facilities, including generation and storage with a capacity in the range of 0 to 1 MW will no longer require a generation license and are to be regulated through a registration process managed by the distribution system operators and overseen by NERSA. Those facilities that are in the capacity range 1 to 10 MW are subject to the NERSA lite licensing process and must be supported by a feasibility study that meets the stated criteria in the New Generation Regulations. Licenses issued in this range will no longer be subject to individual Ministerial dispensation. Energy storage systems deployed in the medium and low voltage distribution networks are most likely to be in the 0 to 1 MW range with fewer numbers in the 1 to 10 MW range. So, the licensing requirements for most of distributed energy storage, even if defined as generation, is not as onerous as it was before the Schedule 2 amendments were made. The issue however, is that the DoE and NERSA need to complete and publish the rules applicable to the registration and Licensing Light processes. Grid Code Compliance Even if no licensing or registration was required, it is generally accepted that anything connected to the grid should not negatively influence the expected quality of supply of grid power, and that a grid code is needed to set out the rules of engagement, so to speak, of how an energy storage system should interact with the grid. The closest code suitable for energy storage is the Renewable Energy Grid code this has a strong curtailment theme which applies to all forms of generation. However, storage needs the additional signal of what to do when there is a surplus of power to do the opposite and re-charge! With just a few basic amendments, the renewable energy grid code could accommodate embedded energy storage systems. The main focus of the Renewable Energy Grid Code is to describe the expected curtailment behaviour of the generating systems under conditions where there is an over-supply of power to the grid.

3 The code defines the over-voltage and over-frequency thresholds that trigger the curtailment of generation. The same will curtailment will apply to energy storage systems, even though their purpose is to generate only when there is a shortfall of generation and the voltage and frequency reduces. As far as storage is concerned, it is more important for the code to define the conditions under which re-charging must be curtailed to avoid storage being an unnecessary burden on the system. These additions to the Renewable Energy Grid Code still need to be made. The True Value of Energy Storage to the South African Electricity Distribution Industry The value of utility scale energy storage is increased the further down in the grid energy value chain it is placed. This is due to the increasing value or stacking of both technical and financial benefits as the storage facilities are located deeper into the network. For example, a 100 MWh storage system placed at a point on Eskom s high voltage transmission network can provide: A means to store surplus renewable energy at a national level, Avoid transmission network bottlenecks and Provide frequency support (reserve margin) for the national generation industry These are the only benefits that can be realized in the case the system is connected to the transmission network. However, if the same energy storage capacity of 100 MWh was deployed by strategically placing twentyfive smaller 4 MWh systems further downstream on the medium voltage distribution networks, not only could the abovementioned benefits still be realized, but the systems could add further value through: Energy purchasing arbitrage, The alleviation of distribution network bottlenecks and overloads The avoidance of Eskom Notified Maximum Demand Charge penalties, The deferment of network refurbishment or network upgrade capital expenditure Improvement of the power factor over the entire transmission and distribution networks Realizing a significant improvement in the security of supply for customers. Providing a measure of standby power to end customers as an alternative to expensive diesel power This increasing value effect or stacking is critically dependent on where in the network the storage system is located. The highest value of all to the end customer and the economy as a whole would be realized where these energy storage systems are strategically placed at the so called grid edge and designed to run as independent power islands or mini-grids to maintain supply to one or a group of end customers in the event of load shedding or other unplanned grid outages. Policy is required to guide this. This optimal location concept must be acknowledged if the full value of distributed energy storage is to feature in the IRP. It is simply the interconnectedness of the grid that enables all of the above-mentioned benefits to be realized even when the facilities are placed at the lower extremities of the grid. The realization of all of the stacked benefits is however subject to certain operational conditions. This includes operating the system every day for tariff arbitrage purposes. And, even if there is a strong correlation between the natural load peak and the pre-defined peak tariff periods, to realize the generation and transmission benefits, requires that overall control of the storage facilities is made available to Eskom as the National System Operator. With today s telecommunications systems, this is easy to establish. As mentioned before, tariff arbitrage is the practice of storing cheap off-peak energy for later release during peak times when the cost of energy is much higher. Table 1 shows the daily arbitrage value of 1 kwh s worth of storage to a municipal distributor (yellow highlight) when applied to an 11 kv intake point subject to the Eskom Megaflex Local Authority tariff for 2018/2019. The table shows the value over a whole year.

4 The table also shows the maximum cost of the energy storage system (pink highlighted value of R 5740 per kwh) for the business case for using the storage for arbitrage alone to be viable. The site will begin to generate a surplus where the actual cost of the storage system is below this figure. Analysis of break-even point of energy storage cost vs. maximum arbitrage potential of the Local Government Megaflex Tariff 1kWh Storage used for 6 days of the week, one shot per day, to shift 1kWh from peak to off-peak, all year round Plant Parameters Megaflex Tariff Application 11kV Intake point Technology Aspects Units Value Operational Aspects Energy Units Value Total Installed Cost of Storage System $/kwh 400 HV Distribution System Losses % 4,00% Storage System Specified Cycle Life Number 7000 MV / LV Distribution % 3,00% Efficiency of Charge and Discharge cycle % 85% Value of Winter Evening Energy Arbitrage c/kwh 246,84 Value of summer Evening Energy Arbitrage c/kwh 54,29 Capital Aspects Units Value Loss-less average value of daily arbitrage c/kwh 102,43 Rand to Dollar Exchange Rate Ratio 14,35 Average daily rate to re-charge system c/kwh 43,72 Local cost of Storage R/kWh 5740 Cycle cost to overcome system recharging losses c/kwh 8,14 Capital loan interest rate %pa 5,5% Cycle savings due shift of losses out of peak c/kwh 3,07 Capital Loan Term Years 10 Net average value of daily energy arbitrage c/kwh 97,36 Cost of Finance R/kWh Total financed plant cost R/kWh 7475 Operational Aspects Network and Demand costs Units Value Theoretical Plant Life, 6 days p/week, 1 cycle/day Years 22,4 Peak Period Duration hours 2 Storage Plant Expected Life Years 15 Demand reduction potential per kwh of storage kva 0,5 Charge / Discharge Cycles required Number 4693 Monthly network charge per kw r/kva 7,63 Monthly demand charge per kw r/kva 28,99 Daily network and demand charge savings potential c/kwh 60,23 * This savings is subject to the system being in operation during the annual half hour peak. LCOE over expected plant life, 1 shot per day c/kwh 159,29 Total potential daily arbitrage value of 1kWh storage c/kwh 157,59 Table 1 Indicative arbitrage only break even cost of storage at an 11 kv Megaflex intake point. Most municipal distributors exhibit a dominant morning and evening peak type of load profile, as they service many of the residential customers in the country. Many are also paying significant NMD penalties in areas where particularly low income residential development has taken place and the demand peaks above the agreed maximum with Eskom. While the peaky load profile creates the opportunity for the daily arbitrage financial savings to be realized by operating the systems to tariff periods, there is still a high probability of simultaneously realizing the national benefits together with the more localized network de-loading and NMD penalty avoidance benefits that storage can provide. In the case storage is deployed to avoid NMD penalties, the value of arbitrage can increase exponentially because of the punitive, compounding nature of the NMD penalty charges. In the case of the 11 kv intake point as shown above that exceeds its NMD in the three winter months, an additional savings of up to R1,80 per day per kwh of storage capacity used will accrue. This can deliver savings of millions of Rand a year on a relatively small intake point with an NMD of only 5 MW for example. The full realization of the stacked benefits requires that the storage facilities be located on the municipal distributor s side of the Eskom meter, and in the case where the municipal distributor passes on the time of use tariff to its customers, on the customer side of the municipal meter. A new potential new service and revenue stream can also be realized where, through negotiation with key customers to locate the storage facilities at their premises, the distributor can provide a measure of secure standby power to the customer in the event of network outages. This new service is possible because today s energy storage systems are designed to operate in an islanded or micro-grid mode. New agreements are needed to get this to work.

5 Quantifying the value of Energy storage in terms of the IRP parameter sheets The 2010 IRP used around thirty Parameter Input Sheets to define the inputs for the modelling system, used to solve for the least cost generation option for the country. In that IRP, there was only consideration of large scale hydro energy storage, and it was modelled under the very narrow objective of replacing peaking plant. It is unfortunate that the same appears to have been done for the IRP2018, and the modelling was done using a non-declining cost trajectory for the storage. As a result, the IRP simply left storage out of the solution. This is significant flaw in the process that should be corrected in the very next iteration of the model. The additional benefits discussed below should also be included in any future IRP modelling. The parameter definitions used in the IRP modelling that are affected by distributed energy storage are as follows: Distribution Infrastructure Expansion And Refurbishment There is reportedly a 70 billion Rand backlog in distribution infrastructure maintenance, a portion of which includes distribution network strengthening, often to service only short duration peak loads. This work involves the replacement of existing distribution infrastructure cabling, an expensive and disruptive activity. Optimally located energy storage can permanently avoid a significant component of this and can simultaneously provide a form of standby power for commercial consumers and protect the local economy in the event there is a grid failure or load shedding. The life of aging distribution infrastructure is also extended where the networks can be de-stressed through peak load reductions that energy storage will deliver. There may be a significant portion of the backlog that may be addressed using storage, bringing the additional benefit of daily tariff arbitrage to reduce bulk energy procurement costs. It is estimated that up to a third 23 billion Rand - of the backlog may be due to the need to upgrade network capacity to cater only for relatively short peaks. The question is what proportion of this backlog could storage deal with? Price Cone In the IRP2010, the price cone was defined as the average price of Eskom power to South Africa. This is not a true reflection of the price that the end user actually experiences and excludes any financially efficient measures that may be possible within the distribution networks not managed by Eskom. (Of all the medium voltage distribution networks in South Africa it is estimated that 60% of such is outside of Eskom, which is significant.) It is the municipal distribution industry that holds the bulk of the peaky residential loads in the country, and as of next year, all municipalities that purchase Eskom power for on-selling will only be able to purchase such power on a time of use basis. In effect, this inflates the municipal distributor s price cone as it is these residential peaks that are difficult to control and expensive to service when purchasing power on the Eskom Megaflex Local Authority tariff (to become Muniflex next year), in order to service these loads. The arbitrage value of energy storage is critical to a non-eskom distributor and aside from geyser control systems, is probably the only practical tool available to municipal distributors to avoid or limit exposure to Eskom peak energy pricing. In addition to a high exposure to peak energy prices, many municipal distributors are being heavily penalized by Notified Maximum Demand charges that could be reduced (or even avoided) where sufficient energy storage can be installed on their networks, downstream of the Eskom bulk supply meter.

6 It is ironic that Eskom currently finds itself in a position where as part of the loan conditions for their newly built coal stations, they are required to invest in around 800 MWh of energy storage in lieu of the Concentrated Solar Plant that they stopped on the basis that it was too costly. It is unfortunate that these storage assets will be placed on the Eskom networks only and hence will be of no benefit to the ailing Municipal distribution industry, nor bring any financial relief to Local Government. In the case of relieving NMD penalties by placing these facilities behind the existing Eskom meter and creating a virtual Eskom intake point further down in the network that still creates peak energy revenues for Eskom, an opportunity has been lost to deploy the 800 MWh of storage to the maximum benefit of South Africa as a whole. The IRP modelling needs to factor in that this storage, (notably not mentioned at all in the draft IRP2018), would have had maximum impact in the case where it is placed at the weakest points identified within the entire distribution system, including Municipal networks. No policy exists to otherwise guide this. If this benefit is taken into account, most of the facilities would likely be placed outside of the Eskom networks. The best for the country as a whole is probably the case where Eskom, with their technical capabilities, owns and maintains the facilities even if they are located on the non- Eskom networks, and they still earn peak energy revenues for Eskom but also eliminate the NMD penalties the municipalities are paying. Is it bad for business for one state owned entity to help another? Is this perhaps an opportunity to help break the debt cycle that many municipalities find themselves in? Cost of unserved energy In terms of protecting the economy, the best location for South Africa s energy storage assets, whether they be privately or utility owned, is to place the facilities on the customer s premises and to run them as power islands in the event of grid outages or the need to shed load arises. This will help to keep the economy going by providing a degree of resilience to these customers while maintaining revenues for the distributors while they restore their grids or comply to load shedding directives. In times of constraint, to reduce demand in the past, Eskom initiated power buy-back initiatives, in effect paying large industrial customers not to consume power. This was not a well-supported initiative, it effectively shut down a portion of the economy as those businesses simply closed shop. If it is assumed that those businesses were to gain access to large scale storage systems, they could participate in a demand response program that would have the same effect but allow economic activity to continue as normal. The contribution that storage could make in reducing the cost of unserved energy can be estimated by multiplying the generally agreed figure of R70 per kwh multiplied by the distributor s SAIDI performance indicator for that part of their network. The modelling should take this location benefit into account, and not simply regard storage as an alternative to transmission connected peaking plant, as is more the case for large scale pumped storage. Demand And Consumption Forecast The EDI certainly has seen a reduction in volumes of energy sold over the last decade but has not necessarily seen a corresponding reduction in instantaneous maximum demand. Some distributors have seen an increase in peak demand, hence the increasing NMD penalty trend, particularly where significant electrification programs in low income residential suburbs have been rolled out. While the IRP can be viewed as a generation plan for the country, it is equally important to also use it as a distribution network plan.

7 While overall energy demand will eventually turn and grow again, network capacity is needed right now to deliver the power, the profile of which is becoming more peaky as the country s universal access to electricity plans progress. Increasing urbanization, with its characteristic peaky load is expected to continue, as is densification due to residential redevelopment (town house complexes) and the backyard shack phenomenon. Of relevance here is peak demand growth, its impact on existing networks and how strategically placed energy storage can manage and reduce the costs associated with this type of growth and solve the backyard shack problem. Demand Side Management Energy storage systems are very powerful DSM tools as they can behave as both scheduled loads and as scheduled energy sources. As a result, they will also enable the establishment of a very effective demand response programs between Eskom and Municipal Distributors and similarly between Municipal Distributors and their large customers. Such a program would be a cheaper option than investments in yet more gas fired peaking plant, and will become ever more relevant as more and more non-dispatched renewable energy gets connected to both Eskom s and the municipal grids. It is not unreasonable that a municipal distributor should aspire to be in a position to control at least 10% of its peak demand liability using energy storage systems, specifically to manage the winter evening peak demand. It is also not unreasonable for a distributor to develop a fleet of storage facilities, sufficiently large to mitigate at least stage one load shedding going forward, particularly as it is becoming evident that the future prospect of load shedding cannot be ignored. The key issue here is that energy storage is only a DSM tool when it is placed on the Demand Side of the meter, and this is where its value truly lies. Generation Location (Although this was not included in the 2010 IRP it is now relevant) This parameter has relevance to small scale embedded generation plants, and whatever allocation the IRP makes in terms of this category of generation. It is likely that a fair component of storage will come into being together with SSEG renewable energy facilities. In the case of these systems, the energy produced is free of transmission losses as well as distribution losses down to the 400 Volt level, a benefit that should be considered. This is significant because the combined transmission and distribution losses that are avoided by placing the energy source right at the load can be as high as 18%. This parameter now has relevance as so many new options are available to end consumers, and there is likely more than 300 MW of SSEG already on the country s networks as we speak. While energy storage systems are net consumers of energy because of their charge and discharge losses, their ability to reduce cable losses (proportional to the square of the current flowing) during peak loading as well as an ability to do power factor correction is of significant new value. So, regardless of whether or not it is coupled to a renewable energy source, a substantial component of storage on a distributors network when used every day for arbitrage, also has the effect of reducing technical losses by reducing the peak current flows from the Eskom intake point to the point of final distribution and provides power factor correction that further reduces these losses. The deeper into the network the system is installed, the greater the benefit, and that must be taken into account.

8 Own Generation (Originally applied to large users but should also now include SSEG). Large consumers such as shopping centres, office parks and hospitals are making significant investment in rooftop photovoltaic systems and are successfully reducing their energy costs by doing this. While this has the effect of reducing the revenues of utilities, it reduces costs to business and assists them in being competitive, a benefit to the economy as a whole. This works well for consumers for example with loads such as air conditioning that correlate well with solar PV production. In these cases, self-consumption is maximized, and the renewable energy investor realizes the full benefit of the investment. In cases where the correlation is poor, an energy storage system can be used to optimize the investor s selfconsumption. Coupled with an appropriate time of use tariff that signals the investor to self-consume the stored energy during peak periods to the benefit of themselves as well as the local distributor. This is a winwin situation. There is a growing international trend (California and China for example), where regulatory permission to invest in renewable energy systems, particularly for photovoltaics, is conditional to a corresponding investment in a component of energy storage, which is made available for the utility to dispatch to manage energy flows. This may be one of the policy options we as South Africa would like to consider and now is the time to act on it. Renewables While the most obvious benefit of a private renewable energy investor optimizing the self-consumption on a privately-owned renewable energy system has already been mentioned, what is perhaps not as obvious is the concept of scaling this up to a Municipality or City-wide level. Should the updated IRP make an allocation for municipal owned (or municipally contracted) renewable energy connected directly to their grids, then the ability to make a portion of that energy dispatchable using energy storage facilities will be of significant benefit to municipalities as a tool to reduce the cross subsidy required for the low-income residential sector. Energy storage will alleviate the expensive ramp-rate issues that the inevitable duck-curve that will develop in South Africa as more and more photovoltaic renewable generation is connected to the grid. Conclusion The generic applications of storage are commonly named internationally and include terms such as frequency support, capacity firming, curtailment minimization, investment deferral, peak shaving, arbitrage and optimizing investment in renewable sources. While the same fundamental principles still apply in the South African environment, it may be better to describe the applications of energy storage in themes that the local electricity distribution environment can better relate to. So, Protecting the economy equals curtailment minimization. Increasing self-consumption of own generation equals optimising renewable energy investment Preserving distribution infrastructure equals peak shaving Load shifting and NMD penalty avoidance equals tariff arbitrage Support for densification and solving the backyard shack issue equals capacity firming

9 Unlocking stalled investment and the provision of free basic energy services may be specifically South African issues that energy storage can solve. Within each theme, new policy, legislation and regulation is likely required and these need to be investigated, created or adapted to enable the development of this exciting new industry. Contact Paul Vermeulen, City Power Johannesburg, Tel (011) ,