Analysing the Value of Pumped Storage in the 2020 Irish Power System. Aidan Cummins, Luke Dillon

Transcription

1 Analysing the Value of Pumped Storage in the 2020 Irish Power System Aidan Cummins, Luke Dillon

2 Department of Civil & Environmental Engineering BE (Energy Engineering) Module NE4020 Final Report Analysing the Value of Pumped Storage in the 2020 Irish Power System Aidan Cummins Luke Dillon Date of Submission: 27 th March 2013 i

3 1. Executive Summary By the year 2020, the levels of wind generation capacity on the Irish power system will have more than doubled in order to achieve the 40% renewable electricity generation targets imposed on the country. The unpredictability and intermittency of wind generation will pose significant challenges to the transmission system operators, demanding a more flexible power system to ensure security of supply and grid stability. Pumped Hydroelectric Energy Storage (PHES) is the sole method of largescale energy storage, and is suggested by many as the ideal method of integrating the 4,800-5,300 MW which transmission system operators EirGrid predict will be required to meet the aforementioned targets. The objective of this research project is to investigate the benefit PHES offers not just the operation of wind generation, but the 2020 Irish power system as a whole. The following research questions were posed in order to achieve this objective: What benefit does PHES have for the operation of the 2020 Irish Power System? Does the Irish power system need another PHES plant? Would a new PHES plant represent an attractive investment to private investors in the liberalised Single Electricity Market? To answer these questions, the 2020 Irish power system was modelled using the PLEXOS power system modelling software. The operation of the Irish power system for the year 2020 was simulated for three different scenarios of PHES capacity, as outlined in Section 9. Simulation results make clear that PHES offers technical and economic benefits to the Irish transmission system and Single Electricity Market by reducing plant generation costs and energy prices, wind curtailment and CO2 emissions. The addition of the a new PHES plant to the system was seen to add further benefit in these areas, however an economic feasibility analysis on the new plant found that a prolonged payback time due to high capital costs made PHES plants an unattractive investment opportunity for private investors in the liberalised Single Electricity Market. Overall, the benefit of PHES to the 2020 is evident and the addition of a new plant can certainly be justified from an operational standpoint, however the high capital costs cannot be overlooked by private investors. The future addition of a new PHES plant will therefore be dependent on investors willing to overlook high capital cost or the involvement of system operators. ii

4 2. Declaration The Authors hereby declare that this final report is of their own work and that it has not been submitted elsewhere for any reward. Where other sources have been used, they have been acknowledged. Signatures: Aidan Cummins Luke Dillon Date: 27/03/2013 iii

5 3. Acknowledgements This project was conceived the authors after gaining an interest in the area of power systems operation from working in the Irish power industry for the summer of First and foremost, we would like to thank Paul Deane for accepting the supervisor role of our project and his continuous support throughout the research duration. We would also like to thank Jim Cronin and Ken Oakley for their input and consultation. We would like to thank EirGrid and SEMO for the provision of system data which was necessary of the report. We would like to also thank Energy Exemplar for their PLEXOS software. Finally, we would like to thank Paul Leahy and University College Cork for the coordination and support of our final year research projects. iv

6 Table of Contents 1. Executive Summary... ii 2. Declaration... iii 3. Acknowledgements... iv Table of Figures... viii Table of Tables... ix 4. Introduction The Single Electricity Market: A Review Introduction Market Operation Generator Unit Payments & Charges Trading Payments Capacity Payments PHES in the SEM PLEXOS Software Review Historical Data Introduction Turlough Hill Data Acquisition Normal operation Interconnection System Overview System Operation Ireland Model Simulation Resolution & Duration System Load Generator Unit Properties & Dispatch Fuel Costs, CO 2 Production and Tax Rates Wind Generator Units Outages PHES in the Model System Generation Capacity Interconnection & Great Britain Generation Reserve Provision v

7 8.11. Network Constraints System Non-Synchronous Penetration Dublin Generation Inertia NI Inertia ROI Kilroot Coal Moneypoint South West Generation PLEXOS Modelling Methodology PLEXOS Modelling Results Operations Model (IC Free) Total System Generation and Costs System Marginal Price Conventional Plant Operation Interconnector Flow Emissions Wind Curtailment PHES in the System Operations Model (IC Fixed)... Error! Bookmark not defined Total System Generation and Costs System Marginal Price Conventional Plant Generation Interconnector Flow Emissions Wind Curtailment Pumped Storage in the System Market Model Total System Generation and Costs Interconnector Flow Emissions Wind Curtailment Pumped Storage in the System Carbon Tax Sensitivity Total Generation Cost vi

8 System Marginal Price Emissions PHES in the System Reduced Interconnection Scenario Total System Generation and Costs Conventional Plant Operation Wind Curtailment PHES in the System Conclusion Conclusion and Future Work Works Cited Appendix 1: Logbook Week 1: Oct 8 th Week 2: Oct 15 th Week 3: Oct 22 nd Week 4: Oct 29 th Week 5: Nov 5 th Week 6: Nov 12 th Week 7: Nov 19 th Week 8: Nov 26 th Week 9: Dec 3 rd Week 10: Dec 10 th Week 11: Jan 7 th Week 12: Jan 14 th Week 13: Jan 21 st Week 14: Jan 28 th Week 15: Feb 4 th Week 16: Feb 11 th Week 17: Feb 18 th Week 18: Feb 25 th Week 19: Mar 4 th Week 20: Mar 11 th Week 21: Mar 18 th Week 22: Mar 25 th vii

9 Table of Figures Figure 5.1: Merit Order allocation [20]... 5 Figure 5.2: SMP in relation to System Load (data from 5 Figure 5.3: Annual SEM Value (data from 6 Figure 5.4: Distribution of monthly pots [27]... 8 Figure 7.1-Turlough Hill TH2 Generation over a typical week Figure 7.2: Turlough Hill Generation per unit Figure 7.3: Interconnector Imports Figure 7.4: System Capacity Figure 7.5: System Capacity Figure 7.6: System Generation TH Online Figure 7.7: System Generation TH Offline Figure 8.1: All-Island Fuel Mix Figure 10.1: Total System Generation Costs Free IC Figure 10.2: Total System Generation Breakdown (GWh) Free IC Figure 10.3: Generation Cost By Category Free IC Figure 10.4: Generation By Category Free IC Figure 10.5: SMP Annual Profile ( /MWh) Free IC Figure 10.7: Gas peaker unit dispatch decreases with PHES capacity increase Figure 10.8: Generator Cycling By Category Figure 10.9: Moneypoint Time Spent Ramping Free IC Figure 10.10: Interconnector Flow Free IC Figure 10.11: Emissions By Sector Free IC Figure 10.12: Wind curtailment Factor Free IC Figure 10.13: PHES Generation (GWh) Free IC Figure 10.14: Payback Period Free IC Figure 10.15: Total Generation Costs Fixed IC Figure 10.16:Total System Generation Breakdown (GWh) Fixed IC Figure 10.17: Generation Cost Breakdown By Category Fixed IC Figure 10.18: Generation By Category Fixed IC Figure 10.19: SMP Annual Profile ( /MWh) Fixed IC Figure 10.20: SMP Annual Profile ( /MWh) Fixed IC vs. Free IC Figure 10.21: Generator Cycling By Category Fixed IC Figure 10.22: Moneypoint Ramping Time Fixed IC Figure 10.23: Interconnector Flow Fixed IC Figure 10.24: Emissions By Sector Fixed IC Figure 10.25: Wind Curtailment Factor Fixed IC Figure 10.26: Wind Farm Losses Fixed IC vs. Free IC Figure 10.27: PHES Generation (GWh) Fixed IC Figure 10.28: Payback Period Fixed IC Figure 10.29: Total System Generation Costs Market Model Figure 10.30: Total System Generation Breakdown (GWh) Market Model viii

10 Figure 10.31: Interconnector Flow Market Model Figure 10.32: Emissions By Category Market Model Figure 10.33: Wind Curtailment Factor Market Model Figure 10.34: Wind Farm Losses Base vs. Market Model Figure 10.35: PHES Generation Market Model Figure 10.36: PHES Payback Period Base vs. Market model Figure 10.38: System Generation For Carbon Tax Sensitivity Figure 10.39: Relationship between Gas and Coal dispatch and carbon tax Figure 10.40: Relationship between SMP and carbon tax Figure 10.41: Relationship between CO2 emissions and carbon tax Figure 10.42: New PHES cumulative cash flow in C 45 Scenario Figure 10.43: Total Generation Cost - Moyle online vs. offline Figure 10.44: Total System Generation - Moyle online vs. offline Figure 10.45: 1PHES Generation by Fuel Type - Moyle online vs. offline Figure 10.46: Negative impact of reduced interconnection capacity on Gas RoI operation Figure 10.47: Minutes spent ramping up and down by Moneypoint coal units Figure 10.48: Percentage of wind energy curtailed in the Republic of Ireland - Moyle online vs. offline Figure 10.49: Payback Period Reduced IC Table of Tables Table 7.1: Turlough Hill Return Dates Table 8.1: Fuel Price and Emissions. 18 Table 10.1: Comparison of peaker unit SRMC Table 10.2: Peaker units which cease to be used with the addition of PHES capacity Table 10.4: Losses prevented by the addition of PHES Table 10.6: Summary of PHES Earnings Free IC Table 10.7: Payback Analysis New PHES Plant Free IC Table 10.8: Payback Analysis New PHES Plant Fixed IC Table 10.9: Payback Analysis Market Model Table 10.10: Payback Analysis Market Model Table 10.12: Calculation of New PHES payback in C 45 scenario Table 10.13: PHES Generation - Moyle online vs. offline Table 10.15: Wind generator revenue lost due to curtailment Table 10.16: PHES Plant Capacity Factors Reduced IC ix

11 4. Introduction Power systems worldwide are have experienced significant changes in recent years with a major increase in installed renewable energy generation, driven by concerns over dwindling fossil fuel reserves and climate change caused by emissions from burning fossil fuels [1]. Under the 2009 Renewable Energy Directive (2009/28/EC), the EU and Irish government have set an ambitious target for the country of 16% of gross final consumption to come from renewables by Contributing to this is a target of 40% of electricity to be generated by renewable energy sources (RES-E), with 37% expected to be generated by wind [2]. In order to meet this target, it is predicted that the amount of wind generation across the island of Ireland will reach an installed capacity of between 4,800 MW and 5,300 MW by 2020 [3]. With an installed wind capacity on the island of 2088MW as of November 2012 [4], this rapid increase in levels of renewable energy penetration in power systems will give rise to new challenges related to the intermittency of renewable resources for system operators. The primary energy sources for technologies like wind and solar power are not controllable, and thus there is an inherent unpredictability associated with renewable energy generators [5]. In a system where electrical supply and demand must be matched on a second by second basis, such generators that cannot be dispatched to meet load demand, unlike conventional thermal generation which can be ramped up or down as required, can cause system stability problems such as frequency fluctuations which could trigger cascade tripping of power stations and blackouts in a worst case scenario [6]. In the Irish Single Electricity Market (SEM), many wind generator units which are registered as Price Takers are given Priority Dispatch status which gives them precedence when competing with other non-priority price taker and price maker generator units, with the goal of incentivising the dispatch of as much wind energy generation as possible in the Irish power system [7]. This gives rise to further problems such as generator cycling of conventional plant: In times of high wind energy generation, other conventional generation must be curtailed in order to accommodate the levels of wind being generated on the power system. During periods of high demand, this results in more flexible peaking generation and mid-merit generation being curtailed or even shut down completely. However in times of low energy demand and high wind speed, Priority Dispatch wind energy generation forces base-load plants (such as coal) to be ramped down. This has major economical and operational ramifications for such plants which are designed for continuous operation at near-full capacity. Cycling of base-load generation incurs significant additional costs associated with start-up, ramping and shut down often to the order of hundreds of thousands of Euros [8]. The significant increase in wind generation capacity discussed, combined with the planned decommissioning of older flexible conventional plant such as the fuel oil units at Tarbert and Great Island will give rise to significant stability and security of supply challenges for the transmission system operators. Clearly, flexible generation plant which can quickly respond to demand fluctuations will be required in order to meet these future challenges on the Irish power system. Pumped Hydroelectric Energy Storage is considered by many to be the ideal solution to these challenges for Ireland [9] [10]. PHES operates by pumping water from a lower to an upper reservoir; excess electrical energy during times of low load demand can be stored as potential energy, related to the elevation difference between the two reservoirs (or Head). As energy demand rises during the 1

12 day, the water stored in the upper reservoir can be used to generate electricity like a hydroelectric power station. This energy storage cycle is repetitively used in power systems to supply peak loads and store energy in low demand periods, with round-trip efficiencies of 70% and greater [11]. PHES is often discussed as a direct integrator of intermittent wind energy through unrequired energy storage, and has been shown to enable greater renewable generation capacity in power systems [12]. However under current Irish SEM rules, firm wind generators receive curtailment compensation under the Dispatch Balancing Cost (DBC) mechanism [7] and thus have little incentive to sell energy to PHES. However with future plans to terminate wind curtailment compensation by 2020 [13], this may become more relevant in Ireland. PHES units also offer further important uses to power systems: they can be operated as synchronous condensers, enabling reactive power regulation for voltage control [14]; black start provision; system frequency control and reserve response through rapid start times ranging from minutes, depending on the unit [15] [16]. While the positives of PHES have been made evident, there are significant drawbacks which prevent this technology from being deployed on a larger scale in Ireland and abroad. Although operation and maintenance costs are low due to zero fuel costs, PHES schemes incur major initial capital costs through planning and construction, and can take many years to complete [17]. Finding suitable sites can also prove difficult; it is considered ideal to use existing bodies of water for at least one, if not both, of the reservoirs to reduce said construction costs. Such sites must also meet specific topographical standards, and are often found in remote, mountains regions with poor vehicle and transmission grid access [18]. There are also significant environmental impact concerns when constructing a PHES scheme, such as water protection interests and wildlife advocates, which can often delay or prevent planning application and construction [17]. These drawbacks have seen cheaper, yet inefficient and carbon-intensive open cycle gas turbine plants (OCGT) being favoured over PHES in Ireland, with the opening of four new plants planned by 2020 [19]. The objective of this research project is to investigate the benefit PHES offers not just the operation of wind generation, but the 2020 Irish power system as a whole. The following research questions were posed in order to achieve this objective: What benefit does PHES have for the operation of the 2020 Irish Power System? Does the Irish power system need another PHES plant? Would a new PHES plant represent an attractive investment to private investors in the liberalised Single Electricity Market? The PLEXOS power system simulation software by Energy Exemplar was used to carry out modelling and analysis for this research project. 2

13 5. The Single Electricity Market: A Review 5.1. Introduction The Single Electricity Market, which went live on 1 st November 2007, is the wholesale electricity market for the island of Ireland, and is the first market of its kind in the world, combining two separate jurisdictions and currencies. The SEM is regulated jointly by the Commission for Energy Regulation (CER) and its Belfast counterpart, the Northern Ireland Authority for Utility Regulation (NIAUR), who define the SEM trading and settlement rules, as set out in the Trading and Settlement Code (TSC). The SEM is operated by the Single Electricity Market Operator (SEMO), a joint venture between EirGrid and SONI, the transmission system operators (TSOs) of the Republic of Ireland and Northern Ireland respectively [20]. The key Objectives of the SEM as set out in the SEM Legislation [21] are: To ensure the secure supply of electrical demand on the island of Ireland, while promoting the use of renewable energy for an environmentally sustainable power system, To ensure efficient and fair competition between market participants, thus protecting the interest of the end consumers of electricity, To carry out necessary decision making in a transparent and consistent fashion. 3

14 5.2. Market Operation The SEM operates under a Central Dispatch model, whereby participating generator units are scheduled and dispatched by the TSO; single generator units have no control over when and to what level they are dispatched in the power system once they have submitted offers [20]. As per the Single Electricity Market Trading and Settlement Code [7], each participant generator is required to submit offers to SEMO for each trading period (30 minutes) of each trading day. These offers must be submitted before gate closure, which is 10:00 on the day before the relevant Trading Day (i.e. 10:00 D-1). A generator unit offer consists of: Technical Offer Data (TOD): Data which outlines the technical capabilities of the generator units such as ramp rates, minimum stable generation level and primary/secondary fuel types. Commercial Offer Data (COD): Data which includes a generators Short Run Marginal Cost of generation as well as no-load costs, start-up costs and price-quantity pairs (set levels of energy which a generator unit can deliver in MW, and the associated price of delivery). Generator units may submit up to three separate start-up costs (cold, warm and hot startups), and multiple price-quantity pairs to be considered. Based on these submitted offers, the TSO runs a Market Scheduling Program (MSP), which will consider technical parameters such as maximum ramp rates and minimum stable generation levels to generate a stack of the lowest cost generator bids necessary to meet the predicted marginal system demand - or Market Schedule Quantity (MSQ) - while ensuring stable system operation. This is price per MW is known as the System Marginal Price (SMP). However the MSP is and unconstrained model and cannot account for real time issues which lead to differences between market schedule and actual dispatch quantities, such as transmission system faults and incorrect wind forecasting. For this reason SEMO completes two more software runs reflecting the reality of what actually happened in generator dispatch one on the day after the trading day (D+1) - known as Ex-Post Indicative (EP1) - and another four days after (D+4) - known as Ex-Post Initial (EP2) - to calculate the final SMP for each half hour of the trading day. This D+4price is the one that is paid to generators as the SMP [22]. Generator units which contribute to the MSQ stack are said to be in-merit, and earn a profit known as infra-marginal rent on the difference between their bid offer and the SMP. Generators whose offer is greater than the SMP are out-of merit and do not receive the SMP. These generator units tend to be older, inefficient plants. 4

15 Figure 5.1: Merit Order allocation [20] The SMP calculated for each trading period is the sum of a Shadow Price, which reflects the SMRC of the marginal generator required meeting demand, and the Uplift, which recovers start up and no load costs which are not recovered by a generator through the infra-marginal rent it receives [23]. This may occur when a generator is run for a short period of time to meet peak demand, as shown by the sharp rise in Uplift payments during peak demand on the sample Trading Day in the graph below. Figure 5.2: SMP in relation to System Load (data from Note that only generator units registered as Price Makers (such as gas-fired plants or pumped hydro energy storage) may set the SMP, while Price Taker generator units and Autonomous (nondispatchable) generator units may not. The MSP will generally attempt to meet as much of the system demand as possible with Priority Dispatch Price Taker units (such as certain wind farms), and then meet the remaining system demand using the lowest cost price takers available [23]. Not only does the system of operation of the SEM enable the running of the lowest cost generators, thus keeping customer costs down, it also encourages new efficient generators to enter the market, resulting in further cost savings, increased security of supply and environmental benefits. 5

16 million 5.3. Generator Unit Payments & Charges SEMO makes a number of different payments to Generators within the SEM. There are two broad classes of Generating Unit Payments: Trading Payments and Capacity Payments. Participant generator units are also expected to pay certain charges related to generation, grid access and administration, as discussed below Trading Payments These are payments to Participants in respect of their Generator Units over a billing period. Such payments will comprise Energy Payments, Constraint Payments, Uninstructed Imbalance Payments and Make Whole Payments less any charges incurred during that period. 1) Energy Payments [7] Energy Payments are made to a Participant based upon the energy generated and sold by the Participant s generator unit(s) over a Billing Period, and is calculated as the product of MSQ and the ex-post SMP. The aforementioned infra-marginal rent is the profit that the generator unit earns after subtracting their Short Run Marginal Costs (SMRC) from the Energy Payment they receive. Energy payments account for a significant proportion of the revenue earned by Participants, as shown by the below chart. 2,500 2,000 1,500 1, Energy Payments Capacity Payments Constraint Payments Figure 5.3: Annual SEM Value (data from 2) Constraint Payments [7] To ensure continuity of supply and the security of the system in real time, some generator units must be dispatched in a different manner to the SEM market schedule. Constraint costs arise when there are differences between the market-determined schedule of generation to meet demand (the Market Schedule Quantity) and the actual instructions issued to generators by the TSOs (the Dispatch Quantity). This is because the TSOs must take into account the technical realities of operating the power system which cannot be accounted for in the unconstrained Market Scheduling Program (MSP), such as transmission network faults and reserve requirements for system security (whereby some generators are instructed to run at a lower 6

17 levels than indicated in the Market Schedule to provide standby generation capacity which can be quickly brought online if required). Constraint payments compensate for additional cost incurred by a generator which is constrained on (when its Dispatch Quantity is greater than its Market Schedule Quantity), or to eliminate compensation for costs not incurred by a generator which is constrained off (DQ<MSQ). 3) Uninstructed Imbalance Payments [7] All dispatchable generator units are required to follow instructions from the control centres within practical limits to ensure the safe and secure operation of the power system. In the SEM, the Uninstructed Imbalance Payments mechanism, as set out in the Trading and Settlement code, provides economic signals to ensure that dispatchable generator units follow their instructions within the acceptable practical limits. If a generator unit s actual output is greater than its Dispatch Quantity, it will receive an Uninstructed Imbalance Payment to compensate for over-generation. Conversely, if a generator unit s actual output less than its Dispatch Quantity, it will be charged an Uninstructed Imbalance Payment to remove compensation for undergeneration. 4) Make Whole Payments [24] A Make Whole Payment is made to a Participant in respect of a Generator Unit, and is designed to compensate for any difference between the total Energy Payments to the Generator Unit in a Billing Period and the sum of the Schedule Production Cost for that Generator Unit for each Trading Period within the Billing Period. 5) Generator Charges [24] Generator Charges are costs imposed on a participant in respect of a generator unit. Some examples include: Transmission Use of System charges: Charges which are paid by Participants for access to the transmission network to transfer energy to trade within the market, Testing Charges: Testing of a Generator Unit requires out of merit running which increases constraint costs. A charge is levied on each Generator when testing through the Testing Charges mechanism in the SEM to recover this net increase in constraint costs. Fixed Market Operator Charge: A charge imposed on Participants related to the number of generating units registered against them and also the size of the generator(s). 7

18 Capacity Payments Capacity Payments are an important mechanism in the SEM, as they incentivise generation availability and provide a more stable, lower-risk income for Participants. It is important that Participant generator units which are dispatched by SEMO recover their shortand long-run costs of generation. As the SEM is an energy-only pool market, generators must recover these costs through the price of energy alone. This may not be possible for certain generator units, such as peaking plants which are brought online to meet peak demand for a short period of time. The large Short Run Marginal Cost (SRMC) associated with such a scenario means peaking generator unit earn minimal infra-marginal rent in comparison to generator units of lower merit order (such as a high efficiency CCGT or a wind generator, which will have a low SRMC). Thus for a peaking generator unit to earn sufficient money to recover its running costs, energy prices would have to have risen to sufficiently high levels during the unit s short period of operation. The Capacity Payment Mechanism (CPM) pays generator units for availability throughout the year from a fixed pot of money, relieving reliance on high prices to recover costs and thus providing a lower-risk revenue stream. The CPM total pot is allocated annually, and determined as the product of the fixed costs of the Best New Entrant peaking plant, and the amount of capacity required to meet an all-island generation security standard [25]. The BNE for 2013, as recommended by the SEMC [26] is the Alstom GT13E2 firing on distillate fuel, sited in Northern Ireland, which has an estimated annualised fixed cost (net of estimated Infra- Marginal Rent and Ancillary Services revenue) of 76.37/kW/year. The SEM Capacity Requirement estimated for 2013 is 6,923MW, thus the 2013 Annual Capacity Payment pot is calculated to be: 76.37/kW/year * 6923MW = 528,709,510 This fixed annual pot is divided into 12 monthly pots weighted against the forecasted maximum demand of that month, thus the majority of cash is available in high demand periods, incentivising generator units to be available for generation during more valuable times. Figure 5.4: Distribution of monthly pots [27] 8

19 For each month, the pot is divided into three payment streams: Fixed (year ahead), Variable (month ahead) and Ex-Post (Month End) [25]: Fixed Sum Capacity Payments (30% of total pot): Calculated prior the start of the Year and has weak incentives to respond to shortages, thus providing a more stable revenue component for generators. Variable Sum Capacity Payments (40%): Uses availability and demand forecasts to provide a forward-looking time-of-day signal for generators, valuing required availability more during periods of low margin than high margin. This pot component improves forecast of likely shortages, but does not respond to un-forecast shortages. Ex-Post Sum Capacity Payments (30%): Each trading period s availability is valued based on real time system conditions, thus providing short-term response incentive to generators. This pot component is more uncertain and reflects the volatility of market energy prices, which will fluctuate with real-time events. 9

20 5.4. PHES in the SEM Turlough Hill is Irelands sole PHES plant, housing four 73MW pump-turbines that are registered as 4 separate generator units (TH1, TH2, TH3, and TH4) in the SEM. Like other renewable energy generator units, PHES plants such as Turlough Hill benefit from having no fuel costs and thus a minimal Short Run Marginal Cost. However they are subject to larger long term costs such as the capital expenditure involved in the construction of the plant. Revenue streams other than Energy Payments are thus very important to Turlough Hill to enable it to cover its Long Run Marginal Costs, as with any peaking generator unit. Due to the nature of its operation, different rules of operation and payment rules apply to PHES in the SEM. Each pump/turbine is treated separately in the SEM much the same as all other generators in the SEM. Each unit is referred to as a Pumped Storage Unit and is settled as a generator unit irrespective of net value [7]. Pumped storage units are registered as predictable price making generators (PPMGs) and as such are scheduled using the economic commitment engine in the MSP software. Pumped storage units submit price-quantity pairs, start-up costs and no load costs equal to zero and as such effectively they make no bids but rather adopt a price for a given half hour trading period from the marginal price making unit which has set the SMP in that trading period. Since there are no submitted prices the scheduling of pumped storage units is performed by the MSP to minimise the total MSP production cost over all scheduled generator units across the thirty hour optimisation horizon while ensuring that the pumped storage units maximum and minimum storage capacity (which are Technical Offer Data submissions) are not breached [23]. The Pumped Storage Units are controlled by the market operator not the PHES station, as per the Central Dispatch model [7]. To operate in the SEM each Pumped Storage Unit must submit Price Quantity Pairs, Start Up Costs and No Load Costs for each unit (equal to zero) as well as Commercial Offer Data and Technical Offer Data. The Commercial Offer Data refers to the target reservoir level at the end of each trading period. The Technical Offer Data refers to efficiency, target reservoir percentage of 50%, max storage capacity (MWh) and min storage capacity (MWh) for each trading day [7]. The target reservoir level is used as a lower limit for the reservoir level at the end of the trading day so that, where feasible, the MSP software shall ensure that the reservoir level at the end of the trading day is greater than or equal to this limit. For each MSP Software run, the Target Reservoir Level Percentage (50%) is multiplied by the Target Reservoir Level to derive a lower limit for the reservoir level at 12:00 on the following trading day and the MSP Software schedules each Pumped Storage Unit such that the reservoir level at 12:00 on the following trading day is greater than or equal to the resultant reservoir level [28]. PHES units do not receive constraint payments like conventional generation units when the DQ differs from the MSQ as outlined in the Single Electricity Market Trading and Settlement Code. PHES receives and pays all other payments set out by the SEM including Energy Payments, Capacity Payments, Uninstructed Imbalances, and Make Whole Payments [7]. 10

21 6. PLEXOS Software Review PLEXOS [29] produced by energy exemplar 1 is a sophisticated power market simulation software used for electricity market modelling and planning. PLEXOS, normally a commercial modelling tool, is free to academic institutions for non-commercial research. The software uses cutting-edge mathematical programming and stochastic optimisation techniques aimed to minimise an objective function subject to the expected cost of electricity dispatch coupled with a number of constraints. These constraints include characteristic of generating plants such as start-up/shut-down costs, ramp up and down rates and maximum and minimum generation. There are various other constraints including fuel costs, environmental limits, and operator and transmission constraints. PLEXOS performs a chronological optimisation using 30 minute periods throughout each day to model the system for a period of time. The time period that will be concentrated on will be short (i.e. one year). The PLEXOS modelling tool has been used by the Commission for Energy Regulation (CER) in Ireland 2 to validate and model Ireland s Single Electricity Market 3 (SEM) [30]

22 7. Historical Data 7.1. Introduction Dispatch quantity data was sourced from the Single Electricity Market Operator, SEMO [31]. The dispatch quantity data was sourced directly from the SEMO website where available and a request for missing data was sent to SEMO who in turn supplied the data. The interconnector flow was sourced separately from the Moyle interconnector physical flows Excel sheet created by Mutual Energy [32]. There are several reasons that historical data was attained, the main reasons are outlined below: To perform data analysis on pumped storage to examine how a pumped storage plant is operated normally. To analyse the impact pumped storage has on the electrical power system as a whole by comparing a period when Turlough Hill was offline to normal operation. To validate the PLEXOS model being used to find the impact additional pumped storage would have on the electrical system Turlough Hill As Turlough Hill is the only Pumped storage station in Ireland the historical data has been based around its operation. Turlough Hill is located in the Wicklow Mountains and began full operation in The generating station has a capacity of 292MW produced by four Siemens turbines; this is generated when water is flowing from the upper reservoir to the lower reservoir. During periods of lower demand the water is pumped back to the upper reservoir ready to be used again. [33] The maximum generation of each unit is 73MW and the maximum when in pumping mode is 71.5MW. The minimum stable level when generating is 5MW and the efficiency of each unit it 70%. [34] 7.3. Data Acquisition The Dispatch quantity was attained for all generators in the SEM for half hourly periods from 1 st January 2009 until the 5 th of July All four units of Turlough Hill went on outage on July 5 th 2010, and the units then returned to operation on the dates listed in table 7.1 below. Unit Return Date TH1 7 th June 2012 TH2 14 th March 2012 TH3 25 th August 2012 TH4 14th July 2012 Table 7.1: Turlough Hill Return Dates This allowed for a period of normal operation to be compared to a period when Turlough Hill was offline for maintenance. The timeframe chosen was a one year period TH offline compared with a one year period TH online. A one year period was chosen as it would give the most accuracy and allowed yearly load trends to be examined to the full extent. The TH online period runs from the 5 th July 2009 to the 4 th July 2010 and the TH offline period runs from the 5 th July 2010 to the 4 th July

23 Generation MW 7.4. Normal operation It is firstly important to gain an understanding of how pumped storage is operated within the SEM. Using the historical data for Turlough Hill pumped storage operations can be examined within the SEM. During the night time Turlough hill is in pumping mode. Each generator that is in operation pumps water from the lower reservoir to the upper reservoir at 71.5MW as show below in Figure 5. The pumping occurs usually sometime between 23:00 and 09:00, when the system demand is lower as seen earlier in the System load curve. The pumping tends to last between 8.5 and 9.5 hours with the main purpose being to fill the upper reservoir to allow for more generating during the day. During generating mode Turlough Hill has several modes of operation. Each unit operates at the minimum stable level of 5MW to provide spinning reserve. This is very useful in provinding reactive power to the grid for voltage regulation. When the generator is running at this output it can very quickly ramp up to provide extra generation to the system. From data analyisis it has been seen that each Turlough Hill unit usually operates at 45MW when extra generation is required and also provides reserve upwards of this. The basic functions of TH2 are shown in Figure 7.2 below. It is important to note that the turbines do not generate in the range of 6-34 MW. Figure 7.1 depicts generation in MW for every half hourly period meaning that a turbine operating at 45MW for 20min would register a value of 30MW. 60 TH Figure 7.1-Turlough Hill TH2 Generation over a typical week Turlough Hill is operated within the SEM to reduce the overall system costs which means it often operates at lower efficiency, for the whole of 2009 the overall plant efficiency was 60% and for 2010 it was 61%. A graph for a typical week is depicted in figure 6 below, the overall plant efficiency works out at 61.5%. 13

24 MW Dispatched Generation MW 60 Turlough Hill General operation over a week TH1 TH2 TH3 TH Figure 7.2: Turlough Hill Generation per unit The pumping and generation schedule of this plant is optimised in co-ordination with thermal and hydro resources to maximize its value to the system, as seen in Figure 7.2 above. The operation of Turlough Hill units is subject to the following constraints. [35] 7.5. Interconnection It was seen that Ireland is a net importer of power from GB via the Moyle interconnector for the period of analysis. Overall generation increases from the period where Turlough Hill online to when it is offline. It is seen that power dispatched over the interconnector has increased when Turlough Hill is offline. This is due to interconnection providing more peak power which PHES was previously supplying. This trend is predicted to be present in the modelling section when comparing the 0 PHES scenario to the 1 PHES scenario. 2,700, IMPORTS 2,600, ,500, ,400, ,300, ,200, ,100, ,000, ONLINE OFFLINE Figure 7.3: Interconnector Imports 14

25 7.6. System Overview The historical analysis investigated a period from 2009 to 20011, it was therefore important to find if there was any dramatic change in the system over the duration of the period. A very telling factor is what plant is available for dispatch and what capacity of each fuel type is available. The best way of defining the system capacity is by the generation adequacy reports. [36] The overall generation capacity increases by 1,000MW from year end Gas generation capacity increases 876MW as Whitegate and Aghada CCGT plants come online. Poolbeg heavy fuel oil, HFO, generators were shut down and a new distillate OCGT was brought online to replace these. This has been a continued trend in Ireland with HFO plants being shut down and being replaced by gas and distillate plants. This is backed up by the difference in capacities between 2009 and 2010 below in figures x and y. Wind generation capacity increases but not by a large enough amount to affect the percentage share of capacity, the increase in capacity was not as great as expected as several projects were not complete until OTHER 2% INTERCONNECTION 5% PHES 3% HYDRO 2% WIND 16% COAL 12% DISTILLATE 4% HFO 10% PEAT 3% GAS 43% Figure 7.4: System Capacity

26 OTHER 2% INTERCONNECTION 4% PHES 3% HYDRO 2% WIND 16% COAL 11% HFO 7% DISTILLATE 5% PEAT 3% GAS 47% Figure 7.5: System Capacity 2010 There are several changes that have already occurred since 2010, more gas plants have been added to the system and HFO have been retired (Great Island). The East-West interconnector has been recently commissioned. There has been continued addition of wind capacity to the system. There are several fundamental changes expected stretching out to HFO plant will be completely retired and replaced. Wind capacity will continue to increase to achieve 37% of generation by Electricity from waste and wave will be present in the system but to what extent is still unclear. EirGrids latest adequacy report shows an addition of 62MW of waste energy in 2015 and year on year increases in Biomass/Landfill gas capacity System Operation There is an overall decrease in generation between the two periods chosen this may cause some of the results to be out of sync with what would be expected. An increase of 22% in wind energy was seen for the whole of Ireland, this was due to there being better winds in the offline period and the increased addition of wind capacity to the power system. The increase in wind generation made it too difficult to discern a link between the advantage PHES has to wind generation and its capacity factor. Large decreases in peat and hydro energy were seen and coal generation increased in generation for the offline period. Coal generation may have increased due to a number of reasons including price, availability, and outages in either period. Gas and Distillate production also saw large decreases due to the overall decrease in generation required. 16

27 WIND NI 1% LFG ROI 0% COAL NI 4% DISTILLITE NI 0% COAL ROI 10% PHES (Generating) 1% DISTILLITE ROI 1% HYDRO ROI 2% PEAT ROI 7% GAS NI 17% Online WIND ROI 7% GAS ROI 50% Figure 7.6: System Generation TH Online DISTILLITE NI 0% WIND NI 1% LFG ROI 0% DISTILLITE ROI 1% HYDRO ROI 2% PEAT ROI 7% COAL NI 5% Offline GAS NI 14% COAL ROI 11% WIND ROI 9% GAS ROI 50% Figure 7.7: System Generation TH Offline The percentage breakdowns for the online and offline periods are portrayed above in figure 7.6 and 7.7. ROI wind generation and coal increase in generation and this is matched by the decrease in PHES and NI gas. The percentage generation found accurately reflects the period and has been verified against SEMO figures found in the fuel mix disclosure. [37] The electricity produced from renewables was 17% and 18% of generation for the online period and the offline period respectively. The rise in renewable generation is mainly due to the increase in wind generation and the overall reduction in generation. Renewable generation is made up of wind, hydro and peat. 17

28 Ireland Model The model used was developed based on data from the Regulatory Authorities used in the development of the annual RA PLEXOS Validation report [38] and further developed to the 2020 version in UCC. Important characteristics of the model used are highlighted below Simulation Resolution & Duration Model simulations were run at 30 minute interval resolution, reflecting the trading period timeframe of the SEM [REF]. Simulations were run for one year; beginning January 1 st 2020 and ending December 31 st System Load As with the validated model released by the CER, system load was input into the model as a halfhourly load and was based on the 2007 Irish load curve Generator Unit Properties & Dispatch Generator properties were input into the model to characterize their operation within the model, in a similar fashion to the submission of Commercial and Technical Offer Data to the Market Operator in real life. The data used is publicly available and was provided by the SEMO website, Regulatory Authorities and specific generators. Commercial input data includes daily price-quantity pairs, no-load costs and start costs (Hot, warm and cold). Technical input data includes availability, minimum stable level, incremental start times, ramp up/down rates and minimum on/off times Fuel Costs, CO2 Production and Tax Rates Table [REF] below summarises the cost of fuels used in the model, and their associated CO 2 emissions and taxes. A Carbon Tax of 30/tonne of CO 2 is implemented of all fuels. Note that the price given for gas is an annual average, as it varies ± 5 cents based on the time of year. Also note that peat is assumed to have not fuel cost as it is harvested by the plant operators. Fuel Price ( /GJ) Carbon Tax ( /GJ) Emission Rate (kg/gj) Gas Coal Peat Distillate Oil Table 8.1: Fuel price and emissions 8.5. Wind Generator Units Wind generator units were modelled as a single generator unit with a single aggregated generation output. There are two wind generator units, ROI WIND and NI WIND to represent wind generation in the Republic of Ireland and Northern Ireland. The wind capacity factor for the model is based directly on the ROI 2008 capacity factors. Wind generator units and other renewable units such as waste, hydro and PHES do not have generation costs associated with them in the PLEXOS model and are considered free generation. 18

29 8.6. Outages For a given model known maintenance schedules can be added for generation units or an optimal maintenance schedule can be assigned by the model. Random outages are also applied using the forced outage rates from the base year [27] PHES in the Model Within the PLEXOS model renewable resources are automatically treated as free generation (i.e. the marginal cost is set to zero). These resources such as wind are considered non-dispatchable and as more variable generation is added the energy system becomes much more difficult to model. In the current market wind farm operators act as price takers, effectively bidding at zero. PLEXOS records a zero value for the water in the PHES reservoir other than the value of the thermal generation it can replace. The model will seek to use all available water in order to minimise the cost of thermal generation during optimisation. To ensure the reservoir does not empty a look ahead period is used. Look ahead is where the optimiser is given information about what will happen ahead of the optimisation period [27] System Generation Capacity System capacity was modelled using information from the EirGrid Generation Capacity Statement [REF] Total system capacity is 15,276 MW. All-island wind generation capacity amounts to 5196 MW, or 37% of total capacity. Figure [FIG] below demonstrates the capacity by fuel type for the All-Island power system All-Island Fuel Mix Interconnection 6% WASTE ROI 2% NI Wind 9% ROI Wave 1% DISTILLATE NI 2% ROI Wind 28% COAL NI 3% GAS ROI 27% GAS NI 7% COAL ROI 6% PEAT ROI 2% HYDRO ROI 2% PUMPED DISTILLATE ROI 3% STORAGE ROI 2% Figure 8.1: All-Island Fuel Mix Interconnection & Great Britain Generation The Moyle interconnector which began commercial operation in 2002 links Northern Ireland to Scotland and has a capacity of 500 MW [39]. The 500 MW East-West Interconnector links the Republic of Ireland to Wales and was commissioned in late These two links between the all- 19

30 island power system the Great Britain power system mean that the Great Britain market can influence the SEM. In the Model the two interconnectors are modelled as a single 1000 MW line ( IC ), of which 900 MW is available for energy flow, while 100 MW is held for static reserve provision, as occurs in real life. Flows on the interconnectors are to some extent driven by arbitrage of the relative prices in the two markets. For this reason it is necessary to represent the generation of the Great Britain in the Model Historically, the marginal plant type and thus power price setter in the GB system has mainly been gas-fired generation [REF plexos validation 2010]. Thus the GB power system is represented in the Model as a single gas-fired generator unit ( GB GENERATION ) calibrated in the same way as done so by in the validated RA PLEXOS model Reserve Provision Generator units are scheduled to provide reserve generation for system security, and are paid a reserve price relative to their provision, as occurs in real market operation. [REF Mention which kind of reserve used?] Network Constraints Several model constraints were implemented to reflect the group of EirGrid Transmission Constraints which are imposed on the real operation of the power system: System Non-Synchronous Penetration System non-synchronous penetration (SNSP) is a real-time measure of the portion of generation from non-synchronous sources (sources which generate electricity at a frequency which differs from the 50 Hz of the Grid), such as wind and HVDC interconnector imports [40]. Maximum SNSP levels of 50% are permissible in the All-Ireland power system due to stability and security of supply constraints. However with the development of enhanced system operational policies, tools and practices, the investment in the required transmission and distribution infrastructure, and the evolution of the appropriate complementary portfolio, the studies indicate that an SNSP level of up to 75% is achievable [41]. A maximum SNSP in the model was set to 70% of total generation Dublin Generation There must be at least 2-3 large generators on-load at all times in the Dublin area to provide voltage control. Plants included are Dublin Bay, Huntstown and Poolbeg [REF change plant to unit refs; DO UNIT REF LIST] Inertia NI There must be at least 3 high inertia machines on-load at all times in the Northern Ireland Region to provide dynamic stability. Plants include Ballylumford and Kilroot Inertia ROI There must be at least 5 high inertia machines on-load at all times in the Republic of Ireland Region to provide sufficient dynamic stability. Plants include Aghada, Whitegate, Moneypoint, Dublin Bay and Tynagh. 20

31 Kilroot Coal At least one Kilroot unit (K1 or K2) must be on-load during high demand to guarantee voltage stability in the Belfast area and to prevent a flow reduction on the North-South tie line in a post fault scenario Moneypoint At least one Moneypoint unit (MP1, MP2 or MP3) is required to be on-load at all times to maintain flow on the 400kV transmission system from the West to the East South West Generation There must be at least 2-3 generators on-load at all times in the South West area of the system for voltage stability. Plants include Aghada, Whitegate and Aughinish. Reference: Transmission Constraint Groups, EirGrid & SONI, 16/6/2010 And Transmission Constraint Groups, Valid from 19th July [ 9July2012.pdf 21

32 9. PLEXOS Modelling Methodology To quantify the potential benefit of PHES to the 2020 Irish SEM and power system, the effect of different levels of PHES capacity on multiple system properties was examined by comparing the results of three separate simulation scenarios: 1 PHES: In this scenario the 2020 Irish SEM is modelled with current PHES capacity; 292 MW provided by Turlough Hill as discussed in Section PHES: A second PHES plant is added to the model to examine the benefit of additional PHES capacity. For the purpose of comparison this new PHES plant is a duplicate of Turlough Hill PHES in terms of maximum capacity and other properties, however the plant efficiency increased to 75% to better resemble efficiencies of new PHES plants worldwide, 0 PHES: This scenario simulates the Irish SEM without any PHES capacity, allowing the significance of zero energy storage in the system to be examined, Discussed Earlier in historic data section. Due to the unpredictability of future interconnection operation, the results of the model simulation are presented in two sections: 2020 Free Interconnection: In this method interconnector flow is simulated based on price differentials between the Irish SEM and the Great Britain power system, as would be expected. This method lends to a more whole prediction of the 2020 power system, as the software is free to dispatch interconnection as it sees optimal Fixed interconnection: Interconnector flow is decided based a fixed set of half-hourly data input in the model. This simulation method gives an accurate simulation based on actual data; however it only serves as a control set of results. This method actually gives rise to decreased system flexibility as it forces PLEXOS to adhere to a set of interconnector flows which do not fit naturally into the 2020 model simulation. This method of analysis is also employed by the Commission for Energy Regulation in their annual PLEXOS Validation Reports. The properties examined were grouped into the following categories: Total System Generation and Cost Emissions Conventional Plant Operation Interconnector Flow Wind Curtailment System Marginal Price Pumped Storage in the System Three additional system scenarios were simulated to further examine system operation and the impact of PHES: Market Simulation Carbon Tax Sensitivity Interconnector Outage 22

33 10. PLEXOS Modelling Results Base Model: Free Interconnection Total System Generation and Costs Total Generation Cost is the total cost of energy generation in the power system for the entire year. Total Generation Cost is a key indicator of system performance as the system operator s objective is to meet system demand for each trading period with the lowest cost generator dispatch portfolio. Total Generation Cost modelled in PLEXOS is equal to the sum of the Generation Cost and Start and Shutdown Cost of every generator unit. Generation cost is the cost associated with the production of energy such as fuel and variable operation & maintenance (VO&M) costs. Start and shutdown costs are the fuel and VO&M costs associated with starting up or shutting down a generator unit, are intensive processes for many thermal units such as coal and gas. As was discussed in Section [REF 2020 model; renewables], renewable generator units such as Waste, Hydro, PHES, Wind and Wave have fuel sources which are considered free and therefore do not contribute to the system Total Generation Cost. The system Total Generation Cost also includes the cost of generating electricity in the GB market to incorporate the cost of generating electricity which is generated and then imported by the Irish system. The system Total Generation Cost was compared for each PHES scenario, and the results are presented in Figure [REF] below. It was found that when the New PHES plant was added to the system in 2 PHES, Total Generation Cost for the year reduced by 16,882,532 (relative to current levels of PHES capacity, as modelled in 1 PHES). It was found that Turlough Hill was also of benefit to the system; when it was removed from the power system in 0 PHES, Total Generation Cost was increased by 22,670,892 over the year. Billion Start & Shutdown Generation PHES 1 PHES 2 PHES Figure 10.1: Total System Generation Costs Free IC 23

34 While the cost of generation decreases with the addition of PHES the total system generation actually increases, as shown in Figure [REF] below. The addition of the New PHES plant results in an increase in total system generation of 371GWh Total System Generation (GWh) 0 PHES 1 PHES 2 PHES WASTE ROI ROI Wind ROI Wave NI Wind COAL NI GAS NI DISTILLATE ROI PHES ROI HYDRO ROI PEAT ROI COAL ROI GAS ROI Figure 10.2: Total System Generation Breakdown (GWh) Free IC This increase in total generation can largely be accredited to the increased storage capacity of the system; generation must be provided when pumped storage is in pumping mode and this stored generation can then be used at a later stage when demand requires. This was confirmed by the observed increase in the amount of energy used in pumping over the year, known as the pumping load. In 1 PHES the system pumping load was GWh, consumed solely by Turlough Hill, whereas in 2 PHES the system pumping load was GWh. This increase of 372 GWh due to the addition of the New PHES almost exactly matches the total system generation increase. It may be considered counterintuitive that total generation cost decreases even though generation increases. However by examining the changes in generator dispatch levels and cost with the addition of PHES in Figures [REF] below, some light can be shed on these results. It can be seen that the cost of gas generation in the Republic of Ireland decreases by 24,980,220 due to dispatch decreasing by 284 GWh in 2 PHES. This reduction is due to the New PHES plant supplying 358 GWh of additional peak load generation over the course of the year, thus displacing other gas peaker units which were used for peak demand in 1 PHES. This reduction is by far the most significant decrease in 2 PHES, and is a major factor in the net decrease in total system generation costs. GB Generation experiences an overall increase in total generation cost, with an increase of 8,390,542 seen in 2 PHES. This is due to increased imports from Great Britain with additional PHES capacity, as will be discussed further in Section [Interconnection REF]. There is a marginal net increase in coal generation in Moneypoint and Kilroot with the addition of PHES capacity. This is due to the New PHES plant requiring additional base load generation for pumping during the night. Peat and NI gas generation also increases to supply the load needed for 24

35 pumping as these are the next cheapest generation sources after coal for pumping, as shown in Section [REF model intro, table on costs]. Renewable generation experiences little or no change with the addition of PHES, expect for wind generation, which increases by 34 GWh due to a decrease in curtailment thanks to additional storage capacity. This will be discussed further in Section PHES dispatch increases as capacity increases, as would be expected. Millions 0 PHES 1 PHES 2 PHES Gas RoI Coal RoI Peat RoI Distillate RoI Gas NI Coal NI Distillate NI GB Generation Figure 10.3: Generation Cost By Category Free IC GWh 0 PHES 1 PHES 2 PHES Figure 10.4: Generation by Category Free IC 25

36 System Marginal Price As discussed in Section [REF SEM introduction], the market system marginal price (SMP) is set by the Short Run Marginal Cost (SRMC) of the marginal generator unit for each half-hour trading period. This energy price is indirectly paid to generator units by consumer electricity bills, thus from the consumer s point of view, it is ideal to keep SMP low. The average annual SMP was found to decrease with the addition of PHES capacity, with average SMP decreasing from 74.77/MWh in 1 PHES to SMP 71.49/MWh in 2 PHES. This reduction can be accounted to the New PHES plant, with a SRMC of zero, displacing high-srmc peaker units as discussed in section PHES 2 PHES Figure 10.5: SMP Annual Profile ( /MWh) Free IC Conventional Plant Operation As conventional power plant such as Gas, Coal and Distillate account for 48% of system generation capacity (see Figure [REF Fuel Mix Pie chart in model intro section]), it is important to consider the implications the addition of PHES have on their operation. The implications for peak load generation, cycling and ramping of conventional plant are examined in the following sections Peak Load Generation Peaker generator units are dispatched when daily electricity demand reaches its peak value in the evening times, due to their rapid start up times and flexible ramping ability to match fluctuating peak load. While these units are useful from the transmission system operator s point of view, the energy they generate comes at a much higher price per MWh than baseload or mid merit power plants due to inefficient operation which drives up system marginal price, as discussed in Section [REF SMP]. PHES plants are also used to provide peak power, as shown in Section [REF historical]. More importantly, PHES units have zero generating costs there was a reduction in the dispatch of fossil fuel peakers such as gas and distillate as PHES is added to the system. Figures [REF] and [REF] below contain examples of the reduction in dispatch of open cycle gas turbine (OCGT) peaker units 26

37 with the addition of PHES capacity, while Table [REF] shows the Short Run Marginal Costs (SRMC) of these units in the base scenario, highlighting the benefit of reducing their dispatch to the system. The table able also contains an example of the SRMC of a mid-merit (Tynagh CCGT) and baseload (Moneypoint 1) generator unit for comparison with the high SRMC of gas and distillate peaker units. GWh 0 PHES 1 PHES 2 PHES Edenderry OCGT Nore Power OCGT Suir OCGT Figure 10.6: Distillate peaker unit dispatch decreases with PHES capacity increase GWh 0 PHES 1 PHES 2 PHES Aghada OCGT 1 Aghada OCGT 2 Marina OCGT Figure 10.7: Gas peaker unit dispatch decreases with PHES capacity increase 27

38 Unit Name Fuel SRMC ( /MWh) Edenderry OCGT Distillate Nore OCGT Distillate Suir OCGT Distillate Aghada OCGT 1 Gas Aghada OCGT 2 Gas Marina OCGT Gas Tynagh CCGT Gas Moneypoint 1 Coal Table 10.1: Comparison of peaker unit SRMC Peaker units which are completely replaced by PHES generation are summarised in Table [REF] below. Unit Name Fuel 0 PHES 1 PHES Generation 2 PHES Generation Generation (GWh) (GWh) (GWh) Ballylumford OCGT 2 Distillate Coolkeeragh OCGT Distillate Kilroot OCGT 1 Distillate Kilroot OCGT 2 Distillate Kilroot OCGT 4 Distillate Table 10.2: Peaker units which cease to be used with the addition of PHES capacity Generator Cycling The integration of increasing levels of renewable power such as wind in deregulated power systems has been shown to cause increased cycling of thermal generators which were originally designed for continuous operation [42]. Generator cycling involves the ramping up/down and starting and stopping of units and causes increased physical deterioration of the unit s components. This results in more frequent part replacement and increased operation & maintenance costs to the plant operator [43]. There are also significant fuel costs related to starting up a generator unit, for example mid-merit CCGT units at Tynagh cost between 98,140 and 116,544 to start up [44]. With renewable power levels of 40% in the 2020, the minimising of generator cycling and the associated costs are a real issue faced by plant operators. To assess rate of generator cycling over the course of the year, the number of starts for the units examined was extracted from simulation results. Figure [REF] below shows the number of times during the year that generator units were started up. Gas generation cycling in the Republic of Ireland decreases by 142 starts with the addition of the New PHES plant, while removing Turlough Hill in 0 PHES results in these units being started 138 more times during the year. PHES also reduced the cycling of distillate plants in the Republic of Ireland, with a reduction of 124 starts in 2 PHES, while there was 113 more starts in 0 PHES. The reduction seen in cycling can be attributed to the ability of PHES plants to cycle quickly, thus replacing the need for less suitable thermal plant to do so. 28

39 There is little change in the cycling of coal units, which are not as prone to being shut down completely with fluctuations in wind, as they supply baseload generation. No. of Starts 0 PHES 1 PHES 2 PHES GAS ROI DISTILLATE ROI GAS NI DISTILLATE NI COAL ROI COAL NI Figure 10.8: Generator Cycling By Category Baseload Ramping Intermittent wind can also prove troublesome for baseload generation such as coal, which are designed to be operated at a consistent, sustained output. Wind generator unit are granted priority dispatch in the Single Electricity Market [45] thus when wind generation is high, baseload coal units may be forced to ramp down generation to accommodate the wind generation. Ramping of these inflexible units can result in increased fuel and VO&M costs for operators. Figure [REF] below shows the length of time over the course of the year that Moneypoint s three units spent ramping up or down. It is clear that the addition of pumped storage capacity reduces ramping of the plant. The addition of the new PHES plant reduces unit ramping time by minutes ( hours); a reduction of 39%. This is again due to PHES plants ability to quickly respond to wind fluctuations and ramp up or down generation as required by system operators. 29

40 Net Exports (GWh) Minutes spent ramping PHES 1 PHES 2 PHES Figure 10.9: Moneypoint Time Spent Ramping Free IC Interconnector Flow Interconnection is seen as a direct competitor to PHES plants as they can provide similar functions such as reserve provision, rapid response times and a method of saving excess energy generation from being lost. The operation of interconnection at different PHES capacities was examined in model analysis to assess the impact the two had on each other. When PHES capacity is added to the power system, there is an increase in imports and a decrease in exports. There is a more notable change with the addition of the New PHES plant in 2 PHES, with imports increasing by 90.1 GWh and exports decreasing by GWh. Note that while net exports decrease, Ireland still remains a net exporter, as was shown in the historical analysis in Section [REF historical]. Ireland exports less power because it is instead used for the pumping of PHES. Ireland imports electricity for the same reason, at times it is cheaper to import electricity for pumping than to buy electricity in Ireland for pumping PHES 1 PHES 2 PHES Figure 10.10: Interconnector Flow Free IC 30

41 Emissions Under EU directives, Ireland is expected to reduce its greenhouse gas emissions by 20% relative to 2005 levels by 2020 [46]. The energy sector was responsible for 21% of Ireland s emissions in 2009, the joint-second largest contributor along with the transport sector [47]. Maximising the dispatch of renewable generators and low carbon intensive thermal generators is therefore imperative if the energy sector is to help Ireland meet its emissions targets. The ability of PHES to facilitate such operations was examined in model analysis. It was found that the addition of PHES capacity resulted in small reductions in overall CO 2 emissions even though generation increases, which can be attributed to the type of plant dispatched. For example, there is an increase in carbon free wind generation, as discussed in Section [REF TGC]. A decrease of 176,631 tonnes was seen with the addition of the New PHES plant in 2 PHES and an increase of 33,458 tonnes when Turlough Hill was removed in 0 PHES. Figure [REF] below shows the change in CO 2 emissions by fuel type with PHES capacity, which evidentially reflects the changes seen in their levels of generation. The displacement of gas and distillate units by PHES (discussed in section [REF]) results in a decrease in emissions, for example gas and distillate generation in the Republic of Ireland decrease by 146,958 tonnes of CO 2 and 15, tonnes of CO 2 respectively with the Addition of the New PHES plant. Million tco PHES 1 PHES 2 PHES DISTILLATE NI COAL NI GAS NI DISTILLATE ROI PEAT ROI COAL ROI GAS ROI Figure 10.11: Emissions By Sector Free IC Wind Curtailment Maximum System Non-Synchronous Penetration (SNSP) levels imposed by transmission system operators ensure security of supply and stable voltage and frequency on power systems. Thus with increased levels of wind generation capacity come the possibility of increased curtailment of wind generators, such as during a windy night when system demand is low. Curtailment of wind can result in loss of revenue for wind farm operators if they do not have a Firm Access Agreement. PHES has been suggested as a method of wind curtailment reduction, and thus the ability of PHES to reduce wind curtailment was examined in model analysis. 31

42 The Curtailment factors present below are calculated in PLEXOS as the percentage of total energy generated by wind units which was not dispatched for the reasons above. For reference, 2011 wind curtailment levels were 2.4% in Republic of Ireland and 1.3% in Northern Ireland [48]. It was found that the addition of PHES capacity reduced wind curtailment levels by providing extra storage capacity. Figure [REF summarises the decreases in curtailment factors for wind generators in the Republic and Northern Ireland. Curtailment Factor (%) ROI Wind 0 PHES 1 PHES 2 PHES NI Wind Figure 10.12: Wind curtailment Factor Free IC The 70% max SNSP network constraint enables what may be considered low levels of wind curtailment, even in 0 PHES; however the curtailed energy still results in notable losses for wind farm operators. Calculating the product of the Average Price ( /MWh) received by wind generator units over the year and the energy they generated which was curtailed allowed an insight into the loss of revenue for wind farm operators, as shown in Tables [REF] and [REF] below. Undispatched Energy (GWh) Price Received ( /MWh) Losses ( ) NI Wind 0 PHES ,349,967 1 PHES ,353,415 2 PHES ,114,207 RoI Wind 0 PHES ,679,232 1 PHES ,594,589 2 PHES ,383,087 Table 10.3: Calculation of monetary losses due to wind curtailment Wind Generator Savings Addition of Turlough Hill 6,081, Addition of New PHES 2,450, Table 10.4: Losses prevented by the addition of PHES 32

43 PHES in the System The addition of the New PHES plant PHES increases the share of PHES in total system generation from 1% to 2% over the year. What became clear from comparing the operation of Turlough Hill and the New PHES plant was the New PHES plant was being utilised more than Turlough Hill. Figure [REF] and Table [REF] below demonstrate the reduction in generation and capacity factor of Turlough Hill in 2 PHES. The reason for the new plant being favoured is its higher round trip efficiency of 75%. GWh New PHES Turlough Hill PHES 2 PHES Figure 10.13: PHES Generation (GWh) Free IC PHES Plant 1 PHES Capacity Factor 2 PHES Capacity Factor Turlough Hill 11.4% 8.5% New PHES N/A 14.0% Table 10.5: PHES Plant Capacity Factors Free IC The feasibility of adding the New PHES to the Irish power system was assessed with a simple payback calculation. A 1.5million/MW estimation of the capital cost of PHES was made based on research in the area [48], as well an on-going PHES project in Coire Glas, Scotland [49]. The New PHES plant earned 18.83m in net profit in 2020, which consists of revenue received for energy generation and reserve provision minus the cost of pumping. Table [REF] below summarises these earnings. Pool Revenue Reserve Revenue Pump Cost Net Profits 33,263,815 11,763,738 ( 26,186,932) 18,840,621 Table 10.6: Summary of PHES Earnings Free IC It was assumed that the New PHES plant would be built by a private party, who could use all profits generated by the plant to pay back the capital investment of 438m, calculated from the above cost per megawatt and the plant s 292MW capacity. This net profit was then assumed to be earned to be earned each of the proceeding years for this simple payback analysis. The results of the analysis are 33

44 Millions presented in Table [REF] and Figure [REF] below. Under the stated assumptions, it was found that the New PHES plant would be paid back in its twenty-third year of operation. This would be considered an unattractive payback time for private investors. PHES Cost Capacity Capital Expenditure Annual Income Payback ( m/mw) (MW) (Years) ,000,000 18,840, Table 10.7: Payback Analysis New PHES Plant Free IC ( 100) ( 200) ( 300) ( 400) ( 500) Figure 10.14: Payback Period Free IC 34

45 Millions Base Model: Fixed Interconnection Total System Generation and Costs The total system generation decreases by over 6,000GWh for each scenario within this model, nearly 90% of this is attributed to the decrease in GB generation associated with Ireland. This is as expected as the flow in the interconnector is lower. The total system costs directly relate to the system generation so the decrease in GB generation causes a decrease in 500m irrespective of PHES scenario. The cost to the Irish system has also decreased due to the overall lower generation, but only in the region of 17m- 22m for each scenario. PHES has the same effect on costs in the system, with TH saving 21m and a new plant reducing costs by 25m as portrayed in Figure below. 1, Start & Shutdown Cost Generation Cost 1, , , , , PHES 1 PHES 2 PHES Figure 10.15: Total Generation Costs Fixed IC It is again seen that the addition of a new PHES plant increases the overall generation of the system by quite a significant amount, 262GWh. This increases is due to the pumping load of PHES. The additional generation is directly accounted for in the pump load of bothe PHES plants. In the 1 PHES scenario the pump load is 261GWh and in the 2 PHES scenariothe pump load is 523GWh. 35

46 PHES 1 PHES 2 PHES WASTE ROI ROI Wave ROI Wind NI Wind COAL NI GAS NI DISTILLATE ROI PUMPED STORAGE ROI HYDRO ROI PEAT ROI COAL ROI GAS ROI Figure 10.16:Total System Generation Breakdown (GWh) Fixed IC The decrease in generation cost directly relates to how the system is operated and what generators are dispatched. For the Fixed IC scenario gas generation in ROI and Distillate generation decrease as PHES is added, which is one of the main reason the system costs decrease. PHES is operated at peak times displacing conventional gas and distillate plants in the Republic reducing their associated generation and overall cost by over 32m. The reduction in gas and distillate generation is displaced by Coal, Peat, Wind and PHES. Coal generation in ROI and NI increases as PHES capacity is added to the system but coal generation does not reach the amount of generation seen in the Free IC scenario as there is less export capacity available and less overall generation required. Coal generation is cheaper than gas generation and the large increase in generation sums to 8.25m. This value plus 500,000 for peat and free wind shows where the major saving is coming from as this 229GWh is produced for 8.75m and the reduction of 271GWh of gas saves the system 28m. It is again seen that wind generation increases as PHES capacity is added to the system as this energy can now be stored rather than curtailed. This is discussed further in section

47 Millions 0 PHES 1 PHES 2 PHES Gas RoI Coal RoI Peat RoI Distillate RoI Gas NI Coal NI Distillate NI GB Generation Figure 10.17: Generation Cost Breakdown By Category Fixed IC Generation GWh 0 PHES 1 PHES 2 PHES Figure 10.18: Generation By Category Fixed IC 37

48 System Marginal Price The fixed model results in a higher SMP for all PHES capacity scenarios, for the 0PHES scenario the SMP is 2.7 /MWh greater. The addition of pumped storage has the same effect in this model, reducing the SMP as PHES capacity is added. The average SMP between the 1 PHES scenarion and 2 PHES scenario decreases by 0.91 /MWh as portrayed in figure below SMP Annual Profile ( /MWh) 1 PHES 2 PHES Figure 10.19: SMP Annual Profile ( /MWh) Fixed IC The general higher SMP in this model was predicted and is due to the fact that the interconnector is not as free to supply peak loads as it previously was in Free IC model. The system therefore dispatches the next expensive generator where importing may have proved cheaper. The SMP increases by 2.4 /MWh when the interconnector is fixed, the weekly SMP showing this decrease is charted in figure below. It is seen that for large periods of the year having an ability to freely import power via the interconnectors reduces the SMP SMP Annual Profile ( /MWh) 2 PHES Fixed 2 PHES Free Figure 10.20: SMP Annual Profile ( /MWh) Fixed IC vs. Free IC 38

49 Conventional Plant Generation Generator Cycling Fixing the interconnector flow takes out some of the flexibility available to the system this is seen clearly in the cycling of generators. Gas and distillate plants cycle many more times to provide peak power which was being provided by interconnection in the Free IC model. The same trend is seen with the addition of PHES in that gas and distillate units cycle less. In the 2 PHES scenario gas and distillate units cycling has nearly reduced to levels seen in the Free IC model, this has been achieved by PHES units cycling 1,983 times more in the Fixed IC model PHES 1 PHES 2 PHES GAS ROI COAL ROI DISTILLATE ROI GAS NI COAL NI DISTILLATE NI Figure 10.21: Generator Cycling By Category Fixed IC Baseload Ramping Fixing the interconnector flow causes Moneypoint to ramp for 157,500 minutes (2,625 hours) more than it did when the interconnector was free to generate. This is because the interconnector is often used to quickly accommodate the fluctuations in generation, especially with increased wind generation. PHES also provides this fast response and reacts quickly to fluctuations in generation which reduces the time Moneypoint spends ramping as seen in figure below. It is again clear that the addition of pumped storage capacity reduces ramping of the plant. The addition of the new PHES plant reduces unit ramping time by 75,300 minutes (1,255 hours); a reduction of 21%. This is again due to PHES plants ability to quickly respond to wind fluctuations and ramp up or down generation as required by system operators. 39

50 Net Exports (GWh) PHES 1 PHES 2 PHES Figure 10.22: Moneypoint Ramping Time Fixed IC Interconnector Flow As the purpose of this model is to fix the interconnector flow the imports and exports have been initially established. For all capacities of pumped storage imports total 1,430.52GWh and exports total 3,628.23GWh resulting in a net exports of 2,197.72GWh. Fixing the interconnector flow involves setting the flow for every half hourly period for the year, this takes the decision to dispatch interconnection away from the model and takes away the flexibility associated with this Net Exports PHES 1 PHES 2 PHES Figure 10.23: Interconnector Flow Fixed IC Emissions There are far less overall savings in emissions in the fixed interconnector model only totalling 1,885.97t CO 2 which is only 1% of the savings previously achieved. This is mainly due to the fact ROI coal generation increased, therefore increasing emissions. There is also less scope for savings in emissions as there is less generation overall and the emissions are already 322,208.04tCO 2 lower than the base model. 40

51 (t CO2/annum) Even with the reduced generation and emissions ROI gas and NI distillate generate more and therefore have more associated emissions. This trend is present because these units were used much more for peak generation as there is less capacity available from interconnection which is often used for peak generation. 18,000, ,000, ,000, ,000, ,000, ,000, ,000, ,000, ,000, DISTILLATE NI COAL NI GAS NI DISTILLATE ROI PEAT ROI COAL ROI GAS ROI - 0 PHES 1 PHES 2 PHES Figure 10.24: Emissions By Sector Fixed IC Wind Curtailment There are higher curtailment factors for the fixed model as there is less flexibility in the system due to the reduction in exports via the interconnectors. This is the reason for reduced generation from the wind sector. The addition of PHES greatly improves the curtailment factor and in the 2 PHES scenario the curtailment is almost as low as the base case level, this trend is shown in figure below. Curtailment Factor (%) NI Wind 0 PHES 1 PHES 2 PHES ROI Wind Figure 10.25: Wind Curtailment Factor Fixed IC 41

52 Million There are greater savings present to wind farm operators with the addition of PHES capacity due to there being larger overall losses. As shown in figure below the 2 PHES scenario reduces losses to within 900,000 which is extremely effective as in the 0 PHES scenario the losses were over 3.2 million greater Fixed Free PHES 1 PHES 2 PHES Figure 10.26: Wind Farm Losses Fixed IC vs. Free IC Pumped Storage in the System Pumped storage generates 108GWh (1 PHES) and 193GWh (2PHES) less in the Fixed IC scenario due to the overall decrease in generation. This is the main reason that the income received by pumped storage plants decreases by 7.8m (1 PHES) and 14m (2 PHES). Even with the decrease in generation it was seen that PHES plant cycled 1,270 (1 PHES) and 1,983 (2 PHES) more times for the Fixed IC model. This was due to the inflexibility of the interconnectors forcing pumped storage to generate for more peak loads that were previously provided by interconnection. The capacity factor of each pumped storage unit is around 4% lower in the Fixed IC model due to the overall decrease in generation. 42

53 Generation (GWh) New PHES 1 PHES 2 PHES Turlough Hill Figure 10.27: PHES Generation (GWh) Fixed IC The addition of the new pumped storage plant causes a decrease in the generation of Turlough Hill as seen in the Free IC model. This is due to the newer plant having a higher efficiency and displacing the existing, less efficient plant. PHES Cost Capacity Capital Expenditure Annual Income Payback ( m/mw) (MW) (Years) ,000,000 11,901, Table 10.8: Payback Analysis New PHES Plant Fixed IC The same feasibility analysis performed in the Free IC model was completed for the Fixed IC model in Table 10.8 above. The profits of the new PHES plant are much lower than the Free IC model resulting in a longer payback period. The main reason for the decrease in profits is the decrease in generation as the majority of revenue comes from energy payments as seen in Figure. In the Fixed IC model pumped storage is providing 50% less reserve than in the Free IC model, this is because PHES available response has decreased. PHES is losing out on 9m and 12.5m in reserve revenues for the 1 PHES and 2 PHES scenarios respectively compared to the Free IC model. The simple payback was again calculated as in the Free IC model. The plant would not be an attractive payback for a private investor but if the system operator invested in the plant the system savings of 25m would result in a much shorter payback of 17.5 years. 43

54 Millions ( 100) ( 200) ( 300) ( 400) ( 500) Figure 10.28: Payback Period Fixed IC 44

55 10.3. Market Model The transmission system operators use market scheduling program, MSP, to generate a stack of the lowest cost generator bids necessary to meet the predicted marginal system demand as discussed is section 5.2. This model removes the transmission constraints discussed in section 8.8. This model was run to examine the difference between actual generation and the schedule predicted by the MSP Total System Generation and Costs The market model results in a decreased total system cost of roughly 40m in comparison to the base case model. The addition removal of Turlough Hill increases the system cost by 25.7m and the addition of a new PHES plant reduces the system cost by 19m for the year. These savings are slightly better than previously seen. It is interesting to note that even with decreases system costs the cost of generator cycling is greater in the Market model. Billions Total Start & Shutdown Cost Total Generation PHES 1 PHES 2 PHES Figure 10.29: Total System Generation Costs Market Model It is again seen that even though the cost of generation decreases the system generation actually increases by a greater amount than seen in the base case model. The overall generation is lower in the market model as it does not account for reserve generation which is required for the system model. There are several differences in how the generators are utilised in the market model, gas RoI, coal RoI and NI, and distillate RoI and NI all have lower generation in the Market model. These differences are matched by increases in peat, wind and GB generation. Distillate units in Northern Ireland are not dispatched ever in the market model. The decrease in coal and gas generation relates directly to the inertia and coal plant constraints as seen in section Without these constraints the model is freer to shut down more plants to reduce system cost but in reality this would not be allowable for system stability purposes. 45

56 The addition of PHES to the system has similar effects as seen in the base case with gas and distillate units being replaced. It is also seen that peat and wind energy increase as the curtailment of these sectors is nearly at 0%. A major difference seen between the base model and the Market model is the continued reduction in coal generation and increase in GB generation used for pumping. GB generation is cheaper than generation in indigenous plants and with constraints off these plants can be shut down and more imports utilised WASTE ROI Wind Wave COAL NI GAS NI DISTILLATE ROI PUMPED STORAGE ROI HYDRO ROI PEAT ROI COAL ROI GAS ROI 0 0 PHES 1 PHES 2 PHES Figure 10.30: Total System Generation Breakdown (GWh) Market Model Interconnector Flow For the market model imports increase and exports decrease at a greater rate than seen in the base case model. For the 2 PHES scenario the difference between imports is 284GWh and the difference in exports is 309GWh. This occurs because there is more flexibility in the system with the removal of constraints allowing GB generation to displace indigenous generation. 46

57 Net Exports (GWh) PHES 1 PHES 2 PHES Figure 10.31: Interconnector Flow Market Model Emissions For the market model emissions are lower because the generation for many sectors is lower as discussed earlier in Section As this model is not precise in what generators are dispatched it therefore is not as accurate at predicting emissions. Million tco DISTILLATE NI COAL NI GAS NI DISTILLATE ROI PEAT ROI COAL ROI GAS ROI PHES 1 PHES 2 PHES Figure 10.32: Emissions By Category Market Model Wind Curtailment This model turns off all constraints including System Non-Synchronous Penetration as discussed is section This previously limited the maximum SNSP to 70% and in the market model this is basically uncapped. This model therefor reduces the capacity factor greatly to almost zero and the addition of PHES has the same decreasing effect on the curtailment factor as previously seen. 47

58 Curtailment Factor (%) PHES 1 PHES 2 PHES NI Wind ROI Wind Figure 10.33: Wind Curtailment Factor Market Model With the reduction in curtailment there are large decreases in the losses that wind farm operators would realistically be receiving. The losses are already inherently low and the addition of PHES capacity reduces the losses to only 337,000. Millions Base Market PHES 1 PHES 2 PHES Figure 10.34: Wind Farm Losses Base vs. Market Model It is interesting to note that curtailment still occurs in this model because there are times when demand is low and wind generation is supplying the entire system load with extra generation spare which gets curtailed Pumped Storage in the System The very same trend is seen in this model with the new PHES plant taking generation away from Turlough Hill as shown in figure below. 48

59 Generation (GWh) New PHES 1 PHES 2 PHES Turlough Hill Figure 10.35: PHES Generation Market Model PHES generates slightly more than present in the base case but the profits received are much less because reserve revenue has been removed for the market model. The reserve revenue lost totals 11.76m for the new PHES plant. Table 10.9: Payback Analysis Market Model PHES Cost Capacity Capital Expenditure Annual Income Payback ( m/mw) (MW) (Years) ,000,000 7,649, Table 10.10: Payback Analysis Market Model The payback results seen below in figure clearly show the importance of reserve payments to PHES. The base case model includes the reserve payments and the market model does not. Millions Free IC Base Market Model 0 ( 100) ( 200) ( 300) ( 400) ( 500) Figure 10.36: PHES Payback Period Base vs. Market model 49

60 Billions Carbon Tax Sensitivity Carbon tax payments are made by generator units for the fuel they burn, and are incorporated in their SRMC. Thus future carbon tax levels will directly impact the total system cost and price of energy paid by consumers. As of Budget 2012, carbon tax on gaseous and liquid fossil fuels stands at 20 per tonne of CO2 emitted. This did not apply to solid fuels such as peat and coal, however In Budget 2013 it was announced that the carbon tax will be extended to solid fuels on a phased basis. A rate of 10 per tonne will be applied with effect from 1 May 2013 and a rate of 20 per tonne from 1 May 2014 [50]. It is currently unclear what the carbon tax on fuels will be in 2020, and while the 30/tonne CO 2 used in base case analysis (hereby C 30) is credible, it is not a certainty. Thus a sensitivity analysis was carried out to assess the impact on the power system of a high carbon tax of 45/tonne CO 2 (herby C 45) and a low carbon tax 15/tonne CO 2 (hereby C 15) in 2020 with varied PHES capacity. The investment payback of the New PHES plant in these scenarios was also examined Total Generation Cost The total generation cost of the system was found to be directly related to carbon tax. For the 1PHES scenario, the total generation cost of the system in C 45 was 315,871, greater than in C 30 while total generation cost in C 15 was 325,175, less than in C 30. Increased PHES capacity resulted in a reduction in total system generation cost, as was found in Section [REF TGC section]. The addition of the New PHES plant reduced total generation cost (relative to 1 PHES) by 16,954, in C 45. Thus additional PHES capacity could be used to offset increased total generation costs associated with a high carbon tax C 15 C 30 C 45 0 PHES 1 PHES 2 PHES Figure 10.37: Total System Generation Costs For Carbon Tax Sensitivity A significant outcome of the carbon tax sensitivity was that when carbon taxes were low in C 15, the system took advantage of this by increasing the amount of coal generation dispatched and decreasing the amount of gas generation dispatched over the course of the year. While this may be 50

61 GWh considered not environmentally conscious on the part of the system operators, it is important to remember that the objective of the transmission system operator s market scheduling software and the PLEXOS solver to generate the least cost dispatch portfolio of generators to meet system demand. Coal costs 2.12/GJ and the average annual cost of Gas is 7/GJ, thus it is unsurprising that in a scenario where the use carbon-intensive fuel such as coal was not heavily penalised by emissions taxes that this fuel would be favoured over more the expensive alternative of gas. Conversely, a large proportion of coal generation was replaced by gas when carbon taxes were high in C 45. Overall, total system generation decreased as carbon tax increased and thus increased cost of generation. Figures [REF] below demonstrate the effects of carbon tax on the dispatch of generators by fuel type in the base case (1 PHES), specifically the dispatch of gas and coal which are the most sensitive to the change in carbon tax. Increasing the carbon tax in C 45 resulted in a 4207 GWh decrease in coal generation and a 2718 GWh increase in gas generation over the course of the year, relative to C 30. On the other hand, decreasing the carbon tax in C 15 resulted in a 1362 GWh increase in coal generation and an 1111 GWh decrease in gas generation DISTILLATE NI DISTILLATE ROI PUMPED STORAGE ROI WASTE ROI HYDRO ROI PEAT ROI COAL NI COAL ROI GAS NI GAS ROI 0 C 15 C 30 C 45 Wind Wave Figure 10.38: System Generation For Carbon Tax Sensitivity 51

62 GWh Gas Coal C 15 C 30 C 45 Figure 10.39: Relationship between Gas and Coal dispatch and carbon tax System Marginal Price The SMP was also seen to be directly related to level of carbon tax in the system. When carbon tax was increased in C 45, increased fuel costs increase generator unit short run marginal costs, thus increasing the average annual SMP, as demonstrated in Figure [REF] below. The addition of PHES capacity reduces SMP, as was seen in Section 9.6, and thus helps mitigate the increased prices caused by high carbon tax. /MWh C 15 C 30 C PHES 1 PHES 2 PHES Figure 10.40: Relationship between SMP and carbon tax Emissions Gas has an emissions production rate of 56.1 kg CO 2 /GJ in the model, while coal has a much higher rate of 94.6 kg CO 2 /GJ. The increased share of total generation from gas units in C 45 therefore contributes to a decrease in CO 2 emissions as it is less carbon intensive, while emissions in C 15 are higher due to the increased use of coal, as seen in Figure [REF] below. In the base case (1 PHES); increasing the carbon tax from 30 to 45/tCO 2 resulted in an annual emissions reduction of 52

63 2,797,641 tonnes of CO 2, while decreasing the carbon tax to 15/tCO 2 resulted in an annual emissions increase of 921,076 tonnes of CO 2. Million tonnes CO2 C 45 C 30 C PHES 1 PHES 2 PHES Figure 10.41: Relationship between CO2 emissions and carbon tax PHES in the System It is clear that the benefit of the New PHES plant to the system when there is a high carbon tax on fossil fuels. PHES generation increases with an increase in carbon tax, for example there is an increase in PHES total generation of 3.75 GWh with the increase in carbon tax in 2 PHES. However the net profit earned by the New PHES plant in C 45 is 1.04m lower than the plant s net profit in the base C 30 model. This is due to the increased cost associated with buying electricity for pumping, which is not recuperated to the same effect as in C 30. Table [REF] below summarises these findings. Carbon Scenario Pool Revenue Reserve Revenue Pump Cost Net Profits C 30 33,263,815 11,763,738 ( 26,186,932) 18,840,621 C 45 40,125,496 12,037,528 ( 34,358,752) 17,804,272 Table 10.11: Comparison of New PHES earnings in C 30 and C 45 scenarios The economic feasibility of the New PHES plant was re-calculated for the C 45 net profit of 17,804,272, and resulted in an increased payback period of 24.6 years, as shown in Table and Figure below. PHES Cost Capacity Capital Expenditure Annual Income Payback ( m/mw) (MW) (Years) ,000,000 17,804, Table 10.12: Calculation of New PHES payback in C 45 scenario 53

64 Millions ( 100) ( 200) ( 300) ( 400) ( 500) Figure 10.42: New PHES cumulative cash flow in C 45 Scenario The most significant outcome of carbon tax sensitivity analysis was the direct influence that carbon tax on total system costs; increasing tax and thus the price paid for fuel results in more expensive generation, higher price paid for electricity through the SMP and decreased revenue for generators. One positive outcome is the reduction in CO 2 emissions encouraged by high carbon taxes. Finally, it is again clear that the PHES units add benefit to the system by mitigating the increased system costs and again reducing SMP. However due to decreased energy revenue, the New PHES plant s payback time increases compared to the base case. This highlights the inherent issue for PHES feasibility in a primarily energy payment-based system. 54

65 Billions Reduced Interconnection Scenario Moyle Interconnector is currently experiencing technical issues associated with the degradation of insulation in its HVDC cable. As a result the Moyle is limited to operating at half capacity (250 MW) when not on outage for repairs [REF]. To examine ramifications of reduced interconnection between Ireland and Great Britain in 2020 with different levels of PHES capacity, a scenario was simulated where Moyle was offline was carried out. This was done by reducing the interconnector capacity in the model by 500MW so that the maximum interconnector flow available was 500MW (including static reserve provision) Total System Generation and Costs Comparing the Total Generation Cost of the system with the Moyle interconnector online and offline, it was found that there was a decrease of 46,255, in the Base Case (1 PHES), with similar decreases seen in the other two scenarios as seen in Figure [REF] below. As was seen in Section [REF TGC analysis], the addition of PHES capacity further reduces Total Generation Costs Moyle Online Moyle Offline PHES 1 PHES 2 Phes Figure 10.43: Total Generation Cost - Moyle online vs. offline By comparing the total generation of units by fuel type, the reasons for the major reduction in Total Generation Cost are evident. As Figures [REF] and [REF] show, there is a decrease in system generation over course of the year when Moyle is offline. This is due to a reduction in the capacity to generate electricity and export it to the Great Britain system and thus a reduction in the demand seen by generator unit. While the annual generation of the majority of generator units decreases, PHES generation actually increases when Moyle is offline, as the plant is required to provide more energy storage with the reduction in export capacity. These results further add to the argument that PHES and interconnection compete on the system. Generation Moyle Moyle Δ (GWh) Online Offline 1 PHES PHES Table 10.13: PHES Generation - Moyle online vs. offline 55

66 GWh Moyle Online 0 PHES 1 PHES 2 PHES Moyle Offline Figure 10.44: Total System Generation - Moyle online vs. offline GWh Moyle Online Moyle Offline Gas RoI Coal RoI Peat RoI Hydro RoI PHES RoI Distillate RoI Gas NI Coal NI Distillate NI Wind & Wave Waste RoI Figure 10.45: 1PHES Generation by Fuel Type - Moyle online vs. offline Conventional Plant Operation While the reduction in interconnection capacity may be considered advantageous for PHES units and their owners, it was found to be disadvantageous from a system-wide perspective. The reduction in interconnection capacity inhibits the flexibility of the system to handle fluctuating wind generation. As figures [REF] show, reduced interconnection capacity results in an increase in wind curtailment, baseload unit ramping and generator cycling. While additional PHES is again shown to increase flexibility and mitigate these negative impacts, the system still suffers from the loss of interconnection. 56

67 Generator Cycling Generation (GWh) Generation (GWh) No. of Starts Number of Starts Moyle Online Moyle Offline 500 Figure 10.46: Negative impact of reduced interconnection capacity on Gas RoI operation Figure [REF] above gives an example of some negative impacts of the loss of interconnection capacity on Gas generation in the Republic of Ireland. It can be seen that while gas units are generating less, they are being cycled more frequently. Being forced into this ineffective operation results in reduced earnings and increased starting costs for these units, as seen in Table [REF] below. Moyle Online Moyle Offline Δ Start & Shutdown Costs ( ) 37,949, ,878, ,929,094 Net Revenue Earned ( ) 306,713, ,534, , Table 10.14: Decreased net revenue for Gas RoI units with Moyle offline Baseload Ramping As previously discussed in Section the ramping of baseload plant is preferred to be kept to as minimal a value as possible. With the reduction in interconnection for all PHES capacity scenarios there are increases in ramping time associated with Moneypoint as seen in figure below. This increase in ramping time is due to less flexibility in the system and less opportunity for exports causing Moneypoint to ramp down and up more often. The same trends are seen with the addition of PHES to the system reducing ramping time as PHES is utilised to accommodate for the fluctuations in generation associated with wind generation. 57

68 Minutes of Ramping Moyle Offline Moyle Online PHES 1 PHES 2 PHES Figure 10.47: Minutes spent ramping up and down by Moneypoint coal units Wind Curtailment % Wind Curtailment Moyle Online Moyle Offline PHES 1 PHES 2 PHES Figure 10.48: Percentage of wind energy curtailed in the Republic of Ireland - Moyle online vs. offline Figure [Ref] above shows the increase in wind curtailment when Moyle is offline. Calculating the product of the Average Price ( /MWh) received by wind generator units and the energy they generated which was curtailed allowed an insight into the loss of revenue for wind farm operators with Moyle offline, as shown in Table [REF] below. Note that PHES can again be seen to reduce losses for wind generators. Moyle Online Moyle Offline Revenue Lost 0 PHES 12,029, ,446, ,417, PHES 5,948, ,759, ,811, PHES 3,497, ,632, ,134, Table 10.15: Wind generator revenue lost due to curtailment 58

69 PHES in the System PHES is utilised to a greater extent with Moyle offline, this is due to PHES generating at more peak times that were being supplied by interconnector imports previously. PHES Cost Capacity Capital Expenditure Annual Income Payback ( m/mw) (MW) (Years) ,000,000 18,322, Table 10.16: PHES Plant Capacity Factors Reduced IC The profits of the new PHES plant are very similar to the profits seen in the base case with Free IC, this results in a similar payback curve as seen below in figure It is again interesting to note that if the system operator was to invest in the new PHES plant the system savings of 23.3m could directly be attributed to the new plant and a payback period of years would be achieved. Millions ( 100) ( 200) ( 300) ( 400) ( 500) Figure 10.49: Payback Period Reduced IC From the analysis of this scenario, it is clear that the power system suffers with the reduction in interconnector capacity, reductions in system flexibility resulting in ineffective gas unit operation and increased wind curtailment.phes benefits from a reduction in interconnection capacity, with an increase of 40GWh generation over the course of the year. While additional PHES capacity was found to mitigate the inflexibility caused, it could not prevent losses completely. 59

70 11. Conclusion Conclusion and Future Work This report set out to answer questions regarding the feasibility of PHES and its impact on the operation of the Irish power system: Does PHES benefit the system? With a number of PHES plants at varied stages of planning in Ireland such as those of Natural Hydro Energy [REF] and Organic Power [REF], is another a new PHES plant necessary or feasible? Do interconnection and PHES complement or compete? Research was first carried out on the operation of the Single Electricity Market, in which all generator units on the Irish power system must participate, to highlight the dispatch and payment of all generator units, and specifically PHES. Historical operation data for the Irish power system over the period of July 2009 to July 2011 was then attained from the Single Electricity Market Operator (SEMO). This data was used to carry out analysis on the real life operation of Ireland s sole PHES plant, Turlough Hill, and also how the system operated with and without PHES. A PLEXOS model of the 2020 Irish power system was perfected with support from the UCC Sustainable Energy Research Group, and simulated in three scenarios of PHES capacity: 1 PHES, which simulated the 2020 system with current PHES capacity (Turlough Hill); 2 PHES, where a new PHES plant was added to the system; and 0 PHES, where Turlough Hill was removed from the system. It was shown that additional PHES capacity reduced generator costs and system marginal price by displacing gas and distillate generation. CO 2 emissions were also found to reduce for the same reason. The impact of additional PHES capacity on interconnector operation was also investigated and shown to reduce net exports, as more energy could be stored rather than exported. The addition of PHES capacity was also found to reduce the amount of wind energy curtailed by providing extra storage. PHES was found to benefit the operation of conventional baseload and midmerit plant, which have been shown to experience increased fuel and operation and maintenance costs associated with excessive ramping and cycling caused by high levels of wind penetration. The feasibility of the New PHES plant modelled was also assessed using an investment cost of 1.5m/MW, resulting in a payback in excess of twenty years. The model was then simulated without network constraints of reserve requirements to investigate how a market scheduling software like that used by SEMO might differ in its scheduling of units. It was found that total system costs reduced in this scenario, as the model did not have to adhere to network constraints and could schedule the lowest cost units at all times, which could cause system instability if done in real life. It was also found that the profits of PHES plants were significantly reduced due to the lack of reserve provision and the associated payments, highlighting the importance of these payments to peaker units such as PHES plants. A sensitivity analysis was then carried out to assess the impact of a low and high carbon tax on 2020 system operation. It was found that increased carbon tax resulted in increased system costs and system marginal price. The addition of new PHES plant was seen to mitigate some of these cost 60

71 increases, however net profits actually reduced due to the increased cost of electricity for pumping. This finding lends to the argument that predominately energy payment-based markets such as the SEM do not value the true benefit of PHES plants. Finally, a scenario was simulated with the Moyle interconnector offline, thus halving interconnection capacity. It was found that with Moyle offline, system flexibility reduced. The addition of the New PHES plant restored some flexibility; again reducing conventional plant cycling, baseload ramping and wind curtailment. To summarise, this report questioned whether the Irish power system benefits from PHES. The results were largely positive, with improvements seen in transmission system operation and reductions in SEM costs. However, the addition of the New PHES plant may be considered somewhat unattractive from a private investment point of view. REF Future work could look more closely at the economic feasibility of PHES in Ireland; barriers and what could be done to make investment more attractive validatation of the model Extended simulation; PHES plants are characterised by long asset life (typically 50 to 100 years), high capital cost, low operation and maintenance cost and round-trip efficiencies of 70-75%. [REF PD] Wind and PHES combined? Does the SEM undervalue PHES? Model the Irish power system for extended simulation durations to uncover more long term results Ramifications of a north-west European market 61

72 Works Cited [ International Energy Agency, International Energy Agency, [Online]. Available: 1 [Accessed ]. ] [ EirGrid plc, [Online]. Available: 2 ] %20Ireland%20Day%20Summit.pdf. [Accessed ]. [ EirGrid plc, Annual Renewable Report 2012, Eirgrid plc, Dublin, ] [ EirGrid & SONI Operations, All Island Wind and Fuel Mix Report - November 2012, EirGrid plc & 4 SONI Ltd., Dublin, ] [ International Energy Agency, Variability of Wind Power and Other Renewables - Management 5 Options and Strategies, International Energy Agency, Paris, ] [ L. Freris and D. Infield, Renewable Energy in Power Systems, West Sussex: John Wiley & Sons Ltd., ] [ The Single Energy Market Operator, The SEM Trading and Settlement Code, The Single Energy 7 Market Operator, Dublin, ] [ Distributed Energy Company Group Ltd., SmartPower.ie, Distributed Energy Company Group 8 Ltd., [Online]. Available: [Accessed ]. ] [ Natural Hydro Energy, naturalhydroenergy.com, Natural Hydro Energy, [Online]. Available: 9 [Accessed ]. ] [ S. o. Ireland, Spiritofireland.ie, Spirit of Ireland, [Online]. Available: 1 [Accessed ]. 0 ] [ T. Jacob, Pumped Storage in Switzerland - and outlook beyond 2000, Stucky Consulting 1 Engineers Ltd.,

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74 ] [ Single Electricity Market Committe, SEM Committe Strategy Day Information Paper (SEM ), Single Electricity Market Committe, Dublin, ] [ Single Electricity Market Operator, SEM Trading & Settlement Code - Helicopter Guide, Single 2 Electricity Market Operator, Dublin, ] [ The Single Energy Market Operator, Pricing and Scheduling Factsheet, [Online]. Available: 2 [Accessed ] 2012]. [ Single Energy Market Operator, Settlement FAQ, [Online]. Available: [Accessed ]. 2 4 ] [ The Single Energy Market Operator, The Capacity Payment Mechanism and Associated Input 2 Parameters, Single Energy Market Operator, ] [ S. E. M. Committee, SEM Fixed Cost of a Best New Entrant Peaking Plant & Capacity 2 Requirements for the Calander Year 2013 Consultation Paper, Single Energy Market Committee & 6 All Irland Project, ] [ J. Parsonage, Industry Presentation: SEM Capacity Payments, SEMO, Dublin, ] [ A. Chiodi, J. P. Deane, M. Gargiulo and B. O Gallachóir, Modelling Electricity Generation - 2 Comparing Results: From a Power Systems Model and an Energy Systems Model. 8 ] [ Energy Exemplar, [Online]. Available: 2 [Accessed ]. 9 64

75 ] [ Commission for Energy Regulation, Redpoint Validation Forecast Model and PLEXOS Validation 3 Report 2010, ] [ The Single Electricity Market Operator, Dynamic Reports, [Online]. Available: [Accessed ]. 3 1 ] [ Mutual energy, Interconnector Physical flows, Moyle Interconnector Ltd., [Online]. Available: [Accessed ]. ] [ ESB, Turlough Hill & Liffey Stations, ESB, [Online]. Available: [Accessed ]. 3 3 ] [ Smart Power, Smart Power, ECHELON, [Online]. Available: 3 Hill-ESB-TH4.cfm. [Accessed ]. 4 ] [ ESB, All-Island Market Modeling Programme, [Online]. Available: rl=http%3a%2f%2fwww.allislandproject.org%2fgetattachment.aspx%3fid%3d39f4c30c-0a59- ] 4142-b878- e49d30b0d324&ei=en81uefrm4yfhqfd_ydadw&usg=afqjcngqvza1xwu6vxkgy_3_axnksunzwg. [Accessed ]. [ EirGrid, Generation Adequacy Report , [Online]. Available: 3 [Accessed ]. ] [ SEMO, Fuel Mix Disclosure, [Online]. Available: QFjAC&url=http%3A%2F%2Fwww.semo.com%2FPublications%2FGeneral%2FFMD%2520Presentation%2520v3.ppt&ei=0C1OUbrMC82Ch ] QfVrIDIAQ&usg=AFQjCNFpykHFvi_a6GLTHZgfKN5r99UMFA. [Accessed ]. [ Comission for Energy Regulation & Utility Regulator, Validation of Market Simulation Software in 65

76 3 SEM to end 2013, Comission for Energy Regulation & Utility Regulator, ] [ Mutual Energy, The Moyle Interconnector, Mutual Energy, [Online]. Available: 3 [Accessed ]. 9 ] [ The EirGrid Group, The DS3 Programme Brochure, The EirGrid Group. 4 0 ] [ The EirGrid Group, Ensuring a Secure, Reliable and Efficient Power System in a Changing 4 Environment, The EirGrid Group, June ] [ N. Troy, Evaluating which forms of flexibility most effectively reduce base load cycling at large 4 wind penetrations, Energynautics, Dublin, ] [ J. G. A. S. Fred Starr, Damage to Power Plant Due to Cycling, European Technology Development 4 Ltd., United Kingdom, ] [ SmartPower, Market Prices - Commercial Offer Data, SmartPower, [Online]. Available: 4 [Accessed ]. 4 ] [ Comission for Energy Regulation & Utility Regulator, Treatment of Price Taking Generation in Tie 4 Breaks in Dispatch in the Single Electricity Market and Associated Issues - Consultation Paper, 5 Comission for Energy Regulation, Dublin, ] [ Sustainable Energy Authority of Ireland, Energy Targets FAQ, Sustainable Energy Authority of 4 Ireland, [Online]. Available: 6 [ ] [Accessed ]. [ Environmental Protection Agency Ireland, What Are Ireland's Greenhouse Gas Emissions Like, 4 Environmental Protection Agency Ireland, [Online]. Available: 66

77 7 ] areirelandsgreenhousegasemissionslike/. [Accessed ]. [ P. Deane, Improved modelling of pumped hydro energy storage, Cork, ] [ BBC News, SSE plans new 800m hydro electric storage scheme in Great Glen, [Online]. Available: 9 [Accessed ]. ] [ Citizens Information Board, Citizen's Information - Carbon Tax, Citizens Information Board, [Online]. Available: 0 ] x.html. [Accessed ]. [ Sustainable Energy Research Group, Irish TIMES Energy Systems Modelling, University College 5 Cork, [Online]. Available: [Accessed ]. ] 67

78 12. Appendix 1: Logbook Week 1: Oct 8 th Completed tasks: Both students were given Paul Deane s Thesis to review to get an overview of PHES and what aspects could be research in the project. Power Systems Modelling 101 was reviewed by both students to gain a knowledge of the transmission network and how it works. Results: It was decided that perusing a project in this area would be of interest to the students and also be beneficial to power systems operators. The research would also tie in with previous research in Paul Deane's Thesis. Objectives for Next Week: It is planned that the students will have an initial meeting with supervisors to discuss the outline and scope of the project. Week 2: Oct 15 th Completed tasks: A meeting was held with the project supervisors, Paul Deane and Eamon McKeogh to discuss and outline plan for project. The review of Paul Deane s Thesis continued in order to gain a well-rounded understanding in the area of PHES It was deemed important to gain a good working knowledge of the rules and operation of the Single Electricity Market (SEM). This week both students researched the area of participant offer process: Generator Technical Offer Data (such as ramp rates and minimum stable generation levels) and Commercial Offer Data (Price-Quantity Pairs and start-up Costs) are submitted by Participants for each half hour period of a Trading day. Results: A scope for the project was created and a general outline for the project was made including a plan of work to be completed. The students began to expand their knowledge in the rules and operation of the Single Electricity Market, especially in the area of participant offer process. 68

79 Objectives for Next Week: Obtain required DQ data from SEMO. Continue to Research SEM in the area of o System Marginal Price (SMP) and Dispatch of inmerit generators. Week 3: Oct 22 nd Completed tasks: The students completed similar work in researching the SEM, this week focusing on System Marginal Price (SMP) and Dispatch of in-merit generators. Transmission System Operator runs a Market Scheduling Program (MSP) which creates a stack of priority Predictable Price Taker and the least cost Price Maker generator units to meet system demand, and sets the SMP which is paid to these generators. Aidan contacted SEMO regarding DQ data for Historic TH outage analysis and it seems it may take some time to acquire this data. Results: The students furthered their knowledge of the SEM, more precisely in the area of System Marginal Price (SMP) and Dispatch of in-merit generators. The DQ historical data analysis part of the project is now pending on when the data is received from SEMO. Objectives for Next Week: Continue to research SEM, involving the area of generator payments and charges. Complete research of PHES in the SEM. Find the exact outage dates for each unit at Turlough Hill. Week 4: Oct 29 th Completed tasks: Meeting between students and supervisor to discuss progress, outline areas of required further study. In this meeting it was further emphasised for the students to understand the SEM and payments within the scheme. The students continued to research the SEM, more specifically focusing on Generator unit payments and charges: Generator units earn revenue through a range of mechanisms such as energy payments for generated energy and capacity payments for unit availability. Aidan contacted SEMO regarding DQ data for Historic TH outage analysis and this data will be acquired as soon as possible. The students acquired the exact outage dates for each unit at Turlough Hill for the larger overhaul that was commenced in

80 Results: The students learned about the payments/charges each generator receives/pays under the rules of the SEM. All four units of Turlough Hill went on outage on July 5 th The units then returned to operation on the following dates: Unit Return Date TH1 7 th June 2012 TH2 14 th March 2012 TH3 25 th August 2012 TH4 14th July 2012 Objectives for next week: Complete the review of the SEM including a review of PHES within the SEM. Review of existing work on PHES in power systems. Week 5: Nov 5 th Completed tasks: A review of the operation of PHES was completed by both students; this included how each unit is treated within the SEM, operation, modelling and payments made/received. PHES units do not receive constraint payments like conventional generation units. The students reviewed existing work on PHES in power systems this week. This review covered areas such as the stability and security benefits of PHES, PHES as a wind integrator in power systems, Irish renewable energy policy and economical and technical barriers to the development of PHES schemes. Results: The students now understand how PHES operates within the SEM and importantly how PHES differs from other generators. The students gained an insight into other benefits of PHES and the barriers for developing further PHES stations. Objectives for next week: Research Power System modelling theory. Week 6: Nov 12 th Completed tasks: This week the students reviewed Power System modelling theory. This involved o Research of literature covering the theory and methods deployed in the modelling of power systems, such as the use of linear and mixed-integer programming. 70

81 Results: The students gained an insight into power system modelling as well as some of the background into the programming of these models. Objectives for next week: Complete PLEXOS registration. Both students should become familiar with how PLEXOS software operates and how the PLEXOS_ Ireland model for 2020 was created. Week 7: Nov 19 th Completed tasks: Both students completed the PLEXOS registration supplied by energy exemplar in order to acquire academic licences to complete the modelling aspect of the project. Each student researched the energy exemplar website to gain an understanding in what PLEXOS is and how the PLEXOS software operates. Both students then reviewed Paul Dean's Thesis to find out how the PLEXOS_Ireland model was created and how the model operates. Results: The students now have PLEXOS licences for the modelling part of the project. The students have an understanding of PLEXOS, how it works and the PLEXOS_ Ireland model which is to be used in TP2. Objectives for next week: It is planned that the students will review the history of the grid from the EirGrid monthly outage summaries for the DQ data analysis. Week 8: Nov 26 th Completed tasks: It was decided by the students that for the historical DQ data analysis an overall view of all generator operations and outages would be of use. The students reviewed the EirGrid monthly outage summaries, Aidan reviewing and Luke reviewing Results: Both students worked in sync to complete this review which would be very useful when the DQ historical data analysis is being undertaken. 71

82 Objectives for next week: The plan for the final week of TP1 is to complete and submit the preliminary report. If time allows the students plan to make a start on the DQ historical data analysis. Week 9: Dec 3 rd Completed tasks: The preliminary report was prepared by both students this week. The SEMO DQ data was received and is ready to be analysed to compare the system operation and generation mix for when Turlough Hill was off-line and on-line. This analysis was not complete at the end of TP1. As part of the preliminary report a Gantt chart was produced; a high level plan of work to be completed in TP2. Results: The preliminary report was completed by the students on time as planned. The DQ data for historical analysis was received and is planned to be completed in the first week of TP2. Objectives for next term: A plan was made for TP2 and is in the preliminary report as well as a Gantt chart associated with the work. Week 10: Dec 10 th Preliminary report was submitted on the 12th of December. Week 11: Jan 7 th Completed tasks: The historical data analysis was completed as discussed. Week 12: Jan 14 th 2011 Curtailment report Irl 2.4% (106 GWh) wind generation (VPTG) dispatched down. NI 1.3% 13.4 GWh Gas in NI decreases w/ 1 PHES, but increases again w/ 2PHES Cycling of gas units in NI increases o TH causes decrease in use of NI peakers, but is causing greater cycling of Ballylumford 72

83 With TH online, B31 (which was normally used as a mid-merit and peaker with TH offline) is being deployed more as a peaking generator, as shown by increased cycling above. Its generation also increased by 50 GWh. B32 is cycled less, but also deployed less (decrease in 200GWh). Surplus to requirement? Week 13: Jan 21 st Done: 73

84 Three separate model scenarios were run; one with the current Irish PHES portfolio (TH), 1 PHES with an additional PHES plant of equal properties to TH and a 75% efficiency, and 0 PHES with no PHES in the power system. Analysis & results highlights: o Total Generation (GWh) marginally increases with each added PHES = ~51 TWh, compared to 35TWh consumption in 2011 (EirGrid annual report). o Total wind generation does not significantly change with added PHES = ~27% of total generation. o Total Generation cost is most expensive for 1 PHES, and least expensive in 0 PHES case ( bn vs bn) o Fuel Cost savings of 23M and 33M relative to 0 PHES for 1 and 2 PHES respectively. o Interconnector Flow decreased, Interconnector Flow Back increased. o CO2 emissions decreased by ~140,000t and 216,000t in 1 and 2 PHES o Hours curtailed reduced by more than half with each PHES. o Generator cycling generally decreases with added PHES To Do: Refresh on market operation (see SEMO training and Prelim Report), with a focus on ancillary services and reserve payments (See NREL wind integration document). Investigate more modern PHES technologies which could be installed in a new PHES, improving on the current TH duplicate. Possible improvements: more than one penstock, higher efficiency pumping, larger MW capacity and variable speed pump-turbines. Investigate results of modelling: o Are Total generation levels of 51 TWh correct? Are generation rises to be expected? o Why does the wind not change? Due to how wind is represented in PLEXOS? o Why does the generation cost not follow total generation? Why does total generation cost rise? o What are the relationships between Interconnector Flow, Interconnector Flow and the GB Generation properties? o o Why are the PHES units rarely operating above 40MW? 74

85 o Understand PLEXOS model properties: o Different revenues price received? Pool revenue? Reserves Revenue? o Why Reserve Costs are zero for all units? o Curtailment Factor? Curtailment Hours? how do they represent wind curtailment? o Raise and Lower Reserve do they represent peak load supply and shedding? o Capacity factor for wind does plexos model wind available and wind and how much was extracted? Organise meeting with E. McK for next week to discuss potential analysis and other ideas. Can wind curtailment reports be obtained Complete SEMO DQ data spreadsheet and carry out analysis: o TH online vs offline Generator cycling (look at other GU s, see if the number of times they start up and shut down increases), CO2 emissions during online and offline periods, Wind energy levels? Interconnector flow levels during TH online and offline periods (does TH affect IC usage?) Week 14: Jan 28 th Historical data needs to be fully sorted Look at what happens when Moyle was offline during the TH offline period. Ken Oakely: Reserve requirements decrease with TH offline ; Reserve matches largest in feed Items to look in to Capacity factor of PHES Annual Generation SMP Important Interconnection Documents: EirGrid 2022 Adequacy Statement. EirGrid Interconnector feasibility report Transmission Constraints 75

86 SWS PHES 600MW for 800M /Resources/CoireGlasPumpedStorageBriefing.pdf 3 x 100MW Update Model 1500/MW (in Silvermines) how does it compare? Current Swiss & German PHES projects Capacity Payments may be abolished/reduced Moyle reduced from 500MW to 250MW Addition Great Island Activate Uplift in Model Activate other reserve categories Rent addition (Inframarginal?) Kilroot emissions sanctions? Sensitivity Analysis Max level wind penetration POR too high; reduce from 15 to 10 MW Lower Resolution intervals Seasonal Constraints? Wind, emissions, reserve, cost, fuel, fuel costs ROCOF/ROCOV? Week 15: Feb 4 th SEMO DATA ANALYSIS Use historical data in PLEXOS? Analysis Periods: Online: 4 th July th July 2010, Offline: 5 th July th July th April 4 th July 2011 missing Comparisons: Wind Curtailment/penetration CO2 emissions Data Prior Nov 2011 missing t CO2/MWh? - Reserve (?) PLEXOS Generation Costs Market Costs Fuel Costs 76

87 To Add 1) Add Great Island as a copy of Whitegate, with an increased Heat Rate of 0.01 GJ/MWh (i.e. required GJ thermal input to produce 1 MWh) 2) Inframarginal rent = SMP - SRMC ISSUES/QUERIES Heat rate is calculated as a function of Base heat rate (GJ/hr) and Heat Rate Incr (GJ/MWh). Can t just increase the heat rate. Analysis Added POR (may have to reduce) Result: (TH OFFLINE, CONSTRAINED) Adding POR reduced Total SEM Generation by 2,158 GWh and Total SEM Generation Cost by 66,306,160. Explanation: Enabling POR allows shorter reserve requirements to be met by faster-acting generators, which can start and run for shorter periods of time, as opposed to when only TOR was enabled, where the same short reserve requirement would be met by a generator unit which had a longer min running time. However Total Generation of the entire Generators group remained exactly the same; it was found that with the reduction in SEM generation with POR added, GB GENERATION increased by 2,158 GWh to make up the decrease exactly. However the GB Total Generation Cost change ( 142, increase with POR added) did not equate to the SEM or Generators group Total Generation Cost reduction. Week 16: Feb 11 th To Do Re run 0 and 1 phes (?) market scenarios 77

88 Add POR & TOR max pump response of 71 MW for each TH unit - Ireland should be a net exporter (check Imports and Exports ) - if not, use TOR only K. Oakely about POR, any other questions Find Inframarginal Rent equivalent (Australian market equivalent) Spark Spread? SEMO DQ Data: Main focus is on the total generation and how it changes with PHES on/offline. Also look at CO2 emissions, I/C flows, wind curtailment/generation if possible Fix Horizons changed by P Deane Redo analysis on Total System, SEM and GB Generation & Costs Model a zero reserve scenario (necessary?) - Scenario with no reserve should be the cheapest. Primary overall most expensive scenario. Ensure Mutually Exclusive is off Meeting Notes 1000MW I/C: 900 MW capacity, 100 MW reserve. Raise Reserve = POR Regulation Reserve = TOR Price = Shadow Price + Uplift (Price = SMP) Actual problem with adding POR - the model shuts down large plant (Moneypoint) and imports power. Technically correct for model but not when compared with real operation. Mutually exclusive was not allowing reserve categories to overlap, must turn off. Reserve Modelling Provision = reserve being provided/available to use Available Response = Max possible reserve that could be provided What causes the difference between Provision and Available Response? Risk = the amount of reserve required by the system Pump Dispatchable Load Provision was added = pumping reserve provided (This covers the reserve for pumping. It is not immediately shown with other reserve on) PLEXOS graphs, must check pump dispatchable load provision. Add POR & TOR max pump response of 71 MW Other Modelling Keep Moyle at current capacity, possible scenario looking at a reduction in capacity. IC max flow=900mw, 50MW static reserve for each interconnector Scenario putting the flow down to 700MW- which would be halving Moyle interconnector output. GISL not included in main model, possible scenario with it included Max wind penetration different % scenarios Week 17: Feb 18 th Work Done 78

89 Cost to consumer in Plexos? Reserve payments? TH gets paid separately for POR, TOR, etc. are we loosing this through omission of other reserve categories? Some plants can serve TOR but not POR 2 Network Constraints, High Inertia NI and Kilroot Coal Units, are included in the Market Models should they be there? Only running for 1 year currently, worth running for greater time periods? What causes the difference between Provision and Available Response reserves? Do they include pump response, or is that just pump dispatchable load? - YES Shorter resolutions worth doing? Ramp constraints and value thereof (flexibility) become more relevant. If not worth doing, worth mentioning P Deane s work on 5 minute models Analysis a) Market Operation b) System Operation (Eirgrid Network Constraints Included) c) Scenarios: a. GISL b. Moyle Capacity reduced c. Wind Penetration Levels (Currently 70%) d. Remove Reserve Completely (suggested by PD) e. Lower Resolution intervals? f. Sensitivity test of removal of certain constraints (SIGA guys mentioned Cork (Whitegate Ahada) constraint g. Seasonal variation of constraints? *Total Generation (SEM & Total System) - Compare historic to Plexos data o SEM & Total generation increases, GB GEN decreases significantly, Waste RoI increases significantly *Total Generation Costs (SEM & Total System) - Compare historic to Plexos data o SEM Costs reduced, GB Gen Cost decreases (as per generation reduction) Generator costs - SRMC Generator s profits/revenues PHES especially; does new PHES earn enough to cover capital? CO2 emissions and costs SMP, Uplift and Shadow price Inframarginal Rent (Spark Spread) Generator Cycling and cost start-up & shutdown costs, start fuel costs, start costs Reserve (TOR = Regulation, scenario with no reserve, Ignore POR completely?, Pump Dispatchable Load Provision, Reserve Requirements change with PHES? o Reserve provision Decreases with added phes Fuel cost and price (fuel price*generation = cost?) o Both go down with phes Cost to consumers (need to find) Capacity factor for units -PHES 79

90 o Wind increases small amount Curtailment factor of wind What happens with PHES and system in general when IC goes offline? - Compare historic to Plexos data How does the higher efficiency PHES affect the older one To Do K. Oakely with analysis SEMO DQ Data: Main focus is on the total generation and how it changes with PHES on/offline. Also look at CO2 emissions looks unlikely data can be acquired, I/C flows, wind curtailment/generation if possible Notes SEM Cost = (Total Generation Cost GB Generation Cost) Price = Shadow Price + Uplift (Price = SMP) Provision = reserve being provided/available to use Available Response = Max possible reserve that could be provided What causes the difference between Provision and Available Response? Just the fact the max amount possible isn t necessary? Risk = the amount of reserve required by the system Risk = Provision Pump Dispatchable Load Provision was added = pumping reserve provided (This covers the reserve for pumping). Reserve data was taken from 2010 ESB data (from initial CER model) Reserve -> See what generators are contributing to each category - > Max Response = the max reserve a unit can contribute to that category of reserve Static reserve on IC s Max pump response added Assumption: Reserve requirements in the model are the same as 2012 Reserve requirement based on largest single in-feed (unless wind forecast error is greater than largest in-feed Reliability of reserve providers has been historically poor cannot be shown in model Cost leakage between UK and Ireland Week 18: Feb 25 th Week 19: Mar 4 th 23/3/2013 Nomenclature? Use Historic data for validation, after/in results sections? Change Cycling Section to Thermal Plant Operation? i.e. o Section: Thermal Plant Operation Dispatch 80

91 Generator Cycling high w/o PHES due to high wind generation; added PHES mitigates this Look at periods of high wind? Ramping: One of the most important implications to consider is the ramping requirement from the power plants caused by the addition of fluctuating renewable energy (i.e. wind). high w/o PHES due to high wind generation; added PHES mitigates this Look at periods of high wind? New PHES income/revenue in 2020 = 18,840,620. At 1.5mil/MW = 439 mil capital cost, payback = years Look at a Baseload, mid and peaker (validate against historic dispatch, may also show that wind increases cycling) Opening/Pre-Results Intro: Discuss different parameters (i.e. each section of results) examined and why they are (e.g. Cycling what it is why it is bad, Increased Renewables, and reduced curtailment of wind). Give quantification of negativities. Conclusion: Parameters examined, how much they were improved by, why PHES helps (e.g. PHES can provide more ramping/faster ramping so mid-merit units don t have to), BUT PHES is currently unattractive due to High initial costs (PD says 1.5mil /MW REF) in an energy only market Conclusion discussion points: o PHES works better through integration with other services (eg in Austria and spain where there are water shortages due to freezing/drought refer to PD) o Often refurbishment of older plant reduces costs o Total Gen increases due to additional generation and pumping by PHES, but efficiency increases o 1.5m /MW gives too big a payback time 8-10 years payback for private investment o No CPM or Ancil Services o Scenarios: Carbon, IC MOYLE OFFLINE: shows how phes performs in an isolated system, and how additional phes units help Markets: How reserve and constraints affect the power system, and how PHES performs in the system w/o these operational characteristics MODELING o Luke is doing high-level analysis, Average SMP reduced (w/ weekly graph demonstrating lower SMP), Total Reserve provision increase. 1. Cycling: Show reduced cycling for certain important (high dispatch) units? Make cycling graphs (generation?) to demonstrate reduction, and state % reduction. 2. Cycling: Minutes ramp up and down of coal units 3. Cycling: Don t include contour units or other ones which are messing things up 4. Total Gen & Cost: Inefficient/older/more expensive plant dispatch reduced? Leads to reduced generation cost (put in the TG & C section) 81

92 5. Total Gen & Cost: Look at Baseload, midmerit and peaker operation 6. Total Gen & Cost: SRMC? 7. PHS: SMP vs PHES operation (pump/gen) to show operation 8. Emissions: Dirtier plant dispatch reduction Show distillate plants reduce/offline completely 9. PHES: Pumping cost (at night) vs generating earnings (during peak load) for PHES 10. CYCLING O&M COSTS DECREASE W/ PHES?- show 11. SMP - High SRMC units (distillates?) used less often, reducing average SMP - Show Ask PD (LOOK INTO THEM FIRST): I think your costs should also be reported as Full System costs (AI+GB) FOR REPORT as this will ensure you cover the cost of any imports. Don t include GB generation in Total Generation References for renewable capacities (and other units) used in model from EirGrid All-Island Generation Capacity Statement Moyle offline scenario: -450MW capacity In analysis, refer back to 1 PHES ie in 0 PHES, having no pumped storage results in increased cycling, while adding additional PHES in 2 PHES results in a decrease Interconnection The resulting net wheeling charges are /MWh from SEM to GB and -0.4 /MWh from GB to SEM respectively, flat across the year. The significance of this is that imports into SEM will be favoured and exports from SEM to GB will be disfavoured. Another consequence of this is that there is an effective deadband of 12.8 /MWh. Within this band, there will be no flow across the interconnector. The size of this deadband is similar to the previous validated model. Analysis Focus: Operations, Fixed vs. Free Due to the unpredictability of future interconnection operation, the results of the model simulation are presented in two sections: 2020 Fixed interconnection: Interconnector flow is decided based on historical data input in the model. This simulation method gives an accurate simulation based on actual data; however it only serves as a control set of results. This method actually gives rise to decreased system flexibility as it forces Plexos to adhere to a set of interconnector flows which do not fit naturally into the 2020 model simulation Free Interconnection: In this method interconnector flow is simulated based on price differentials between the Irish SEM and the Great Britain power system, as would be expected. This method lends to a more whole prediction of the 2020 power system This method of analysis is also employed by the Commission for Energy Regulation in their annual Plexos Validation Reports Renewable Target 82

93 In Ireland, the 2008 Carbon Budget has set a target for 40% of electricity consumption from renewable sources by 2020 [Directive 2009/28/EC of the European Parliament and of the Council - [The DS3 Programme Delivering a Secure, Sustainable Electricity System] What are the renewable capacities based on? Total System Consumption and Cost Generation + Imports Exports Imports/Exports Imports increase providing the pumping power for PHES?? 83

94 Things to look at Pumping cost (at night) vs generating earnings (during peak load) for PHES Table 2 shows the difference between PLEXOS and historic generation levels for thermal generation units over the complete horizon. A positive value indicates that PLEXOS utilised a generation unit more than historic levels. The results show that PLEXOS schedules 88% of plant (45 out of 51) to within 5% or less of historic capacity factor levels. We believe this result is reasonable. 84

95 Week 20: Mar 11 th A poster was completed and presented on the 14 th of Mach. 85