Analysing the Value of Pumped
Storage in the 2020 Irish
Power System
Aidan Cummins, Luke Dillon
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
109547274
Luke Dillon
109517952
Date of Submission:
27th March 2013
i
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
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:
Date:
____________________________
____________________________
Aidan Cummins
Luke Dillon
27/03/2013
iii
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 2012.
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
Table of Contents
1.
Executive Summary ......................................................................................................................... ii
2.
Declaration ..................................................................................................................................... iii
3.
Acknowledgements........................................................................................................................ iv
Table of Figures .................................................................................................................................... viii
Table of Tables ....................................................................................................................................... ix
4.
Introduction .................................................................................................................................... 1
5.
The Single Electricity Market: A Review.......................................................................................... 3
5.1.
Introduction ............................................................................................................................ 3
5.2.
Market Operation ................................................................................................................... 4
5.3.
Generator Unit Payments & Charges ...................................................................................... 6
5.3.1.
Trading Payments ........................................................................................................... 6
5.3.2.
Capacity Payments .......................................................................................................... 8
5.4.
PHES in the SEM .................................................................................................................... 10
6.
PLEXOS Software Review .............................................................................................................. 11
7.
Historical Data ............................................................................................................................... 12
8.
7.1.
Introduction .......................................................................................................................... 12
7.2.
Turlough Hill .......................................................................................................................... 12
7.3.
Data Acquisition .................................................................................................................... 12
7.4.
Normal operation.................................................................................................................. 13
7.5.
Interconnection..................................................................................................................... 14
7.6.
System Overview................................................................................................................... 15
7.7.
System Operation ................................................................................................................. 16
2020 Ireland Model ....................................................................................................................... 18
8.1.
Simulation Resolution & Duration ........................................................................................ 18
8.2.
System Load .......................................................................................................................... 18
8.3.
Generator Unit Properties & Dispatch .................................................................................. 18
8.4.
Fuel Costs, CO2 Production and Tax Rates ............................................................................ 18
8.5.
Wind Generator Units ........................................................................................................... 18
8.6.
Outages ................................................................................................................................. 19
8.7.
PHES in the Model................................................................................................................. 19
8.8.
System Generation Capacity ................................................................................................. 19
8.9.
Interconnection & Great Britain Generation ........................................................................ 19
8.10.
Reserve Provision .............................................................................................................. 20
v
8.11.
9.
Network Constraints ......................................................................................................... 20
8.11.1.
System Non-Synchronous Penetration ......................................................................... 20
8.11.2.
Dublin Generation ......................................................................................................... 20
8.11.3.
Inertia NI ....................................................................................................................... 20
8.11.4.
Inertia ROI ..................................................................................................................... 20
8.11.5.
Kilroot Coal .................................................................................................................... 21
8.11.6.
Moneypoint................................................................................................................... 21
8.11.7.
South West Generation................................................................................................. 21
PLEXOS Modelling Methodology .................................................................................................. 22
10.
PLEXOS Modelling Results......................................................................................................... 23
10.1.
Operations Model (IC Free)............................................................................................... 23
10.1.1.
Total System Generation and Costs .............................................................................. 23
10.1.2.
System Marginal Price................................................................................................... 26
10.1.3.
Conventional Plant Operation .................................................................................. 26
10.1.4.
Interconnector Flow.................................................................................................. 30
10.1.5.
Emissions ................................................................................................................... 31
10.1.6.
Wind Curtailment .......................................................................................................... 31
10.1.7.
PHES in the System ....................................................................................................... 33
10.2.
Operations Model (IC Fixed) ................................................ Error! Bookmark not defined.
10.2.1.
Total System Generation and Costs .............................................................................. 35
10.2.2.
System Marginal Price................................................................................................... 38
10.2.3.
Conventional Plant Generation..................................................................................... 39
10.2.4.
Interconnector Flow...................................................................................................... 40
10.2.5.
Emissions ....................................................................................................................... 40
10.2.6.
Wind Curtailment .......................................................................................................... 41
10.2.7.
Pumped Storage in the System ..................................................................................... 42
10.3.
Market Model ................................................................................................................... 45
10.3.1.
Total System Generation and Costs .............................................................................. 45
10.3.2.
Interconnector Flow...................................................................................................... 46
10.3.3.
Emissions ....................................................................................................................... 47
10.3.4.
Wind Curtailment .......................................................................................................... 47
10.3.5.
Pumped Storage in the System ..................................................................................... 48
10.4.
10.4.1.
Carbon Tax Sensitivity ....................................................................................................... 50
Total Generation Cost ................................................................................................... 50
vi
10.4.2.
System Marginal Price................................................................................................... 52
10.4.3.
Emissions ....................................................................................................................... 52
10.4.4.
PHES in the System ....................................................................................................... 53
10.5.
11.
Reduced Interconnection Scenario ................................................................................... 55
10.5.1.
Total System Generation and Costs .............................................................................. 55
10.5.2.
Conventional Plant Operation ...................................................................................... 56
10.5.3.
Wind Curtailment .......................................................................................................... 58
10.5.4.
PHES in the System ....................................................................................................... 59
Conclusion ................................................................................................................................. 60
Conclusion and Future Work ................................................................................................................ 60
12.
Works Cited ............................................................................................................................... 62
13.
Appendix 1: Logbook................................................................................................................. 68
Week 1: Oct 8th ................................................................................................................................. 68
Week 2: Oct 15th ............................................................................................................................... 68
Week 3: Oct 22nd ............................................................................................................................... 69
Week 4: Oct 29th ............................................................................................................................... 69
Week 5: Nov 5th................................................................................................................................. 70
Week 6: Nov 12th............................................................................................................................... 70
Week 7: Nov 19th............................................................................................................................... 71
Week 8: Nov 26th............................................................................................................................... 71
Week 9: Dec 3rd ................................................................................................................................. 72
Week 10: Dec 10th ............................................................................................................................. 72
Week 11: Jan 7th ................................................................................................................................ 72
Week 12: Jan 14th .............................................................................................................................. 72
Week 13: Jan 21st .............................................................................................................................. 73
Week 14: Jan 28th .............................................................................................................................. 75
Week 15: Feb 4th ............................................................................................................................... 76
Week 16: Feb 11th ............................................................................................................................. 77
Week 17: Feb 18th ............................................................................................................................. 78
Week 18: Feb 25th ............................................................................................................................. 80
Week 19: Mar 4th .............................................................................................................................. 80
Week 20: Mar 11th ............................................................................................................................ 85
Week 21: Mar 18th ............................................................................................................................ 86
Week 22: Mar 25th ............................................................................................................................ 86
vii
Table of Figures
Figure 5.1: Merit Order allocation [20] ................................................................................................... 5
Figure 5.2: SMP in relation to System Load (data from www.sem-o.com) ............................................ 5
Figure 5.3: Annual SEM Value (data from www.sem-o.com) ................................................................. 6
Figure 5.4: Distribution of monthly pots [27] ......................................................................................... 8
Figure 7.1-Turlough Hill TH2 Generation over a typical week .............................................................. 13
Figure 7.2: Turlough Hill Generation per unit ....................................................................................... 14
Figure 7.3: Interconnector Imports....................................................................................................... 14
Figure 7.4: System Capacity 2009 ......................................................................................................... 15
Figure 7.5: System Capacity 2010 ......................................................................................................... 16
Figure 7.6: System Generation TH Online ............................................................................................. 17
Figure 7.7: System Generation TH Offline ............................................................................................ 17
Figure 8.1: All-Island Fuel Mix 2020 ...................................................................................................... 19
Figure 10.1: Total System Generation Costs Free IC ............................................................................. 23
Figure 10.2: Total System Generation Breakdown (GWh) Free IC ....................................................... 24
Figure 10.3: Generation Cost By Category Free IC ................................................................................ 25
Figure 10.4: Generation By Category Free IC ........................................................................................ 25
Figure 10.5: SMP Annual Profile (€/MWh) Free IC ............................................................................... 26
Figure 10.7: Gas peaker unit dispatch decreases with PHES capacity increase ................................... 27
Figure 10.8: Generator Cycling By Category ......................................................................................... 29
Figure 10.9: Moneypoint Time Spent Ramping Free IC ........................................................................ 30
Figure 10.10: Interconnector Flow Free IC ........................................................................................... 30
Figure 10.11: Emissions By Sector Free IC ............................................................................................ 31
Figure 10.12: Wind curtailment Factor Free IC ..................................................................................... 32
Figure 10.13: PHES Generation (GWh) Free IC ..................................................................................... 33
Figure 10.14: Payback Period Free IC.................................................................................................... 34
Figure 10.15: Total Generation Costs Fixed IC ...................................................................................... 35
Figure 10.16:Total System Generation Breakdown (GWh) Fixed IC ..................................................... 36
Figure 10.17: Generation Cost Breakdown By Category Fixed IC ......................................................... 37
Figure 10.18: Generation By Category Fixed IC .................................................................................... 37
Figure 10.19: SMP Annual Profile (€/MWh) Fixed IC ............................................................................ 38
Figure 10.20: SMP Annual Profile (€/MWh) Fixed IC vs. Free IC .......................................................... 38
Figure 10.21: Generator Cycling By Category Fixed IC.......................................................................... 39
Figure 10.22: Moneypoint Ramping Time Fixed IC ............................................................................... 40
Figure 10.23: Interconnector Flow Fixed IC .......................................................................................... 40
Figure 10.24: Emissions By Sector Fixed IC ........................................................................................... 41
Figure 10.25: Wind Curtailment Factor Fixed IC ................................................................................... 41
Figure 10.26: Wind Farm Losses Fixed IC vs. Free IC ............................................................................ 42
Figure 10.27: PHES Generation (GWh) Fixed IC .................................................................................... 43
Figure 10.28: Payback Period Fixed IC .................................................................................................. 44
Figure 10.29: Total System Generation Costs Market Model............................................................... 45
Figure 10.30: Total System Generation Breakdown (GWh) Market Model ......................................... 46
viii
Figure 10.31: Interconnector Flow Market Model ............................................................................... 47
Figure 10.32: Emissions By Category Market Model ............................................................................ 47
Figure 10.33: Wind Curtailment Factor Market Model ........................................................................ 48
Figure 10.34: Wind Farm Losses Base vs. Market Model ..................................................................... 48
Figure 10.35: PHES Generation Market Model ..................................................................................... 49
Figure 10.36: PHES Payback Period Base vs. Market model ................................................................. 49
Figure 10.38: System Generation For Carbon Tax Sensitivity ............................................................... 51
Figure 10.39: Relationship between Gas and Coal dispatch and carbon tax........................................ 52
Figure 10.40: Relationship between SMP and carbon tax .................................................................... 52
Figure 10.41: Relationship between CO2 emissions and carbon tax.................................................... 53
Figure 10.42: New PHES cumulative cash flow in C €45 Scenario ........................................................ 54
Figure 10.43: Total Generation Cost - Moyle online vs. offline ............................................................ 55
Figure 10.44: Total System Generation - Moyle online vs. offline........................................................ 56
Figure 10.45: 1PHES Generation by Fuel Type - Moyle online vs. offline ............................................. 56
Figure 10.46: Negative impact of reduced interconnection capacity on Gas RoI operation................ 57
Figure 10.47: Minutes spent ramping up and down by Moneypoint coal units................................... 58
Figure 10.48: Percentage of wind energy curtailed in the Republic of Ireland - Moyle online vs. offline
.............................................................................................................................................................. 58
Figure 10.49: Payback Period Reduced IC............................................................................................. 59
Table of Tables
Table 7.1: Turlough Hill Return Dates ................................................................................................... 12
Table 8.1: Fuel Price and Emissions…………………………………………………………………………………….……………18
Table 10.1: Comparison of peaker unit SRMC ...................................................................................... 28
Table 10.2: Peaker units which cease to be used with the addition of PHES capacity ......................... 28
Table 10.4: Losses prevented by the addition of PHES ......................................................................... 32
Table 10.6: Summary of PHES Earnings Free IC .................................................................................... 33
Table 10.7: Payback Analysis New PHES Plant Free IC.......................................................................... 34
Table 10.8: Payback Analysis New PHES Plant Fixed IC ........................................................................ 43
Table 10.9: Payback Analysis Market Model ........................................................................................ 49
Table 10.10: Payback Analysis Market Model ...................................................................................... 49
Table 10.12: Calculation of New PHES payback in C €45 scenario ....................................................... 53
Table 10.13: PHES Generation - Moyle online vs. offline ..................................................................... 55
Table 10.15: Wind generator revenue lost due to curtailment ............................................................ 58
Table 10.16: PHES Plant Capacity Factors Reduced IC .......................................................................... 59
ix
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 2020. 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
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 0.5 – 15 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
5. The Single Electricity Market: A Review
5.1.
Introduction
The Single Electricity Market, which went live on 1st 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
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
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 www.sem-o.com)
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
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.
5.3.1. 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
€ million
€2,000
Energy
Payments
€1,500
Capacity
Payments
€1,000
Constraint
Payments
€500
€0
2012
2011
2010
2009
Figure 5.3: Annual SEM Value (data from www.sem-o.com)
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
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
5.3.2. 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 InfraMarginal 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
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
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
6. PLEXOS Software Review
PLEXOS [29] produced by energy exemplar1 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 Ireland2 to validate and model Ireland’s Single Electricity Market3 (SEM) [30].
1
1
2
http://www.energyexemplar.com/
http://www.cer.ie/
11
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.
7.2.
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
1974. 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 1st
January 2009 until the 5th of July 2011. All four units of Turlough Hill went on outage on July 5th 2010,
and the units then returned to operation on the dates listed in table 7.1 below.
Unit
TH1
TH2
TH3
TH4
Return Date
7th June 2012
14th March 2012
25th August 2012
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 5th
July 2009 to the 4th July 2010 and the TH offline period runs from the 5th July 2010 to the 4th July
2011.
12
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.
TH2
60
40
Generation MW
20
0
-20
-40
-60
-80
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
Turlough Hill General operation over a week
60
40
Generation MW
20
TH1
0
TH2
-20
TH3
TH4
-40
-60
-80
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.
IMPORTS
2,700,000.00
MW Dispatched
2,600,000.00
2,500,000.00
2,400,000.00
2,300,000.00
2,200,000.00
2,100,000.00
2,000,000.00
ONLINE
OFFLINE
Figure 7.3: Interconnector Imports
14
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 2009-2010. 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 2011.
OTHER
2%
PHES
3%
WIND
16%
INTERCONNECTION
5%
GAS
43%
HYDRO
2%
COAL
12%
HFO
10%
DISTILLATE
4%
PEAT
3%
Figure 7.4: System Capacity 2009
15
OTHER
2%
WIND
16%
PHES
3%
HYDRO
2%
INTERCONNECTION
4%
GAS
47%
COAL
11%
HFO
7%
DISTILLATE
5%
PEAT
3%
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 2020. HFO plant will be
completely retired and replaced. Wind capacity will continue to increase to achieve 37% of
generation by 2020. 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.
7.7.
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
COAL NI
4%
DISTILLITE NI
0%
WIND NI
1%
LFG ROI
0%
Online
WIND ROI
7%
GAS NI
17%
COAL ROI
PHES (Generating)
10%
1%
DISTILLITE ROI
1%
HYDRO ROI
2%
PEAT ROI
7%
GAS ROI
50%
Figure 7.6: System Generation TH Online
COAL NI
5%
Offline
DISTILLITE NI
0%
WIND NI
1%
GAS NI
14%
LFG ROI
0%
DISTILLITE ROI
1%
WIND
ROI
9%
COAL ROI
11%
HYDRO ROI
2%
PEAT ROI
7%
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
8. 2020 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.
8.1.
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 1st 2020 and ending
December 31st 2020.
8.2.
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.
8.3.
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.
8.4.
Fuel Costs, CO2 Production and Tax Rates
Table [REF] below summarises the cost of fuels used in the model, and their associated CO2
emissions and taxes. A Carbon Tax of €30/tonne of CO2 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
Gas
Coal
Peat
Distillate Oil
Price (€/GJ)
7
2.12
0
12.06
Carbon Tax (€/GJ)
1.68
2.81
3.15
2.21
Emission Rate (kg/GJ)
56.1
94.6
106
74.1
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
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].
8.7.
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].
8.8.
System Generation Capacity
System capacity was modelled using information from the EirGrid 2012-2021 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.
2020 All-Island Fuel Mix
WASTE ROI
2%
Interconnection
6%
GAS ROI
27%
COAL ROI
6%
ROI Wind
28%
ROI Wave
1%
NI Wind
9%
DISTILLATE NI COAL NI
2%
3%
GAS NI
7%
PEAT ROI
2%
HYDRO ROI
PUMPED
2%
STORAGE ROI
DISTILLATE ROI
2%
3%
Figure 8.1: All-Island Fuel Mix 2020
8.9.
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 2012. These two links between the all19
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.
8.10. 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?]
8.11. 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:
8.11.1. 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.
8.11.2. 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].
8.11.3. 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.
8.11.4. 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
8.11.5. 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.
8.11.6. 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.
8.11.7. 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
2012”
[http://www.eirgrid.com/media/Transmission%20Constraint%20Groups%20Version%201%204%201
9July2012.pdf
21
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 7.2.
2 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.
2020 – 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
10.
PLEXOS Modelling Results
10.1. Base Model: Free Interconnection
10.1.1. 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.
Start & Shutdown
Billion
€2.14
Generation
€2.12
€2.10
€2.08
€2.06
€2.04
€2.02
€2.00
€1.98
€1.96
€1.94
0 PHES
1 PHES
2 PHES
Figure 10.1: Total System Generation Costs Free IC
23
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)
WASTE ROI
ROI Wind
50000
ROI Wave
45000
NI Wind
40000
35000
COAL NI
30000
GAS NI
25000
DISTILLATE ROI
20000
PHES ROI
15000
HYDRO ROI
10000
PEAT ROI
5000
COAL ROI
GAS ROI
0
0 PHES
1 PHES
2 PHES
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 414.83GWh, consumed solely by Turlough Hill,
whereas in 2 PHES the system pumping load was 786.33GWh. 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
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 10.1.6. PHES dispatch increases as capacity
increases, as would be expected.
Millions
0 PHES
1 PHES
2 PHES
Distillate NI
GB
Generation
€900
€800
€700
€600
€500
€400
€300
€200
€100
€Gas RoI
Coal RoI
Peat RoI
Distillate
RoI
Gas NI
Coal NI
Figure 10.3: Generation Cost By Category Free IC
GWh
16000
0 PHES
1 PHES
2 PHES
14000
12000
10000
8000
6000
4000
2000
0
Figure 10.4: Generation by Category Free IC
25
10.1.2. 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 10.1.3.1
1 PHES
90
2 PHES
85
80
75
70
65
60
55
Figure 10.5: SMP Annual Profile (€/MWh) Free IC
10.1.3. 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.
10.1.3.1. 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
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
60
50
40
30
20
10
0
Edenderry OCGT
Nore Power OCGT
Suir OCGT
Figure 10.6: Distillate peaker unit dispatch decreases with PHES capacity increase
0 PHES
GWh
1 PHES
2 PHES
40
35
30
25
20
15
10
5
0
Aghada OCGT 1
Aghada OCGT 2
Marina OCGT
Figure 10.7: Gas peaker unit dispatch decreases with PHES capacity increase
27
Unit Name
Fuel
SRMC (€/MWh)
Edenderry OCGT
Distillate
128.43
Nore OCGT
Distillate
93.69
Suir OCGT
Distillate
93.69
Aghada OCGT 1
Gas
104.71
Aghada OCGT 2
Gas
103.24
Marina OCGT
Gas
99.35
Tynagh CCGT
Gas
44.15
Coal
47.40
Moneypoint 1
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
Ballylumford OCGT 2
Coolkeeragh OCGT
Kilroot OCGT 1
Kilroot OCGT 2
Kilroot OCGT 4
Distillate
Distillate
Distillate
Distillate
Distillate
0 PHES
Generation (GWh)
0.004
0.004
0.0027
0.0027
0.021
1 PHES Generation
(GWh)
0
0.0265
0.0027
0.0027
0.021
2 PHES Generation
(GWh)
0
0
0
0
0
Table 10.2: Peaker units which cease to be used with the addition of PHES capacity
10.1.3.2. 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
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
900
800
700
600
500
400
300
200
100
0
GAS ROI
DISTILLATE ROI
GAS NI
DISTILLATE NI
COAL ROI
COAL NI
Figure 10.8: Generator Cycling By Category
10.1.3.3. 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 75390
minutes (1256.5 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
Minutes spent ramping
300000
250000
200000
150000
100000
50000
0
0 PHES
1 PHES
2 PHES
Figure 10.9: Moneypoint Time Spent Ramping Free IC
10.1.4. 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 136.8 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.
2900
Net Exports (GWh)
2850
2800
2750
2700
2650
2600
2550
2500
0 PHES
1 PHES
2 PHES
Figure 10.10: Interconnector Flow Free IC
30
10.1.5. 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 CO2 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 CO2 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 CO2 and 15,969.62 tonnes of CO2 respectively
with the Addition of the New PHES plant.
Million tCO2
18
DISTILLATE NI
16
COAL NI
14
12
GAS NI
10
DISTILLATE ROI
8
6
PEAT ROI
4
COAL ROI
2
GAS ROI
0
0 PHES
1 PHES
2 PHES
Figure 10.11: Emissions By Sector Free IC
10.1.6. 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
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
(%)
0 PHES
1 PHES
2 PHES
2
1.8
1.6
1.4
1.2
1
0.8
0.6
0.4
0.2
0
ROI Wind
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.
NI Wind
RoI Wind
0 PHES
1 PHES
2 PHES
0 PHES
1 PHES
2 PHES
Undispatched Energy
(GWh)
63.06
33.62
16.24
112.05
51.57
34.89
Price Received
(€/MWh)
68.99
70.01
68.59
68.54
69.71
68.31
Losses (€)
€
€
€
€
€
€
4,349,967
2,353,415
1,114,207
7,679,232
3,594,589
2,383,087
Table 10.3: Calculation of monetary losses due to wind curtailment
Addition of Turlough Hill
Addition of New PHES
Wind Generator Savings
€ 6,081,195.42
€ 2,450,709.28
Table 10.4: Losses prevented by the addition of PHES
32
10.1.7. 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
700
600
500
400
300
200
100
0
1 PHES
2 PHES
Figure 10.13: PHES Generation (GWh) Free IC
PHES Plant
Turlough Hill
New PHES
1 PHES Capacity Factor
11.4%
N/A
2 PHES Capacity Factor
8.5%
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
€ 33,263,815
Reserve Revenue
Pump Cost
Net Profits
€ 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
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
(€m/MW)
1.5
Capacity
(MW)
292
Capital Expenditure
Annual Income
€ 438,000,000
€ 18,840,621
Payback
(Years)
23.25
Table 10.7: Payback Analysis New PHES Plant Free IC
€100
€0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28
Millions
(€100)
(€200)
(€300)
(€400)
(€500)
Figure 10.14: Payback Period Free IC
34
10.2. Base Model: Fixed Interconnection
10.2.1. 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 10.15 below.
Start & Shutdown Cost
Generation Cost
€1,690.00
€1,640.00
Millions
€1,590.00
€1,540.00
€1,490.00
€1,440.00
0 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
50000
WASTE ROI
45000
ROI Wave
40000
ROI Wind
35000
NI Wind
30000
COAL NI
25000
GAS NI
20000
DISTILLATE ROI
PUMPED STORAGE ROI
15000
HYDRO ROI
10000
PEAT ROI
5000
COAL ROI
0
GAS ROI
0 PHES
1 PHES
2 PHES
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 10.2.6.
36
0 PHES
Millions
€900.00
1 PHES
2 PHES
€800.00
€700.00
€600.00
€500.00
€400.00
€300.00
€200.00
€100.00
€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
0 PHES
Generation GWh
1 PHES
2 PHES
16000
14000
12000
10000
8000
6000
4000
2000
0
Figure 10.18: Generation By Category Fixed IC
37
10.2.2. 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 10.19 below.
SMP Annual Profile (€/MWh)
1 PHES
2 PHES
95
90
85
80
75
70
65
60
55
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 10.20 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
90
85
80
75
70
65
60
55
Figure 10.20: SMP Annual Profile (€/MWh) Fixed IC vs. Free IC
38
10.2.3. Conventional Plant Generation
10.2.3.1. 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.
0 PHES
1 PHES
2 PHES
1200
1000
800
600
400
200
0
GAS ROI
COAL ROI
DISTILLATE ROI
GAS NI
COAL NI
DISTILLATE NI
Figure 10.21: Generator Cycling By Category Fixed IC
10.2.3.2. 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 10.22 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
450000
400000
350000
300000
250000
200000
150000
100000
50000
0
0 PHES
1 PHES
2 PHES
Figure 10.22: Moneypoint Ramping Time Fixed IC
10.2.4. 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.
2500
Net Exports (GWh)
2000
1500
Net Exports
1000
500
0
0 PHES
1 PHES
2 PHES
Figure 10.23: Interconnector Flow Fixed IC
10.2.5. Emissions
There are far less overall savings in emissions in the fixed interconnector model only totalling
1,885.97t CO2 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
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.
18,000,000.00
16,000,000.00
14,000,000.00
DISTILLATE NI
(t CO2/annum)
12,000,000.00
COAL NI
10,000,000.00
GAS NI
DISTILLATE ROI
8,000,000.00
PEAT ROI
6,000,000.00
COAL ROI
4,000,000.00
GAS ROI
2,000,000.00
0 PHES
1 PHES
2 PHES
Figure 10.24: Emissions By Sector Fixed IC
10.2.6. 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 10.25
below.
Curtailment Factor
(%)
3
0 PHES
1 PHES
2 PHES
2.5
2
1.5
1
0.5
0
NI Wind
ROI Wind
Figure 10.25: Wind Curtailment Factor Fixed IC
41
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 10.26 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
18.00
16.00
14.00
Million €
12.00
10.00
8.00
6.00
4.00
2.00
0 PHES
1 PHES
2 PHES
Figure 10.26: Wind Farm Losses Fixed IC vs. Free IC
10.2.7. 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
New PHES
Turlough Hill
450
400
Generation (GWh)
350
300
250
200
150
100
50
0
1 PHES
2 PHES
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
(€m/MW)
1.5
Capacity
(MW)
292
Capital Expenditure
Annual Income
€ 438,000,000
€ 11,901,732.97
Payback
(Years)
36.8
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
Millions
€400
€300
€200
€100
€0
0
2
4
6
8
10 12 14 16 18 20 22 24 26 28 30 32 34 36 38
(€100)
(€200)
(€300)
(€400)
(€500)
Figure 10.28: Payback Period Fixed IC
44
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.
10.3.1. 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
€2.12
€2.10
€2.08
€2.06
€2.04
€2.02
€2.00
€1.98
€1.96
€1.94
0 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 8.8.3.-8.8.7. 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
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.
50000
45000
WASTE ROI
40000
Wind Wave
35000
COAL NI
30000
GAS NI
25000
DISTILLATE ROI
PUMPED STORAGE ROI
20000
HYDRO ROI
15000
PEAT ROI
10000
COAL ROI
GAS ROI
5000
0
0 PHES
1 PHES
2 PHES
Figure 10.30: Total System Generation Breakdown (GWh) Market Model
10.3.2. 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
3000
Net Exports (GWh)
2500
2000
1500
1000
500
0
0 PHES
1 PHES
2 PHES
Figure 10.31: Interconnector Flow Market Model
10.3.3. Emissions
For the market model emissions are lower because the generation for many sectors is lower as
discussed earlier in Section 10.3.1. As this model is not precise in what generators are dispatched it
therefore is not as accurate at predicting emissions.
Million tCO2
18
16
14
DISTILLATE NI
12
COAL NI
GAS NI
10
DISTILLATE ROI
8
PEAT ROI
6
COAL ROI
4
GAS ROI
2
0
0 PHES
1 PHES
2 PHES
Figure 10.32: Emissions By Category Market Model
10.3.4. Wind Curtailment
This model turns off all constraints including System Non-Synchronous Penetration as discussed is
section 8.8.1. 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
Curtailment Factor
(%)
0.6
0 PHES
1 PHES
2 PHES
0.5
0.4
0.3
0.2
0.1
0
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
€14.00
€12.00
€10.00
€8.00
Base
€6.00
Market
€4.00
€2.00
€0 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.
10.3.5. 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 10.35 below.
48
New PHES
700
Turlough Hill
Generation (GWh)
600
500
400
300
200
100
0
1 PHES
2 PHES
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
(€m/MW)
1.5
Capacity
(MW)
292
Capital Expenditure
Annual Income
€ 438,000,000
€ 7,649,527
Payback
(Years)
57.26
Table 10.10: Payback Analysis Market Model
The payback results seen below in figure 10.36 clearly show the importance of reserve payments to
PHES. The base case model includes the reserve payments and the market model does not.
Free IC Base
Millions
Market Model
€400
€300
€200
€100
€0
(€100)
0
2
4
6
8
10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40
(€200)
(€300)
(€400)
(€500)
Figure 10.36: PHES Payback Period Base vs. Market model
49
10.4. 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 CO2 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 CO2 (herby C
€45) and a low carbon tax €15/tonne CO2 (hereby C €15) in 2020 with varied PHES capacity. The
investment payback of the New PHES plant in these scenarios was also examined.
10.4.1. 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 €315,871,006.88 greater than in C €30
while total generation cost in C €15 was €325,175,546.11 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 €16,954,411.82 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
€2.50
€2.40
€2.30
Billions
€2.20
€2.10
€2.00
€1.90
€1.80
€1.70
€1.60
€1.50
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
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.
50000
DISTILLATE NI
45000
DISTILLATE ROI
40000
PUMPED
STORAGE ROI
WASTE ROI
GWh
35000
30000
HYDRO ROI
25000
PEAT ROI
20000
COAL NI
15000
COAL ROI
10000
GAS NI
5000
GAS ROI
Wind Wave
0
C €15
C €30
C €45
Figure 10.38: System Generation For Carbon Tax Sensitivity
51
Gas
Coal
25000
20000
GWh
15000
10000
5000
0
C €15
C €30
C €45
Figure 10.39: Relationship between Gas and Coal dispatch and carbon tax
10.4.2. 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 €45
95
90
85
80
75
70
65
60
0 PHES
1 PHES
2 PHES
Figure 10.40: Relationship between SMP and carbon tax
10.4.3. Emissions
Gas has an emissions production rate of 56.1 kg CO2/GJ in the model, while coal has a much higher
rate of 94.6 kg CO2/GJ. The increased share of total generation from gas units in C €45 therefore
contributes to a decrease in CO2 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/tCO2 resulted in an annual emissions reduction of
52
2,797,641 tonnes of CO2, while decreasing the carbon tax to €15/tCO2 resulted in an annual
emissions increase of 921,076 tonnes of CO2.
Million tonnes CO2
C €45
C €30
C €15
18.00
17.00
16.00
15.00
14.00
13.00
12.00
0 PHES
1 PHES
2 PHES
Figure 10.41: Relationship between CO2 emissions and carbon tax
10.4.4. 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
C €30
C €45
Pool Revenue
Reserve Revenue
Pump Cost
Net Profits
€33,263,815
€40,125,496
€11,763,738
€12,037,528
(€26,186,932)
(€34,358,752)
€18,840,621
€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 10.10 and
Figure 10.29 below.
PHES Cost
(€m/MW)
1.5
Capacity
(MW)
292
Capital Expenditure
Annual Income
€ 438,000,000
€17,804,272
Payback
(Years)
24.6
Table 10.12: Calculation of New PHES payback in C €45 scenario
53
€100
€0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28
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 CO2 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
10.5. 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).
10.5.1. 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 €46,255,758.33 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
€2.20
€2.18
Billions
€2.16
€2.14
€2.12
€2.10
€2.08
€2.06
€2.04
0 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
(GWh)
1 PHES
2 PHES
Moyle
Online
291.09
576.57
Moyle
Offline
305.66
618.33
Δ
+14.57
+41.76
Table 10.13: PHES Generation - Moyle online vs. offline
55
Moyle Online
GWh
Moyle Offline
45000
44800
44600
44400
44200
44000
43800
43600
43400
43200
43000
0 PHES
1 PHES
2 PHES
Figure 10.44: Total System Generation - Moyle online vs. offline
GWh
14000
Moyle Online
Moyle Offline
12000
10000
8000
6000
4000
2000
0
Gas RoI Coal RoI Peat RoI Hydro PHES RoI Distillate Gas NI Coal NI Distillate Wind & Waste
RoI
RoI
NI
Wave
RoI
Figure 10.45: 1PHES Generation by Fuel Type - Moyle online vs. offline
10.5.2. 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
10.5.2.1.
Generator Cycling
Generation (GWh)
Generation (GWh)
No. of Starts
Number of Starts
13200
680
660
13150
640
620
13100
600
580
13050
560
540
13000
520
12950
500
Moyle Online
Moyle Offline
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.
Start & Shutdown Costs (€)
Net Revenue Earned (€)
Moyle Online
37,949,253.49
306,713,558.31
Moyle Offline
46,878,348.18
302,534,122.11
Δ
+8,929,094
-4,179.436.20
Table 10.14: Decreased net revenue for Gas RoI units with Moyle offline
10.5.2.2. Baseload Ramping
As previously discussed in Section 10.1.3.3 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 10.47 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
Minutes of Ramping
Moyle Offline
Moyle Online
350000
300000
250000
200000
150000
100000
0 PHES
1 PHES
2 PHES
Figure 10.47: Minutes spent ramping up and down by Moneypoint coal units
10.5.3. Wind Curtailment
% Wind Curtailment
Moyle Online
Moyle Offline
3.5
3
2.5
2
1.5
1
0.5
0
0 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.
0 PHES
1 PHES
2 PHES
Moyle Online
€ 12,029,199.16
€ 5,948,003.74
€ 3,497,294.46
Moyle Offline
€ 30,446,211.16
€ 18,759,109.14
€ 13,632,002.09
Revenue Lost
€ 18,417,012.00
€ 12,811,105.40
€ 10,134,707.64
Table 10.15: Wind generator revenue lost due to curtailment
58
10.5.4. 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
(€m/MW)
1.5
Capacity
(MW)
292
Capital Expenditure
Annual Income
€ 438,000,000
€ 18,322,710
Payback
(Years)
23.9
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 10.49.
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
18.76 years would be achieved.
Millions
€400
€300
€200
€100
€0
(€100)
0
2
4
6
8
10 12 14 16 18 20 22 24 26 28 30 32 34 36 38
(€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
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. CO2 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
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
http://www.naturalhydroenergy.com
http://www.organicpower.ie/content/projects/glinsk.htm
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
Works Cited
[ International Energy Agency, “International Energy Agency,” [Online]. Available:
1 http://www.iea.org/aboutus/faqs/renewableenergy/. [Accessed 20 11 2012].
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6 2008.
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Hawaiian Electric Company, “heco.com,” Hawaiian Electric Company, [Online]. Available:
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toid=94600420af0db110VgnVCM1000005c011bacRCRD&vgnextchannel=ab020420af0db110VgnV
CM1000005c011bacRCRD&vgnextfmt=default&vgnextrefresh=1&level=0&ct=article. [Accessed 25
11 2012].
[ C.-J. Yang, “Pumped Hydroelectric Storage,” 2010.
1
7
]
[ O. Torres, “Life Cycle Assessment of a Pumped Storage Power Plant,” Norwegian University of
1 Science and Technology, 2011.
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1 Ltd., 2011.
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[ Comission for Energy Regulation, “CER factsheet on the Single Electricity Market,” Comission for
2 Energy Regulation, Dublin, 2010.
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[ Single Electricity Market Committe, “SEM Committe Strategy Day Information Paper (SEM-102 013),” Single Electricity Market Committe, Dublin, 2010.
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2 Electricity Market Operator, Dublin, 2009.
2
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[
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The Single Energy Market Operator, “Pricing and Scheduling Factsheet,” [Online]. Available:
http://www.semo.com/JoiningTheMarket/Pages/PricingandSchedulingFactsheet.aspx#PandSBM20. [Accessed 1 12
2012].
[ Single Energy Market Operator, “Settlement FAQ,” [Online]. Available: http://www.sem2 o.com/training/settlement/Pages/settlfaq.aspx. [Accessed 28 11 2012].
4
]
[ The Single Energy Market Operator, “The Capacity Payment Mechanism and Associated Input
2 Parameters,” Single Energy Market Operator, 2006.
5
]
[ 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, 2012.
]
[ J. Parsonage, “Industry Presentation: SEM Capacity Payments,” SEMO, Dublin, 2007.
2
7
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[ 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”.
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[ Energy Exemplar, “www.energyexemplar.com,” [Online]. Available: www.energyexemplar.com.
2 [Accessed 2 12 2012].
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[ Commission for Energy Regulation, “Redpoint Validation Forecast Model and PLEXOS Validation
3 Report 2010,” www.allislandproject.org, 2010.
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[ The Single Electricity Market Operator, “Dynamic Reports,” [Online]. Available: http://www.sem3 o.com/Pages/default.aspx. [Accessed 07 01 2013].
1
]
[ Mutual energy, “Interconnector Physical flows,” Moyle Interconnector Ltd., [Online]. Available:
3 http://www.mutual-energy.com/The_Moyle_Interconnector/Interconnector_Physical_Flows.php.
2 [Accessed 01 02 2013].
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[ ESB, “Turlough Hill & Liffey Stations,” ESB, [Online]. Available: http://www.esb.ie/main/about3 esb/turlough-liffey-stations.jsp. [Accessed 04 03 2013].
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[ Smart Power, “Smart Power,” ECHELON, [Online]. Available: http://www.smartpower.ie/Turlough3 Hill-ESB-TH4.cfm. [Accessed 03 04 2013].
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]
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ESB, “All-Island Market Modeling Programme,” 10 2005. [Online]. Available:
http://www.google.ie/url?sa=t&rct=j&q=&esrc=s&frm=1&source=web&cd=2&ved=0CDEQFjAB&u
rl=http%3A%2F%2Fwww.allislandproject.org%2FGetAttachment.aspx%3Fid%3D39f4c30c-0a594142-b878e49d30b0d324&ei=eN81UefrM4yFhQfD_YDADw&usg=AFQjCNGqvZa1xwu6VXKgy_3_AXNKsunzwg
. [Accessed 05 03 2013].
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3 http://www.eirgrid.com/media/Generation%20Adequacy%20Report%202010-2016.pdf. [Accessed
6 26 03 2013].
]
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SEMO, “Fuel Mix Disclosure,” 29 02 2012. [Online]. Available:
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QFjAC&url=http%3A%2F%2Fwww.semo.com%2FPublications%2FGeneral%2FFMD%2520Presentation%2520v3.ppt&ei=0C1OUbrMC82Ch
QfVrIDIAQ&usg=AFQjCNFpykHFvi_a6GLTHZgfKN5r99UMFA. [Accessed 23 03 2013].
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]
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3 http://www.mutual-energy.com/The_Moyle_Interconnector/Index.php. [Accessed 12 2 2013].
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]
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4 Environment,” The EirGrid Group, June 2011.
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4 wind penetrations,” Energynautics, Dublin, 2009.
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]
[ J. G. A. S. Fred Starr, “Damage to Power Plant Due to Cycling,” European Technology Development
4 Ltd., United Kingdom, 2002.
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]
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4 http://smartpower.ie/Tynagh-CCGT-Tynagh-Energy-TYC.cfm. [Accessed 16 2 2013].
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]
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4 Breaks in Dispatch in the Single Electricity Market and Associated Issues - Consultation Paper,”
5 Comission for Energy Regulation, Dublin, 2011.
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] areirelandsgreenhousegasemissionslike/. [Accessed 26 2 2013].
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1 2 12 2012].
]
67
12.
Appendix 1: Logbook
Week 1: Oct 8th
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 15th
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
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 22nd
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 29th
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 2010.
69
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 5th 2010. The units then returned to
operation on the following dates:

Unit
TH1
TH2
TH3
TH4
Return Date
7th June 2012
14th March 2012
25th August 2012
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 5th
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 12th
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
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 19th
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 26th
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 2010-2012 and Luke reviewing 2007-2009.
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
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 3rd
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 10th
Preliminary report was submitted on the 12th of December.
Week 11: Jan 7th
Completed tasks:

The historical data analysis was completed as discussed.
Week 12: Jan 14th
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
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 21st
Done:
73


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 (€2.113 bn vs €2.042 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




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 28th
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





SWS PHES – 600MW for £800M - http://www.sse.com/CoireGlas/ProjectInformation/ ,
http://www.sse.com/uploadedFiles/Z_Microsites/Coire_Glas_Hydro_Scheme/Controls/Lists
/Resources/CoireGlasPumpedStorageBriefing.pdf
3 x 100MW
€1500/MW (in Silvermines) – how does it compare?
Current Swiss & German PHES projects
Capacity Payments may be abolished/reduced
Update Model






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 4th
SEMO DATA ANALYSIS
Use historical data in PLEXOS?
Analysis Periods: Online: 4th July 2009 – 4th July 2010, Offline: 5th July 2010 – 5th July 2011
4th April – 4th July 2011 missing
Comparisons:






Wind Curtailment/penetration
CO2 emissions – Data Prior Nov 2011 missing – t CO2/MWh? http://www.eirgrid.com/operations/systemperformancedata/co2emissions/
Reserve (?)
Generation Costs
Market Costs
Fuel Costs
PLEXOS
76
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 (€142,289.43
increase with POR added) did not equate to the SEM or Generators group Total Generation Cost
reduction.
Week 16: Feb 11th
To Do

Re run 0 and 1 phes (?) market scenarios
77








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
Email 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 18th
Work Done
78







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?
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*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
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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
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Email 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
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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 25th
Week 19: Mar 4th
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
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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 = 23.25 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)
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5.
6.
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8.
Total Gen & Cost: Look at Baseload, midmerit and peaker operation
Total Gen & Cost: SRMC?
PHS: SMP vs PHES operation (pump/gen) to show operation
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):
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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 2012-2021
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 +13.2 €/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:
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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.
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
This method of analysis is also employed by the Commission for Energy Regulation in their annual
Plexos Validation Reports.
2020 Renewable Target
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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 http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=Oj:L:2009:140:0016:0062:en:PDF].
[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??
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Things to look at
Pumping cost (at night) vs generating earnings (during peak load) for PHES
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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.
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Week 20: Mar 11th
A poster was completed and presented on the 14th of Mach.
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Week 21: Mar 18th
A presentation was delivered on Tuesday the 19th.
Analysis and write up completed for PLEXOS modelling results, section 10 in the Report.
Week 22: Mar 25th
Final Report was completed and handed up on the 27/03/2013.
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