POLITECHNIKA ŁÓDZKA
WYDZIAŁ ELEKTROTECHNIKI, ELEKTRONIKI, INFORMATYKI I AUTOMATYKI
INSTYTUT ELEKTROENERGETYKI
PRACA DYPLOMOWA MAGISTERSKA
ANALIZA CEN ENERGII ELEKTRYCZNEJ NA RYNKU HURTOWYM W ASPEKCIE DOSTĘPNYCH
MOCY WYTWÓRCZYCH I ZDOLNOŚCI PRZESYŁOWYCH SYSTEMU ELEKTROENERGETYCZNEGO
ANALYSIS OF THE ELECTRICITY PRICES AT THE WHOLESALE ELECTRICITY MARKET TAKING
INTO ACCOUNT AVALIABLE POWER CAPABILITIES AND CROSS-BORDER POWER FLOWS
Autor:
Wiktor Furmańczyk
Nr albumu: 206420
Opiekun pracy:
dr inż. Michał Wierzbowski
ŁÓDŹ, luty 2017
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TABLE OF CONTENTS
1. INTRODUCTION .............................................................................................................. 5
1.1. Executive summary ............................................................................................. 5
1.2. Thesis structure .................................................................................................. 6
1.3. List of abbreviations ........................................................................................... 7
1.3.1. In English ................................................................................................. 7
1.3.2. In Polish ................................................................................................... 8
2. ELECTRICITY MARKET OPERATION ................................................................................. 9
2.1. How does an electricity market works? ............................................................. 9
2.2. Standard Market Designs ................................................................................. 11
2.2.1. Model A – power monopoly ................................................................. 11
2.2.2. Model B – power agency ...................................................................... 12
2.2.3. Model C – wholesale market ................................................................ 12
2.2.4. Model D – wholesale and retail market ............................................... 13
2.3. Structures of wholesale electricity markets ..................................................... 14
2.3.1. Wholesale centralised market .............................................................. 14
2.3.2. Stock market – transmission system operator ..................................... 15
2.3.3. Wholesale decentralised market .......................................................... 16
2.3.4. Summary ............................................................................................... 17
2.4. Merit order vs. pay-as-bid on the pool market ................................................ 17
2.5. Bilateral market ................................................................................................ 19
2.6. Comparison between pool and bilateral markets ............................................ 19
2.7. Models of the market ....................................................................................... 20
2.7.1. Nodal pricing ......................................................................................... 20
2.7.2. Cooper plate ......................................................................................... 21
2.7.3. Comparison ........................................................................................... 22
3. DESCRIPTION AND WORKING PRINCIPLE OF THE WHOLESALE ELECTRICITY MARKET IN
POLAND ........................................................................................................................ 22
3.1. History ............................................................................................................... 22
3.2. Participants and relationships among them..................................................... 23
3.3. Structure of the market and electricity prices shaping .................................... 29
3.3.1. Active (competitive) market ................................................................. 29
3.3.2. Technical (regulated) market ................................................................ 41
3.4. Cross-border trading in the perspective of the single market for electricity in
the EU ............................................................................................................... 50
3.5. Capacity market ................................................................................................ 59
4. FACTORS AFFECTING ELECTRICITY PRICES ................................................................... 66
4.1. Power generating capacity ............................................................................... 67
4.2. Subsidy mechanisms ......................................................................................... 72
4.2.1. Cogeneration ........................................................................................ 73
4.2.2. Renewable energy sources ................................................................... 76
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5. ELECTRICITY PRICES IN THE DIFFERENT SEGMENTS OF THE WHOLESALE MARKET .... 81
5.1. Prices on the markets ....................................................................................... 82
5.1.1. January 2016 ......................................................................................... 84
5.1.2. June 2016 .............................................................................................. 86
5.1.3. September and October 2016 .............................................................. 88
5.2. Wind generation ............................................................................................... 91
5.3. Summary ........................................................................................................... 93
6. GENERAL SUMMARY .................................................................................................... 94
7. STRESZCZENIE ............................................................................................................... 94
8. REFERENCES .................................................................................................................. 95
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1. INTRODUCTION
Nowadays, electricity access is fundamental for each society. An average person does
not think about how electricity appears in a power socket, because it is mostly available
and must be paid by a consumer. However, somebody will enquiry about the electricity
price to know how it is shaped and to discover for what, basically, is expected to pay.
In the history, the definition of the electricity market did not almost exist, because the
production, the transmission and the distribution of electricity were supervised by a
country which focused all the electricity industry. It was common for communist
Poland where lasted the electricity monopoly. In this reality, the government
encountered many barriers, both technical and economic natures. There were not
well-known mechanisms for investments and developments in the power sector. The
reform of this sector was needed. The idea for improving the electricity effectiveness
and for reducing the electricity costs was the implementation of the electricity market
[16].
1.1. Executive summary
The main objective of this thesis is focusing on the electricity market and its role in
electricity trading in Poland. However the report reviews the various designs of
wholesale electricity markets with special reference to the pool market, that is an
electricity price determinant, even for over the counter transactions in the shape of
bilateral agreements.
Poland, considered as a developed country, is developing market mechanisms in
electricity trading in the form of many instruments on the stock market called
Towarowa Giełda Energii S.A., hence this market is described in detail. Since electricity
is traded to be physically transmitted at the end, there is also a mention of the
balancing market.
The pool market does not operate only domestically, but is partly integrated with
foreign markets under the conception of the pan-European electricity market. The
thesis refers to cross-border power flows and their impact on prices.
The Polish energy system needs to be safe, where energy is eco-friendly produced at a
reasonable price taking diversified energy mix into account. Following this issue, the
thesis is supplemented by the recent situation regarding renewable energy sources
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and cogeneration. There is also a short description of the proposed capacity market.
The analytical part of the report refers directly to its theme. It is to compare prices on
the day-ahead market and the balancing market depending on the system’s
operational condition in the different specified periods.
1.2. Thesis structure
The thesis is divided into six chapters. Chapter 1 introduces the primary topic
addressed in the report.
Chapter 2 is to show possible standard market designs. The wholesale market seems
to be the most liberalised and competitive among presented ones, hence the report
focuses on it. Trading on this market may take different forms. The chapter presents
its two structures: centralised and decentralised, its two price clearances: pay-as-clear
and pay-as-bid and its two models of pricing: nodal pricing and cooper plate. Each
regulated market operates collaterally with bilateral market, but one of them is usually
prevalent. At the end of the chapter these two markets are compared in tabular way.
Chapter 3 includes a full description of the Polish wholesale market. It starts with its
history. Further there is information on the players trading on the active and technical
markets. The complexity of these two segments shows subchapters 3.3.1 and 3.3.2.
Cross-border trading completes the described domestic market. The chapter ends with
analysis of the recently proposed capacity market.
Chapter 4 focuses on factors affecting electricity price. They refer to available capacity
of Centrally Dispatched Generation Units supervised by the transmission operator and
subsidy mechanisms for the specified generation methods.
Chapter 5 is a practical part of the report showing prices on the spot markets and their
variability. The analysis depends on the comparison between these prices and the data
derived from current daily coordination plans delivered by the operator. On this basis,
conclusions have been drawn.
Chapter 6 summarises the report as a whole. Chapter 7 provides an executive summary
in Polish. Chapter 8 does not introduce any additional information. It consists
references.
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1.3. List of abbreviations
1.3.1. In English
ACER – Agency for the Cooperation of Energy Regulators,
ATC MC – Available Transfer Capacity Market Coupling,
ATC – Available transfer capacity,
CACM – Capacity Allocation and Congestion Management,
CBR – Cross-border redispatching,
CCME – Certified Capacity Market Entity,
CCP – Corrected contract position,
CDCP – Current Daily Coordination Plan,
CDGU – Centrally Dispatched Generation Unit,
CDV – Corrected delivery volumes,
CEE – Central Eastern Europe,
CfD – Contracts for differences,
CFIM – Commodity Forward Instruments Market,
CHP – Combined Heat and Power,
CRM – Capacity Remuneration Mechanisms,
DAM – Day-ahead market,
DCP – Daily Coordination Plan (see the context in the text),
DCP – Declared contract position (see the context in the text),
DSO – Distribution System Operator,
DSP – Deviation Settlement Price,
DSR – Demand Side Response,
EAM – Emission Allowances Market,
ERO – Energy Regulatory Office,
FBA MC – Flow-based Allocation Market Coupling,
FCC – Final clearing price,
FIM – Financial Instruments Market,
FSA – Financial Supervision Authority,
HHI – Herfindahl-Hirschman Index,
IDM – Intraday market,
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IPR – Interventional power reserve,
LPD – Linear Programming Dispatch,
MRA – Multilateral remedial action,
MRC – Multi-Regional Coupling,
nCDGU – Non-centrally Dispatched Generation Unit,
NEC – Net Export Curve,
NIMBY – Not in My Backyard,
NPS – National Power System,
OPR – Operational power reserve,
OTC – Over the counter,
PMP – Physical measuring point,
PPS – Polish Power System,
PRM – Property Rights Market,
PTDF – Power Transfer Distribution Factors,
RDV – Real delivery volumes,
RED – Real electricity delivery,
RES – Renewable energy sources,
RO – Reliability options,
SCED – Security-constrained economic dispatch,
SCUC – Security-constrained unit commitment,
TGC – Transmission Grid Code,
TPA – Third Party Access,
TSO – Transmission System Operator,
UCTE – Union for the Coordination of the Transmission of Electricity,
VCP – Verified contract position,
VDV – Verified delivery volumes,
VoLL – Value of Lost Load.
1.3.2. In Polish
GPI TGE – Giełdowa platforma informacyjna Towarowej Giełdy Energii S.A.,
OZE – Odnawialne źródła energii,
PGE – Polska Grupa Energetyczna S.A.,
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PKN – Polski Koncern Naftowy,
PSE – Polskie Sieci Elektroenergetyczne S.A.,
TGE – Towarowa Giełda Energii S.A.
2. ELECTRICITY MARKET OPERATION
2.1. How does an electricity market works?
The primary purpose for the introducing of an electricity market is to decrease the
overall electricity prices for both wholesale and retail customers. Other reasons for this
activity are:
improvement in the power economy effectiveness,
encouragement for new investments in production and transmission,
possibility to choose a wide range of suppliers due to competitiveness on the market,
consumer protection guarantee due to the legal market regulations,
improvement in the electricity quality.
The main rule of the working of the electricity market is the division between the
electricity as the product and its delivery as the service. When the electricity is
considering as the product, it can function on the market. On this market all
participants must have equal rights and unfettered access if it is possible technically or
financially. It is essential for the competitive electricity price shaping as a result of the
equilibrium between supply and demand. However the electricity market differs from
the rest markets, because the services are more important than the financial
operations over the products. A transmission system operator (or operators) is
responsible for the distribution of loads balancing demand uninterruptedly, because
energy is not able to be large-scale stored. It is being done considering stability, safety
and integrity of a transmission system.
In general the entire market process consists of the three main phases: preparation,
main market process and completion (fig. 1). The process is initiated by the participants
who sell and purchase electricity. The contracts (in different forms) are led by a market
operator on a central market or by both the transmission system operator (TSO) and a
power exchange on a stock market. When the market is decentralised, technical and
trade operators conclude contracts and prepare load schedules. Hence, the market
organization decides how the market process runs.
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Preparation
Bilateral contracts
Stock transactions
Balancing transactions
Distribution of loads
Completion
Payments for bilateral contracts
Payments for stock transactions
Payments for balancing transactions
Ancillary servicesPayments for ancillary
services
Capacity contractsPayments for capacity
contracts
Fig. 1. Main market processes Source: own development based on [22]
In order that the aforementioned market processes can be achieved, some market
rules must be followed. The well-functioning electricity market is relied on
competitiveness of its participants which should be limited only by technical
restrictions. It is possible to implement, when all suppliers and customers are treated
equally regardless of production technology, energy consumption volumes and
country policy. There is a need to develop the law to prevent market abuse. If the
market aims to keep low prices, there should be no cross-border barriers bringing in
the exchange consciously to favour chosen participants, e.g. domestic suppliers. Each
customer should have the possibility to choose any available supplier or seller on the
market not considering energy flows and network access. Taking into these aspects
account, the market operator coordinating with the TSO is under obligation to
implement a simple market structure suited to domestic conditions. This structure
should be flexible for futures changes in the sector.
The electricity market is a tidal market where prices are setting and loads are
distributing for the defined trading period. It is usually a hour. These basic periods
apply for both the stock market and the balancing market. It caused that the
participants must schedule volumes and prices for energy for each trading period. Both
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the stock and balancing prices are the base prices for all market and shape the prices
for bilateral contracts.
2.2. Standard Market Designs
Considering the structures and the operating principles for electricity markets, there
are four main models of the following forms 8:
power monopoly,
power agency,
wholesale market,
retail market.
2.2.1. Model A – power monopoly
This model focuses all electricity branches that are integrated vertically (fig. 2). End-
consumers can buy energy from the assigned distribution system operators to which
are connected. The operators are regulated by local authorities or able to operate
freely, partly or fully. The electricity prices are continuously supervised by a
government which manipulates them. Consequently, power monopolies act in
countries where the market reforms were not mandated, i.e. authoritarian countries.
Power monopoly
Generation
Distribution of loads
Transmission network
DSO2 DSOnDSO1
E-C1 E-C1n E-C21 E-C2n E-Cn1 E-Cnn
Fig. 2. Model A – power monopoly Source: own development based on [22]
Abbreviations: DSO: Distribution System Operator; E-C: End-customer
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2.2.2. Model B – power agency
The most important function in this model is exercised by an independent power
agency which buys energy from different producers (fig. 3). The agency has the
exclusive right to set the electricity prices and to decide about distribution of loads. It
is mostly realised by concluding long-term contracts between the agency and
producers or distribution system operators. In the result, the power agency is
responsible for investments in the power industry fulfilling a specified policy. In Poland
in the 1990s this function was conducted by Polskie Sieci Elektroenergetyczne S.A.
(PSE), which operated in a similar system then.
Power agency
Transmission system operator
DSO2 DSOnDSO1
E-C1 E-C1n E-C21 E-C2n E-Cn1 E-Cnn
GEN1 GEN2 GEN3 GENn
Fig. 3. Model B – power agency Source: own development based on [22]
Abbreviations: see fig. 2; GEN: Generator
2.2.3. Model C – wholesale market
On a wholesale market producers offer energy bids at the fixed process defined by
them. These bids are sold on a day-ahead market or are the objects of the agreements
in bilateral contracts. The wholesale markets are temporary, because they are
established to form markets where end-customers can purchase energy from any
distribution system operator (DSO). By contrast, on this market customers are limited
to connected lines owned by a specified operator. There is a division of the wholesale
market into three forms: centralised market, stock market – transmission system
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operator and dispersed market (see subchapter 2.3). In figure 4 the structure of the
market is shown.
Wholesale day-ahead market
DSO2 DSOnDSO1
E-C1 E-C1n E-C21 E-C2n E-Cn1 E-Cnn
GEN1 GEN2 GEN3
Fig. 4. Model C – wholesale market Source: own development based on [22]
2.2.4. Model D – wholesale and retail market
The last model is the extension of the model C. There are many ways for concluding
contracts. Anyone who has the energy trading license is able to trade energy as a
trading company. For example, the trading company can sell energy to final customers,
but earlier is obliged to pay distribution fees the network owner from which the end-
customer is energised. Connections among different participants are presented in
figure 5.
Wholesale day-ahead market
DSO2 DSOnDSO1
E-C1 E-C1n E-C21 E-C2n E-Cn1 E-Cnn
GEN1 GEN2 GEN3
Fig. 5. Model D – wholesale and retail market Source: own development based on [22]
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2.3. Structures of wholesale electricity markets
As mentioned in subchapter 2.2.3 wholesale electricity markets are described
according to the forms of operation. When the market is centralised, both the stock
market and the balancing market function linked to each other. On this market energy
trading is led by the stock and transmission system operator. On the other hand, these
two markets can be clearly separated. The TSO does not participate in the stock
market, but is solely responsible for balancing the system then. The last form regards
a dispersed market where coordinators manage the scheduling units on behalf of stock
members in commercial terms or in both commercial and technical terms.
2.3.1. Wholesale centralised market
The centralised market is a market where stock and balancing transactions are
integrated. This market works mainly based on marginal pricing as a pool market. It
means that participants submit offers for selling and bids for purchasing electricity, but
the last accepted bid is binding and sets the market price. This process is conducted by
the operator who takes the production offers and arranges them in ascending order.
Furthermore the operator manages distribution of loads included the system balancing
pursuant to offers taking into account technical constraints of generation and
transmission (imbalances, outages, ancillary services and so on). The operator is also
able to outsource financial managing to a specialised financial institution. Additionally,
there may be companies spun off by the operator for managing transmission system
properties.
Financial contracts on the market can be concluded in different ways. They may be
direct among participants (bilateral contracts), indirect by the agency or the financial
institution and run on the stock market as forward instruments. There is no obligation
to reveal information on contracts to the operator. These contracts are concluded to
compensate differences between the contract price and a temporary market price
then. However participants can throw contracted energy volumes open to the
operator. In this case they account for them with the operator. These volumes are
compared with the energy volumes for selling or purchasing set on the centralised
market.
All participants on the centralised market announce their offers and bids in the defined
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trading periods. There is a possibility to submit them at both the positive and negative
prices. When a producer delivers a bid with the negative price, e.g. during low demand
in the night valley, he is willing to pay additional supplements at a declared price into
his energy in order not to be disconnected from the transmission system. It is often
argued by high costs of restarting a shut generation unit.
To sum up, on the centralised market, the price for a power unit in the scheduled
period is set by the equilibrating of supply volumes and forecasted demand. The
demand is created by accepted offers of purchasers, therefore the centralised market
is a real-time pool market with integrated segments leading by the operator.
2.3.2. Stock market – transmission system operator
The main operating principle of the wholesale market as a stock market – transmission
system operator is a separation of electricity trading from technical aspects of the
transmission system. In practice, it provides to create the two markets, islanded, but
working sequentially in time.
This wholesale market consists of the two market types. The first is optional based on
the power stock exchange, which diverts electricity on the stock market by the way of
setting the equilibrium point between supply and demand. Consequently, it
determines the price and the volume for accepted offers and bids (spot market). This
base price shows the market power of the participants and the way of its shaping
allows to maintain market’s competitiveness. The other products of this market are
forward and futures transactions (physically or financially). They take place in the
various periods (weekly, monthly, quarterly or annually).
When the power stock exchange operates based on a flexible price for demand, the
balancing market is almost unpredictable and inflexible. This market is managed by the
TSO, who is responsible for maintaining sufficient capacity reserves to make the
transmission network operation safe. In order to balance the system taking into
account all transactions from the stock market and bilateral contracts, the TSO must
have enough amounts of the balancing offers, both the incremental and reducing ones.
In the result the TSO answers for financial flows appearing between contracted and
real used energy. On the balancing market in this model next to the marginal prices,
the bid prices and the clearing prices apply as well. After correcting the contracted
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energy volumes by the TSO, he must balance participants’ contract positions. The
difference in prices for the energy volumes between the contracted and the corrected
ones is the bid price and the same difference between the corrected and the real used
ones fixes the clearing price.
2.3.3. Wholesale decentralised market
On this market three actors operate: a power stock exchange, a TSO and a scheduling
coordinator. The roles of the first two persons are the same like on the stock market,
where electricity trading is separated for its transmission. The new actor – the
scheduling coordinator is a holder of the scheduling units. He can operate them making
their commercial work schedules for generating and consuming ones and cooperating
with the TSO. In these conditions, he is a broker in contracts to buy or sell at the level
of the transmission or distribution system. On the market there are also scheduling
coordinators who not only make their scheduling units available commercially, but also
are under obligation to balance them on the prepared work schedules taking into
account technical constraints. Consequently, such coordinator is a broker for the TSO
on the balancing market. The multitude of relations on the decentralised market
makes the bid contracts and transactions between each participant (fig. 6).
GENERATORS
DSO
POWER STOCK EXCHANGE
NON-TARIFF CONSUMERS
TRANSMISSION SYSTEM OPERATOR
Energy supply
Bid contracts Bid contracts
Bid transactions
Bidtransactions
Bidtransactions
Fig. 6. Wholesale decentralised market Source: own development based on [22]
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2.3.4. Summary
The shown different market designs are the models for the market evolution from the
power monopoly to the decentralised market (fig. 7). In Poland the last described
market functions, however its implementation was a complex process.
POWER MONOPOLY
POWER AGENCY
MARKET AND TRANSMISSION SYSTEM OPERATOR
POWER EXCHANGE
TSO
POWER EXCHANGE
SCHEDULING COORDINATORS
TSO
Fig. 7. Market evolution Source: own development based on [22]
2.4. Merit order vs. pay-as-bid on the pool market
The wholesale centralised market relies on the auctions involving offers to supply
energy and bids to buy it. Generally these auctions are run according to uniform pricing
under the pay-as-clear system. It allows to choose the most competitive suppliers who
are automatically awarded the marginal price. This price is a price for last accepted bid
that is the most expensive simultaneously. The value of this bid schedules the total
customer demand to meet, because the operator ranks all offers and bids according to
their prices. Offers of producers establish the ascending curve which let select the
least-costly resources (the merit order auctions).
Due to increasing the electricity costs, some countries introduced the pay-as-bid
auctions. All winning suppliers in a given period receive payments according to their
individual offers. In this system the cheapest suppliers have no encouragement to keep
their prices at the low level, when others earn more. Thus they are forced to change
the bidding strategy by trying to push the offer price up as closest to the price of the
highest approved offer. However, when the demand is low these suppliers may be
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omitted because of overestimated prices.
The prices for these auctions can be settled ex ante (before delivery) and ex post (after
delivery considering measured power consumption). Power exchanges use the ex ante
system, therefore all prices are shaped based on demand forecasting as a basis to win
a transaction. Consequently, the physical delivery takes place through the balancing
market.
In theory both the systems give similar results, but the pay-as-clear one works better.
Not only the second does not reduce the costs, but also lead to unhealthy competition.
The pricing schemes are shown in figure 8.
Fig. 8. Pay-as-clear auctions (A) and pay-as-bid auctions (B) Source: own development based on [36]
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2.5. Bilateral market
The bilateral market allows their participants to exchange energy under jointly
agreeable rules. This market is fast decentralised. The parties of the contract can freely
form their agreements. It seems to prevent fluctuations in prices by performing long-
term planning, making cost-effective investments and developing cheaper resources.
The majority capacity is traded among participants, but the rest can be transferred to
the power stock, which is similar to the pool market. Even though electric energy may
be set by the market rules or on a cost basis, sellers and buyers on this market are
hedged against unpredictability in the real-time market.
SUPPLIERS
BUYERS
STOCK TSOBILATERAL CONTRACTS
OFFERS
BIDS
LOAD
DEMAND INFORMATION
VOLUNTARY SUPPLY INFORMATION
Fig. 9. Bilateral market operation Source: own development based on [24]
2.6. Comparison between pool and bilateral markets
Both pool and bilateral markets can function together permeating to each other, but
one of them is mostly prevalent. The main benefits and weaknesses of these two
markets are described in the undermentioned table 1.
Table 1. Pool and bilateral markets – benefits and weaknesses (based on [4], [24], [42])
Market Benefits Weaknesses
Pool market
provides price transparency and discovery,
open for all generation units, attractive for small ones which low variable costs,
generates low transaction costs revealing prices and capacity of each counterparty,
convenient for building long-term business relationships,
may not be impervious to unexpected outages without enough developed capacity mechanisms,
difficult to manage when trading is virtual and scheduling remains wrong,
able to market power abuse by dominating huge units which keep high prices consciously to maximize their revenues,
may form confidential concerns.
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easy to manage by facilitating demand-side participation and real-time action,
possible to predict the risk by developing financial instruments.
Bilateral market
friendly for suppliers and buyers who prefer unfettered trading,
incentive to reasonable investments to decrease production costs, i.e. by diversifying the energy mix,
operates to promote long-term contracts to limit prices fluctuations,
weakens market power abuse.
hard to balance when majority of supply is out of the operator’s awareness,
subject to privilege huge units who can provide continuous power delivery,
complex, requires the balancing market to dispatch centrally.
2.7. Models of the market
The power flows generate loses according to the physical laws. They limit the
transmission network efficiency and force generators to work in severer conditions to
balance them. In high voltage lines such loss is about 2 – 2,5%. The lower voltage, the
higher loss up to 8 – 10% in low voltage lines [22]. Consequently, these loses must be
covered by the network operators. They are paid by end-customers through the
constant fees. For transmission networks, not only loses constitute the transmission
fee, but also other factors associated with: capital and operating (capex and opex)
expenditures, congestion costs, ancillary services et al.
There are two models for pricing issues: nodal pricing and cooper plate. To reflect
differences between them, physical and virtual networks are taken into account.
2.7.1. Nodal pricing
This model forms pricing, when the detailed network model is considered. It means
that each consumer pays for electricity based on his localization from the nearest node.
The whole system is divided into linked nodes represented by generators and
recipients. The connections are featured by network loses factors that resulted from
distribution of loads effectively. These factors impact on prices, thus they can be
simulated and averaged for the selected trading periods on the market. However such
analyses are always more or less vitiated. Due the fact that in this model the
transmission costs are the integral part of the electricity price in the bids, the TSO may
have surpluses or shortfalls in fees. It makes the operator as a market participant and
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should be excluded by proper law regulations. For the operator is easier to impose
shortfalls costs on consumers regarding regulatory accounting, but in general such a
model motivates him to keep the transmission costs low.
2.7.2. Cooper plate
When putting all producers and consumers on the plate, network flows can be ideal
without any constraints. It allows to operate freely on this plate (cooper plate) when
appearing transmission loses are assigned to the balancing (virtual) units. The loses are
paid equally by each consumer.
The whole plate may be characterised by its input and output. They are continuously
changing since their values are forecasted. The vital predictions arise, when the
operator gets the results of the auctions finished on the intraday market. It is crucial
for creating re-dispatch if earlier prepared timetable management does not work. All
in all, such a situation generates the varying transmission cost, that is calculated by
averaging the nodal prices or providing for real dispatch. However there is no point
diversifying it, when transmission loses are omitted. The cost is always equal for all
recipients, who pay additional money for transmission charges in their bills. In some
cases it occurs as a coefficient factor added to the price when is cleared. Contrary to
the nodal pricing, the costs for electricity and transmission do not have an impact on
each other remaining separated.
Moreover, there is a system that links the two aforementioned models for pricing –
zonal pricing. In this system different locations are divided into the zones, where
transmission constraints may be almost ignored. On the other hand, congestion
between the zones (interzonal limitations) appears frequently with huge network
impact. Consequently, the electricity prices differ based on the region. When zones
operate in the uniform system determining a market, it is similar to the cooper plate
pricing. However the zones may comprise several such nodes as a collective node.
Generally, the market relies on interzonal and intrazonal congestion management.
There is a marginal price for relieving congested transmission capacity. The new zones
may be established, when the intrazonal transmission costs are high which means
frequent constraints. It is a possibility to link many large market players in the new
zone that may be inefficient for a reasonable price. Therefore the creation of the new
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zones must run under a competiveness condition. [17]
2.7.3. Comparison
It seems that the nodal pricing is more fair for end-customers, because it differs among
transmission constraints creating regional balancing markets (there is no necessity for
re-dispatching) when the nodes are formed in the zones. These markets can work
better for small communities by encouraging new players to invest locally to limit
power outages. It allows to decentralize power generation units (to decrease
monopolist) and to relieve the transmission network during peak demand. However in
the large zone there could be a collusive concentration of big producers, who are able
to set the controlled prices in network hubs. For economic reasons, it is better to build
a new industrial plant closer to a generator in order to minimize the transmission costs.
Then the electricity price is strongly related with investment decisions that can limit
the remote areas’ security. [11]
The second system is easier to understand, because is devoid of the complex market
process. It is resulted in balancing management from the perspective of the entire
transmission network. However it may remain less effective when considering the
optimization for power flows and the social surplus maximization. [11]
3. DESCRIPTION AND WORKING PRINCIPLE OF THE WHOLESALE ELECTRICITY MARKET IN POLAND
3.1. History
The Polish power sector started to change after 1989, when the country was at the
beginning of the political transformation. Electricity changed its status from a good to
a commodity. The recipient was increasingly perceived as a customer who needs a
valuable product. However, the Polish government launched the market elements to
the power sector in the half of the 1990s. In 1997 the new law called Prawo
energetyczne regarding the power sector was established. The first activity was based
on long-term contracts supervised by Polskie Sieci Elektroenergetyczne S.A. These
contracts involved the majority of the electricity production and were not set by the
market rules. It seemed that an electricity market was needed, but nobody knew how
to derive from the examples of the electricity market mechanisms in the world
23
effectively. The another question was how to balance supply and demand. In 1999, the
Ministry of Treasury announced the tender for introducing the electricity market. It
was mainly supported by PSE S.A. and Energoprojekt-Consulting S.A. (owned by PSE).
In December 1999, the Ministry accepted the market project and the power exchange
– Giełda Energii S.A. started to work. PSE was obliged then to develop rules of the
balancing market operation and the Transmission Grid Code (TGC). The balancing
market has been launched in September 2001 consociating the largest producers.
Despite many supporters of a pool market, the early market model was based on
bilateral contracts on the Germany pattern. The spot market on the power exchange
completed these contracts and the day-ahead transactions on the balancing market.
However there were many hardships in managing the balancing market by the TSO.
The transmission network worked in the copper plate system (see subchapter 2.7.2)
with centralised distribution of loads based on the node constraints. [21]
After the Poland’s accession to the European Union, the Polish electricity market has
started to move towards the European market. In 2003 the power exchange (currently
Towarowa Giełda Energii S.A.) obtained a license for running a commodity exchange.
However, the key role in liberalisation was the year 2007 with the law about the
mandatory termination of all long-term contracts that limited market development.
The whole market was transforming gradually into the decentralised market. The
regulated markets became more and more popular as a form of trading. Towarowa
Giełda Energii S.A. (TGE) broadened its markets setting i.a.: intraday market, property
rights market, physical forward market. Currently the Polish electricity market is
divided into three segments dependent to each other: active (competitive) electricity
market, technical (regulated) market and financial market. These markets are
described in details in consecutive chapters. [21], [37]
3.2. Participants and relationships among them
Interactive influence of different players on the market is crucial for the optimization
of their market position. There can be interactions between players by exchange
(seller – buyer) and by parallel relationships (seller – seller). Information flow
determines participants’ behaviour, who compete with each other on the competitive
market. On the whole on the Polish wholesale decentralised market run the following
24
players:
power generators (G),
the Transmission System Operator (TSO),
business coordinators (BS) along with Towarowa Giełda Energii S.A. and trading
companies (running on the retail market as well),
scheduling coordinators (SC),
recipients: distribution companies (DC) as wholesale recipients (retail suppliers) or
distribution system operators (DSOs) and end-consumers as entitled or
transmission network recipients.
G1
G2
Gn
IMPORT
GENERATORSBUSINESS
OPERATORS
TGE S.A.
BROKERS
SCHEDULING COORDINATORS
SC1
SC2
SCn
SYSTEM OPERATORS
TSO
DSOs
RETAIL SUPPLIERS
DC1
DC2
DCn
END-CONSUMERS
EC1
EC2
ECn
RETAIL MARKETWHOLESALE MARKET
MARKET OPERATORSDISTRIBUTION COMPANIES
Fig. 10. Players on the markets Source: own development based on [35]
On the Polish power exchange there are also the market makers, who conclude the
contracts with the exchange for placing sale and purchase orders in order to keep
selected financial instruments fluency. In general, the structure of market players was
shaped by the consolidation process (horizontal and then vertical) of power companies
that came from the Programme for the power sector accepted by The Council of
Ministers in 2006.
Currently the wholesale market regards the electricity trading as a commodity supplied
or received in transmission (high voltages) networks. These networks shape the closed
widespread grid of connections with generators attached. The transmission system is
important for balancing purposes, thus the boundary between the wholesale and retail
25
markets is the 110 kV distribution network to which the Centrally Dispatched
Generation Units (CDGU) are connected. The wholesale market operates as a
competitive market, while the retail one is regulated by the Energy Regulatory Office
(ERO). The electricity trading at a preparation stage is related with the Grid Codes both
for the transmission and distribution systems that state eligibility for the operators in
these systems.
Power generators
Power producers (included importers) operate on the supply side in the market. They
can be distinguished taking into account a fuel for the electricity production. Based on
data from the TSO the majority of generation drew on fossil fuels in 2015 (84% of total).
It means that the generation units burning hard and lignite coal are dominant in the
electricity trading for their owners in the capital groups. There are the three largest
producers: PGE Górnictwo i Energetyka Konwencjonalna S.A., TAURON
Wytwarzanie S.A. and ENEA Wytwarzanie sp. z o.o., who made the generation sub-
sector averagely-concentrated according to the HHI factor for 2015. They fed together
54.7% of 149.1 TWh into the transmission grid in the same year. [34]
Power producers are able not only to sell energy in the various market segments
(included over-the-counter trading), but also to operate on the technical market
offering the control system services. The producer as a generating unit’s administrator
can get its managing over to a scheduling coordinator. However in each case the
producer is under obligation to make a timesheet elaboration for concluded sales
agreements. In practice, the timesheet defines the electricity flows for each hour of
the daily trading period in the contract’s duration. This division of the energy volumes
must be also properly assigned for each generating unit of the producer taking into
account technical constraints and other services by the scheduled unit. Consequently,
the producer establishes the generation scheduling units that reflect his contract
positions. Because of many forms of trading, the well-prepared timesheet is a key point
for a producer’s revenue.
Transmission System Operator
The Transmission System Operator (PSE) is a licensed monopolist who brokers
26
between the electricity trading and its physical flows. The operator acts a key role in
the competitive market functioning. The profile of his activity involves managing the
transmission system, conducting the balancing market and developing
competitiveness on the electricity market. For all these objectives the operator is
expected to command the well-functioning technical infrastructure of the national
transmission grid so that all regions of Poland could have unfettered access to the
electricity supply. It requires to ensure the necessary development of the Polish Power
System (PPS) which should work securely and cost-effectively taking into account the
synchronous operation of the European power system, asynchronous connections,
cross-border interconnections and the balancing requirements. Despite the priority of
the PPS’s stable operation over trading activities on the market, the operator must
provide enough capacity and energy in the system. To realize such a goal, he makes
the coordination plans with different durations, supervises distribution of loads and
purchases the technical services. Moreover he administrates the balancing market by
operating scheduling units defined in the TGC.
Polskie Sieci Elektroenergetyczne S.A. has the TSO role approved by the ERO President
to the end of 2030. PSE runs a licensed activity with the regulated electricity tariffs for
transmission. The company belongs to the State Treasury which is a sole stakeholder.
Currently PSE is exercised by the Government Plenipotentiary for Strategic Energy
Infrastructure.
Business coordinators
The business coordinator is a commercial holder of the scheduling unit belonging to a
trading company as the balancing market player. To operate on the balancing market,
he must conclude the contract with the TSO. The coordinator manages his virtual
scheduling units by making the commercial timesheet elaboration for the electricity
flows. When he is not a sole holder of the unit, he cooperates with a scheduling
coordinator who is a timesheet recipient. Otherwise he sends timesheets to the TSO
or to the appropriate DSO for verifying and approving. The business coordinator may
be also a settlement party for sales agreement concluded on his behalf.
27
Trading companies
The trading companies operate on the different market segments buying or selling
energy. They can participate in the stock exchange sessions or be a contract side when
they buy energy from producers and sell it to consumers in bilateral contracts. Their
activity relies on making profits by achieving the highest spread between the offer and
bid prices for as the great energy volumes as possible. However it is always connected
with prices fluctuations, therefore the company must manage its risk effectively. The
company reports sales agreements to the TSO regardless if its contract position is close
or open. When the contract position is open (unbalanced), the company can operate
on the balancing market predicting a profitable clearing price (but it increases the risk).
Assuming that the company purchased less energy on the market than sold in
consecutive trading periods, it must buy some more at the real clearing price.
Conversely, the company resells the excessive volumes to the TSO. All trading
operations are conducted according to the timesheets for the virtual scheduling units
with pointed deviation from the contract position. Such a scheduling unit consists
always of the offer unit and the bid unit.
Currently there are 464 trading companies, who have a valid license approved by the
ERO President for the electricity trading [38].
Scheduling coordinators
The scheduling coordinator has a similar role to the business coordinator. He takes
over some of the tasks of suppliers, recipients and the TSO if he meets the formal and
legal requirements. Consequently, he operates the scheduling units belonging to the
aforementioned players. These units are the physical places for energy delivery or
energy collection, thus this coordinator manages them in its both commercial and
technical scope. In order to he can prepare the balanced timesheets for the scheduling
units, he must act on all aspects of the concluded contracts. For generation units it is
necessary for him to take into account technical matters such as maximum and
minimum production specifications, start-up times, ramp-up rates and others. Instead
for receiving units he administrates their connectivity and intake the timesheets.
What is more, the scheduling coordinator is able to balance transmission system
constrains by offering the control system services. On the other hand changing
28
production and transmission conditions in time are the reasons for the correcting
preliminary timesheets. The operational functions of the scheduling coordinator finish
with the settlement of the contract positions, when the scheduled flows are compared
with the measured ones.
Distribution system operators
In 2016 there are 121 companies registered by the ERO as eligible for the electricity
distribution [38]. There are the five main distribution companies: PGE Dystrybucja S.A.,
TAURON Dystrybucja S.A., ENEA Operator Sp. z o.o., ENERGA-Operator S.A. and RWE
(Innogy) Stoen Operator S.A.
The DSO operates on the wholesale market in the role of a distribution company, which
buys energy there and sell it on the retail market to end-consumers connected to its
grid or embracing the Third Party Access (TPA) principle. Similar to the other players,
the DSOs can conclude the agreements through bilateral contracts, the power
exchange transactions and the balancing transactions. They also prepare the
timesheets for the accepted sales contracts, but they can operate under less restrictive
technical circumstances than the power producers. Although they do not need to place
an offer on the balancing market, they are passive participants on this market, because
their contract positions remain always open. It results from prediction difficulties for
load curves of their recipients. Even though energy consumption forecasting is
accurate with little error for a month or a year, there is a necessity to balance all
deviation as closest the delivery day, that may be done on the day-ahead market, on
the intraday market or on the balancing market. Consequently, the operation of the
distribution company involves the price fluctuation risk.
In some ways they are forced to operate on the balancing market because of variable
electricity demand of their end-consumers (contrary to the scheduling coordinators
who act there to maximise profits). When the distribution company is a balancing
company (connected to the transmission grid) on the balancing market, he must have
a balancing scheduling unit [28].
End-consumers
According to the Energy Law Act (Chapter 1, Article 3) an electricity recipient is any
29
person, who receives or loads energy pursuant to the agreement with a trading
company. If this recipient uses electricity only for his own needs, he is called an end-
consumer. A distribution company (DSO) operates on the two markets simultaneously
as a wholesale recipient and a retail supplier.
The most relevant for the development of the competitive market in Poland was the
amendment to the Energy Law in 2005 that assumed as of 1 July 2007 the
implementation of the TPA principle. It means that all electricity consumers are able
to choose any supplier and all distribution or trading companies can sell energy to any
their recipient. However in 2015 only more than 375 thousand from about 15.4 million
end-consumers with the G tariff group (for households) embraced this principle
actively. Similarly in the other tariff groups (A, B, C) slightly more than 12% of total
decided to change a current supplier. Consequently, the majority of end-consumers is
energised from the suppliers of last resort, who in large part belong to so-called
incumbent suppliers. They are a comprehensive agreement party (after the
implementation of the unbundling principle). [34]
On the other hand on the wholesale market the entitled end-consumers operate, who
are connected to the transmission or distribution grid within the range of the balancing
market. They can buy energy directly from a power producer or indirectly from a
trading company concluding bilateral contracts. On the power stock exchange they
also participate on the demand side as non-tariff recipients. Such an activity requires
an ability to predict demand and the proper telecommunication equipment to balance
it, thus these recipients are usually huge companies. Of course the entitled end-
consumer can cooperate with a business or scheduling coordinator in the range of
managing his receiving scheduling unit on the balancing market.
3.3. Structure of the market and electricity prices shaping
3.3.1. Active (competitive) market
The Polish Power Exchange
Towarowa Giełda Energii S.A. has been functioning since 1999 and plays an important
role in making the wholesale electricity market more competitive. It is owned by the
Warsaw Stock Exchange who is a sole stakeholder. The exchange is under supervision
of the Financial Supervision Authority (FSA), what guarantees its transparency and
30
safety in trading on all markets offered. All transactions made on TGE are settled by
the Commodity Clearing House.
TGE is shaped by the legal regulations in Poland and the European Union. The
important role in its development was the operation of the unbundling principle on 1
July 2007 and later in 2010 the exchange obligation. It caused that power producers
have stopped selling energy mainly within the same capital groups and by the Energy
Law Act were forced to participate in the exchange with 15% of energy generated
(except from the producers related with PSE by long-term energy contracts, who must
trade on the exchange fully). Today the exchange is a place, when producers sell almost
a half of energy offered [34].
THE POLISH POWER EXCHANGEELECTRICITY
DAY-AHEAD MARKET
INTRADAY MARKET
COMMODITY FORWARD
INSTRUMENTS MARKET
FINANCIAL INSTRUMENTS
MARKET
PROPERTY RIGHTS
CO2 EMISSION RIGHTS
EXCHANGE TRADING
CERTIFICATES OF ORIGIN REGISTER
REGISTRY
GUARANTEES OF ORIGIN REGISTER
Fig. 11. TGE product portfolio Source: own development based on [3]
Day-Ahead Market (DAM)
The day-ahead market consists of ordinary bids and block bids. Quotation phases for
these bids are led two days (D-2) and a day (D-1) before the delivery day, however the
amounts and the prices for electricity of block contracts are set only in continuous
trading. On this market there are also electricity instruments called RDS and RDN
WEEKEND. The schedule for quotation is shown in figure 12.
31
DAM(hourly)
DAM(block)
7:00 15:008:00 9:00 10:00 11:00 12:00 13:00 14:00
D-2 CONTINOUS TRADING
CONTINOUS TRADING
FAPD-1
CONTINOUS TRADING
D-2
D-1
RDS
CONTINOUS TRADING
CONTINOUS TRADING
Fig. 12. Schedule for quotation on the day-ahead market Source: own development based on [3]
The ordinary orders running in the single-price trading system involve the hourly and
the RDS instruments. For hourly instruments at 10.30 a.m. fixing of prices for
consecutive hours of the delivery day occurs setting the fixing of The First Fixed Auction
Price (fixing I). Then from 10.35 a.m. till 11.30 a.m. the phase preceding fixed auction
price quotation for the RDS instruments holds. Later in the message of the exchange
the clearing price is specified (fixing II). Execution time for both instruments is a hour
of the day listed in the ID of the instrument. The RDS instruments depict the market
coupling mechanism based on the implicit auctions between TGE and Nordpool Spot
through the connections with Sweden and Lithuania (SwePol Link and LitPol Link
consecutively). The available trading volumes on these cross-border connections are
announced by TGE in consultation with PSE a day before delivery.
These fixed auctions lead to establish the market clearing price in uniform pricing. It
means that all accepted offers are fulfilled at the marginal price. On the exchange this
price is set to maximize the trading energy volumes or to minimize these volumes
differing in orders for buy and sell at a specified price. Ordinary orders take the form
of blocks with the defined volumes and prices. For each hour the participant can place
an order consisting of 25 blocks at the maximum price of 1,500 PLN (excluded the RDS
instruments from which the prices are from -500 EUR to 3,000 EUR). Orders for sell are
positioned descending while orders for buy ascending. When there are orders at the
same price, they are aggregated.
32
Fig. 13. The marginal pricing example Source: own development
In the above example the marginal price is 185 PLN/MWh and the total trading volume
amounts to 350 MWh (the intersection point of the supply and demand curves). This
price proves the market rule for pricing, because the difference between the sums of
the buy volumes (400 MWh) and the sell volumes (350 MWh) is minimum and equals
to 50 MWh. However there may be more than one price meeting the maximum trading
volumes. Then the price is set according to the detailed market regulations.
On the DAM its players can also submit the block orders, however they are quoted only
in the continuous trading system. Such a system applies for the hourly instruments as
well. The block bids allow their owners to operate more freely, because the orders may
be submitted for a specified number of hours.
The block orders are divided into two groups: the block instruments (BASE, PEAK,
OFFPEAK) and the RDN WEEKEND instruments. The specification for these instruments
is presented in table 2.
Table 2. The specification of the block instruments
Type Nominal value
[MWh] Execution time
BASE 23 – 25 0.00 – 24.00 on the delivery day
PEAK 15 7.00 a.m. – 10.00 p.m. on the delivery day
OFFPEAK 8 – 10 0.00 – 7.00 a.m. and 10.00 p.m. – 24.00 on the
delivery day
BASE WEEKEND 47 – 49 0.00 – 24.00 on Saturday and Sunday
33
PEAK WEEKEND 30 7.00 a.m. – 10.00 p.m. on Saturday and Sunday
OFFPEAK WEEKEND
17 – 19 0.00 – 7.00 a.m. and 10.00 p.m. – 24.00 on
Saturday and Sunday
The continuous trading system is characterised by the current execution of the orders
for sell and buy on the condition that their prices match. Each order may have also its
minimum or maximum price as a trigger limit and be then awaiting for a reverse order.
According to the market rules for queued orders, these ones for buy with the highest
price limit shall be executed firstly and reversely in case of the orders for sell. TGE gives
the minimum and maximum rates for each trading hour.
On this market there are different types of orders that may or may not participate in
the both systems (tab. 3).
Table 3. The types of orders on the day-ahead market
Type Duration System Switching between systems
when unrealised
Rest of day trading day from the
submission single-price continuous
yes, in both directions
Good until expiry
until the end of an instrument quotation
period
single-price continuous
yes, in both directions
Good until date until the date specified
during submission single-price continuous
yes, in both directions
Timed order trading day from the
submission single-price continuous
yes, in one direction from single-price to continuous
Call auction trading day for a specified auction
single-price no, it is deleted
Fill and kill until the end of the
first transaction continuous
no, it is deleted, but may be realised partly
Fill or kill until the end of the
first transaction continuous
no, it is deleted when is not realised fully
For analytical purposes the exchange presents actual values of the indices [PLN/MWh].
They indicate the average prices for all transactions within a specified time-scale. The
trade-weighted average prices involve the indices such as: IRDN, sIRDN and offIRDN.
The others are the arithmetic average of these prices: IRDN24, IRDN8.22, IRDN23. The
latest index on the power market – TGe24 is a reference instrument for the future
contracts on the financial instruments market. However TGeBase is the most
representative index on the DAM, because it takes into account all types of quotation
phases and systems. This index mirrors so the current condition of TGE and is a baseline
34
for other transactions outside the market.
Intraday market (IDM)
The intraday market functioning is similar to the previous market and let its players
manage their energy portfolio for better forecasting changes in real-time. Due to its
role, the IDM is a second component of the spot market with lower trading volume
than on the DAM. The intraday market is a hourly market relies on the continuous
trading system. The players can submit the same types of orders listed in table 3,
however instead of switching to another system, the specified orders may be
transferred to another trading session where the instrument is quoted.
The IDM quotation schedule involves a day before the delivery day from 11.30 a.m. till
3.30 p.m. and the delivery day from 8.00 a.m. till 3.30 p.m. In this case the difference
regards the submitting of the transactions. During trading on the D-1 the transactions
can be concluded for each hour of the delivery day, but trading on the same day as
physical delivery is limited to 12 hours from midday to midnight. However the
transactions are submitted to the TSO periodically every hour, thus the schedule
consists of 8 ranges from which there are the descending delivery periods. The first
range covers the hours from 12.00 a.m. till 24.00 and the following ones are shorter by
a hour. The last range regards so the period from 7.00 p.m. to 24.00.
TGE presents on its website the volume-weighted average prices for the transactions
on the trading session for consecutive hours.
Commodity Forward Instruments Market (CFIM)
The commodity forward instruments market features the largest trading volumes. It
offers the contracts with various delivery terms including weekly, monthly, quarterly
and annual ones. The execution of orders and transactions holds as on the DAM for
the block orders on the D-2, thus these transactions, when concluded are notified
together with others on the DAM unless the quotation is through concluding the OTC
(over the counter) deals. The CFIM operates so on working days from 8.00 a.m. to 2.00
p.m. based on the continuous trading system for the forward instruments: BASE, PEAK
and OFFPEAK. For each trading session the daily clearing price is calculated taking into
account the mean of last 10 transactions. Execution time for them is the same as in
35
table 2, but in the weekend and on non-business days the BASE and OFFPEAK
instruments run consecutively. In turn execution and quotation periods result from the
calendars of the forward instruments published by TGE.
The characteristic attribute for the forward instruments is the quotation in series. It
means these instruments comply the exchange standard, which for each forward
instrument determines the same underlying instrument at the rate from the DAM and
the expiration date. Consequently, there is a strong relationship between the prices
for the aforementioned instruments, however operating on the CFIM is more risky
than on the DAM due to the financial leverage effect. In general it relates to the value
change of the contributed collateral as a part of the forward instrument’s value when
the prices on the CFIM fluctuate significantly.
The forward contract may be concluded for the electricity delivery or on the RES
Property Rights. However the RES Property Rights on the forward market (called OZE)
are intended to execute both financially and physically, while the same rights on the
property rights market (called PMOZE generally) have only a financial nature.
Property Rights Market (PRM)
The property rights market, as suggested by the name, is a market for these rights,
which constitute a transferable commodity and result from the certificates of origin.
According to the Polish energy legislation, the certificates of origin are issued by the
ERO President for generation from RES, CHP (combined heat and power) plants, biogas
and for energy efficiency. They have colours assigned: green, yellow, violet and white
ones consecutively. Since 6 September 2016 on TGE there has been also the quotations
for the property rights from so-called blue certificates (the PMOZE-BIO index). The
contract names for particular property rights are shown in table 4.
Table 4. Contract names for particular property rights according to the source
Source for Certificates of Origin constituting the property rights
Contract name
Description
RES (green certificates)
PMOZE for the generation period until 28
February 2009
PMOZE_A for the generation period since 1
March 2009
agricultural biogas (blue certificates)
PMOZE-BIO only for electricity generated from
agricultural biogas since 1 July 2016
36
high-efficiency CHP plants (yellow certificates)
PMGM for gas-fired plants or plants with
<1 MW installed capacity
PMMET for methane-fired plants or gas-fired
plants from biomass
PMEC others
agricultural biogas (violet certificates)
PMBG only for biogas delivered to a gas
distribution network
energy efficiency (white certificates)
PMEF for all activities presented in the
Energy Efficiency Act
There may be two types of transactions for the property rights: the session and OTC
transactions. They are characterised by their indices for particular types of contracts
separately. In case of session transactions the property rights may be quoted under
the both systems that hold on Tuesdays and Thursdays. On the PRM there is no
limitation in price fluctuations, however in the fixed auction system the orders for buy
having their required collateral value must not exceed the defined transaction limit in
order to they can be executed. Likewise such a restriction regards the orders for sell,
but the rate is the total number of the property rights. When exceed the limit, they are
rejected.
The trading volumes and prices on the PRM are part a result of the regulations of the
Minister of Energy, where the compulsory purchase rates for the various certificates
of origin are defined. Moreover, since 1 July 2016 the tradable green certificates
system has been changed by the auction system, however the green certificates and
the property rights for them in consequence will obtain no longer than 31 December
2035 for the RES plants started functioning before 1 July 2016.
On the exchange market there are also the registers for the certificates of origin and
the guarantees of origin. Only the first allows to embrace the support mechanisms and
may be traded as the property rights. The guarantees of origin function as the
confirmation for end user that each portion of 1 MWh of electricity supplied to the
network originated from renewable energy source. On the other hand they may
generate extra revenue, because are transferable. However TGE is not a party to the
agreements.
Emission Allowance Market (EAM)
The product offered on the EAM is carbon dioxide emissions allowances as a result of
37
the EU climate policy. They enable their owners to emit an equivalent of a tonne of
CO2. The market functioning is related to the EU Emissions Trading System, currently
its third stage for the years 2013-2020 implemented to the Polish legislation on 9
September 2015. Despite the progressive transformation from the allowances
allocated free of charge to the auction system, Poland is being granted the free
emission allowances, provided that modernisation investments are given (the
derogation for the power sector). However the limit of these allowances will be
decreasing yearly and the companies conducting their activity in energy-intensive
sectors (obliged to source them) will be forced to purchase them on the EAM.
Consequently, the EAM is a secondary market for trading in allowances. There is also
a possibility to purchase the emission allowances over the counter markets as bilateral
contracts. The quotation on the exchange takes places exclusively under the
continuous trading system. There is one index for the volume-weighted average price
of all transactions – CO2PL. Because of the aforementioned situation, the transactions
are not concluded.
Financial instruments market (FIM)
The financial instruments market started its activity on 4 November 2015 offering the
futures products based on the TGe24 index from the DAM. TGe24 is defined as an
arithmetic average of the prices for all transactions concluded during the fixing I.
The futures product is a financial instrument, which lets conclude the derivative
transactions as a tool for hedging the electricity prices on the spot market. However
the hedging in this case means rather minimising losses instead of maximising profits.
It may be done by concluding the futures contracts at prices known currently to forgo
possible revenue, but simultaneously to protect against the price fluctuations averting
risk. Consequently, the player position on the FIM is a result of his current or future
position on the DAM. When the player is not going to participate in the DAM, his
activity on the FIM is speculative.
In trading there are the annual, quarterly and monthly contracts in four series (solely
the annual ones involve two consecutive calendar years) with different contract
notional volumes. The player, who buys an instrument, has a long position that remains
open until a reversed transaction is concluded. He operates on the FIM in hope of a
38
price rise for his instrument in order to he could sell the contracted electricity volume
on the DAM for a higher price. Conversely the seller operates. When he has a short
position and a price will be lower than a contracted one, he can close his position
buying the same volume cheaper and makes a profit.
The clearance of the open futures contracts is based on the mark-to-market rule. It
means that the price changes for the future contracts are settled daily after each
session at the so-called daily clearing price. In this case the future instrument seems to
be more flexible in management than the forward one that features a terminable
clearance. The annual and quarterly contracts before “delivery” are split into the
shorter ones of the same duration for the clearance (cascading). The monthly contract,
the whole or a part of the longer one is settled at the final clearing price (FCC) when
remains open on the last trading day. The FCC is the mean of all TGe24 indices during
execution period of a contract.
The market operates on working days from 8.00 a.m. till 2.00 p.m. under the
continuous trading system. However when the transaction exceeds the defined
dynamic variation limits, the balancing phase launches. This phase is similar to the
single-price trading system on other markets. Currently, the FIM is at its early stage.
Bilateral contracts
Bilateral contracts are an another form for the electricity trading depending on
concluding agreements among the market players directly. Such contracts shape the
so-called OTC market. All contract conditions (prices, energy volumes, duration) result
solely from the parties’ arrangement and they are not limited by any market rules
(however the prices often reflect the situation on the exchange). Bilateral contracts
like others are physically carried out by the TSO, but the parties settle their positions
between themselves regardless of settlements on the balancing market. They are
concluded in a long time-frame as annually, quarterly, monthly, but each of them
submitted to the TSO must have a form of the daily-hourly timesheet. Both in 2014
and 2015 these volumes on the OTC market were at a similar level and totalled almost
60 TWh [34].
Prices and volumes for such contracts may be fixed, but often change in time what
makes them similar to the current ones on the market. Both the seller and the buyer
39
want to avoid the electricity price fluctuation and then they can conclude the contract
for differences (CfD). Such a contract is divided into three types: one-side, two-side
and min-max contract according to the discrepancy settlement from the established
so-called strike price (fig. 14). The one-side contract involves compensation only for
the buyer, when the real price is higher than the appointed price. The two-side
contract is frequent than the previous one. Both sides compensate missing proceeds
to each other based on the current situation on the market. The last type regards two
strike prices: the lowest and the highest ones. The range between them is free of
compensation.
Fig. 14. Types of CfD contracts
Source: own development based on [14], [22]
40
Offers and bids on the market
Operating on the market to maximise the revenues of its players requires the adoption
of a proper strategy. When the orders to buy are not constrained by technical issues,
but depend on end-consumer behaviour on the retail market, the orders to sell must
fulfil all technical limitations of the generation units and the transmission system.
Consequently, the offers on the market are often made at the last moment before
closing the session, when the initial technical constraints of the system are already
known (the TSO publishes the Initial Daily Coordination Plan till 4.00 p.m. two days
before the delivery).
The producer who operates his generating unit (or the scheduling coordinator on his
behalf) is under obligation to contract enough energy volumes through bilateral
contracts or exchange transactions in order to his contract position for each hour could
be higher than the minimal power output of the unit. Then the timesheet elaboration
for the unit is possible and the TSO can develop further the daily and current daily
coordination plans (the DCP and the CDCP consecutively).
It seems that the producer should offer his first sell block (covered the minimal power)
at a low price to meet the marginal or clearing price (depending on the pricing system).
He will do it when he has no volumes from bilateral contracts or they are too small.
However, in the assumed situation he can offer the first block at a higher price counting
on the gain as the difference between the marginal price and his price when the block
is accepted (in uniform pricing). Otherwise, aware of the risk, he makes the upwards
offer on the balancing market forecasting significant demand for energy in the system.
When the unit achieved its minimum with bilateral contracts, the producer can shape
his offers according to the most profitable strategy offering the first block at a high
price.
In any case the prices for the exchange offer and the downward offer on the balancing
market are related to variable costs of the electricity production. In the pay-as-clear
auctions producers with winning offers can also cover their fixed costs by virtue of the
aforementioned gain (except for the last accepted offer for which the marginal price is
equal to the variable costs of its unit). On the other hand, in the pay-as-bid auctions
during continuous trading the player must provide in his offer for both variable and
fixed costs trying not to exceed, but to be close to the price of the last accepted offer
41
in the previous auction. There is also a possibility for the producer to cover his variable
costs on the balancing market through the accepted downward offer. The rest costs
may be covered from the concluded contracts.
3.3.2. Technical (regulated) market
Balancing market
The balancing market is a technical market closely related to the other segments of the
wholesale market. It enables the trading electricity volumes to be possible physically.
The TSO serves the main role on this market and is responsible for balancing supply
and demand in real time taking into account planning the operation of the National
Power System (NPS). He achieves this duty by balancing the corrective orders to sell
and buy.
Balancing on the market takes place among the TSO and market participants using
objects such as the physical measuring point (PMP), the electricity destination of the
balancing market (ED) and the scheduling unit (SU). The SU is a basic object on the
market with the defined contract position representing a collection of the EDs. Each
unit is settled based on the balance sheets in real time with metering of energy in the
PMPs. All units operate within the range of the transmission network and of the
distribution network with a voltage of 110 kV to which the CDGUs are connected.
However, there are also the so-called points “over the network” which set the virtual
places for energy flows among trading agents (business and scheduling coordinators).
The types of the scheduling units are listed in the TGC and the basic division involves
generating (apart for wind units) and receiving units, active (balancing) and passive
(not balancing) units. The generation units act a key role for the TSO within the scope
of the DCP and CDCP plans for distribution of loads. The TSO has also his own units for
balancing loses, cross-border exchange and external generation.
The settlement on the balancing market is complex. The price shaping depends mainly
on the strategy adopted by the active scheduling units and the forecasted working
conditions of the NPS making by the TSO. The market operators report to the TSO their
concluded sales agreements for the D trading day on the day-ahead balancing market
(from 9.00 a.m. till 1.00 p.m. on the D-1) or on the intraday balancing market (from
5.00 p.m. on D-1 till 9.00 p.m. on the D). Within the working hours of the day-ahead
42
balancing market, the active scheduling units can report their balancing offers, that are
later taken into account by the TSO to prepare the DCP, till 4.30 p.m. on the D-1. This
is possible to do by The Electricity Market Information Exchange System. The system
operator, having the plan for hourly demand in the NPS with chosen units, makes then
another plan – the CDCP that consists of 15 minutes periods of forecasted demand on
the delivery day. It may be updated regularly during the current system operation in
order to the working points of units could be accurately matched to demand changes
in the system. The platform for observing the system continuous functioning (with all
announcing operational accidents and availability alterations) is The Operative
Cooperation System with Power Stations. All balancing offers, verified and accepted by
the TSO, take part in distribution of loads within the mentioned plans.
In each hour of the trading day on the balancing market the active scheduling unit has
three contract positions: the declared (DCP), verified (VCP) and corrected (CCP) one.
They must be set to settle their volumes with the real electricity delivery (RED). When
they are negative, it means that energy is received from the market. Otherwise, energy
is delivered.
The DCP means the sum of all energy volumes derived from concluded sales
agreements reported both on the day-ahead and intraday balancing markets. After
verifying the agreements and the balancing offers (upwards and downward) by the
TSO, the scheduling unit has the VCP that comes from its technical capabilities. The
end position results from the plans for the NPS working. In selected cases the CCP may
be equal to the operative electricity volumes for delivery according to the last version
of the CDCP determined by network constraints.
The clearance in terms of value and quantity is divided into two pricing systems. The
balancing power, according to TGC, is defined as the unplanned and planned ones. The
unplanned balancing power regards the verified delivery volumes (ΔVDV = DCP - VCP)
and the real delivery volumes (ΔRDV = CCP - RED). This kind of power may be settled
at the clearing price of the DSP deviation. On the other hand, the planned balancing
power is interpreted as the corrected delivery volumes (ΔCDV = VCP - CCP). The market
player reckons with the TSO for these volumes at the clearing price of the corrected
contract position for each hour of the trading day. On the market there are also the
receiving scheduling units that operate actively in reducing loads at the TSO behest
43
being paid for it.
The balancing offers are necessary to relate the reported sales agreements with the
current technical conditions of the NPS. The active scheduling units are able to declare
up to 10 price sequences for each trading hour with the energy for reducing (R) and/or
increasing (I) their load. These sequences may be divided liberally, but the total
downward energy must be equal to the energy from the sales agreements. Then the
upwards energy stands for the difference between the maximum production
capabilities and the contract position of the unit. In figure 15 the possible relation
among them is shown.
SUR1 = 50 MWh
SUR2 = 70 MWh
POWER EXCHANGE= 100 MWh S5(R) = 60 MWh
SUR4 = 40 MWh
REMAINING= 105 MWh
CO
NTR
AC
T PO
SITI
ON
S1(R) = 90 MWh
S2(R) = 40 MWh
S3(R) = 70 MWh
S4(R) = 40 MWh
SUR3 = 70 MWh
S6(R) = 30 MWh
DO
WN
WA
RD
SEQ
UEN
CES
S8(I) = 20 MWh
S7(I) = 45 MWh
S9(I) = 20 MWhS10(I) = 20 MWh
UPWARDS SEQUENCES
SALES AGREEMENTS
BALANCING OFFERS
Fig. 15. Relation between balancing offers – example Source: own development based on [22]
The clearing price of the DSP deviation is a marginal price resulting from the
combination of the balancing offers making with the algorithm for distribution of loads
called the Linear Programming Dispatch (LPD). It is done for the flexible balanced CDCP
plan.
These offers belonging to the active scheduling units of the producers and the TSO are
positioned in ascending order. The intersection between the forecasted load level and
the pile determines the point under which the offers are approved for implementation.
The price of the last accepted offer indicates the clearing price of the DSP deviation.
44
This clearing price may differ depending on if the energy is delivered (the clearing price
of the DSP deviation for purchase) or received (the clearing price of the DSP deviation
for sale) by the unit. The aforementioned clearing prices remain at the same level,
because the balancing factor which distinguishes them is equal to 0 currently [28].
The clearing price of the corrected contract position is defined for the each accepted
sequence for given hour of the trading day. Its value depends on the interaction
between the VCP and the CCP for the generation and the TSO’s units separately.
The clearing processes are different for the active and passive units being on both sides
of the cooper plate. The passive unit (power recipients, passive producers, trading
companies) settles an account with the TSO only between its declared contract
position (DCP = VCP = CCP) and the real consumed power volumes. The power
exchange remains always balanced, thus it does not participate in the market. The
below diagrams present the clearance examples.
Bilateral contractsExchange
transactionsContracts with
trading companies
+
DCP
CDCP
Fixing of the clearing price of
the DSP deviationVCP
CDCP(flexible balanced)
CDCP(with system constraints)
DCP
CCP
+
-VCP
ΔVDV
+-CCP
ΔCDV
PMP
RED
+-RED
ΔRDV
The clearing price of the corrected contract position
x
Payments for CDV
x
Payments for VDV
x
Payments for RDV
The price for must-run
generation
Total payments for deviation
Fig. 16. Clearance scheme for the Active Generation Scheduling Unit Source: own development based on [22], [28]
45
Bilateral contractsExchange
transactionsContracts with
trading companies
+
DCP = VCP = CCP
PMPRED+-RED
ΔRDV
x
Payments for RDV(total payments
for deviation)
The clearing price of the DSP
deviation for sale
Fig. 17. Clearance scheme for the Passive Receiving Scheduling Unit Source: own development based on [22], [28]
The presented balancing market model in Poland may remain disadvantageous for the
TSO, when the market players are not encouraged to reveal their real demand
forecasts. It caused the difficulties in balancing at the earliest stage. Such a situation
results from the discrepancy between the balancing offers correlating for planning and
the clearance of the balancing power based on the real measurements. When the
player submits his bids departing from the forecasts, he is supposed to reveal his
contract position as close to the clearance, therefore he can take advantage of the
market surplus, what is more profitable for him. On the other hand the TSO makes a
mistake then in working out the plan, what it may cause uneconomic distribution of
loads.
Ancillary services
By ancillary services all control system services are meant that make the separate
market similar to the balancing market. This market is an auxiliary market to account
power produces for their control and emergency activities. They are crucial to make
concluding trading contracts freely. In the TGC there is the directory of services, which
allow the TSO to have a power reserve with different access time. This reserve may be
46
sourced in the system by automatic control systems or on the TSO demand. The
expenditures for the majority of ancillary services are covered by end-consumers as
part of the transmission fee.
The producer, who provides ancillary services, makes power deviations, therefore he
is responsible to reckon with the TSO on the balancing market for these deviations
from the contract position of his scheduling unit. Consequently, these two markets are
integrated with each other, however the balancing market functions in hourly periods,
while the market of ancillary services lets balance in the shorter time (minutes,
seconds). There is also the relationship between the clearing price of the DSP deviation
and the operational time of ancillary services, e.g. the interventional power reserve.
When such a service is activated, this price can be higher.
The TSO can balance the temporary values of energy flows in the system by the services
listed in table 5.
Table 5. Directory of services in NPS ([5], [28])
Providers of services Type of service
Active Generation Scheduling Units 1. Operational power reserve. 2. Participation in primary regulation. 3. Participation in secondary regulation. 4. Participation in automatic voltage and
reactive power regulation. 5. Working with underload. 6. Working with overload.
Old generation units intended to shut down until the end of 2017 or 2019 Controlled energy consumption (Demand Side Response – DSR)
Interventional power reserve
Non-centrally Dispatched Generation Units (nCDGUs)
Must-run generation
The Active Generation Scheduling Units provide control services by the balancing
market according to the technical requirements described in the TGC and the bilateral
transmission contracts.
The operational power reserve (OPR) is defined as the planning overcapacity, which
results from the flexible balanced CDCP plan. In other words, it means the available
generating capacity of the active units that is not used to produce power (it is free of
sales agreements on the wholesale market) and may be made of by the TSO during
47
peak demand from 7.00 a.m. to 10.00 p.m. on working days. According to the TGC
operational power reserve should be equal to 18% of the planned demand for energy
in the system (reduced by the intended use of the interventional power reserve). The
price for this reserve is determined in accordance with the undermentioned curve:
Price for OPR[PLN/MWh]
OPR[MWh]
Reference price for OPR
Curve:price = constans
Curve:price x power = constans
Required OPR0
Fig. 18. Establishing the operational power reserve price Source: own development based on [28]
According to figure 18, the price depends on the required OPR. When it is less than the
expected one, all bidders are paid the same price for providing overcapacity at a
specified hour. It may be represented by the demand curve with the required reserves
except peaks. During peak demand, there are fewer bidders available, hence others
remaining get lower prices, but multiplied by higher volumes. In this way the OPR costs
are independent from the amount of players keeping equal.
On the other hand the input in both the primary and secondary regulations is planned
by the TSO at the stage of creating the CDCP with system constraints. These services
involve the active unit’s working with the functional control system putting on at the
TSO request. It may be used as the second (primary) or the minute (secondary)
regulations. The aim for the regulation is keeping the balance between electricity
demand and supply in the entire synchronous area. It is done by the control systems
that stabilise the system frequency. The primary one operates in just several seconds
by turbine speed controllers as a result of the system disturbances. The secondary one
lasts longer from seconds to usually 15 minutes. It is activated in automatic frequency
and power control systems, when the TSO changes the control error signal. It modifies
the required active power of the unit and allows to restore the required system
48
frequency and the exchange power.
These services are good for the centralised power system which runs in Poland. PSE
chooses the power reserves taking into account their suitable levels in different system
locations. However it may limit the cross-system connections throughput when the
power flows controlling is not decentralised.
According to the TGC the input in the NPS of the primary regulation should amount to
±170 MW and the secondary regulation to about ±500 MW. These reserves are cleared
as the planned balancing power on the balancing market. The control power is not
booked from the concluded sales agreements and the price for delivering regulation
services constitutes 5% of the price for the must-run generation. This price should
compensate the costs resulting from the worse working conditions of the unit.
The another ancillary service is working with automatic voltage regulation in
generation nodes. It is planned and activated similar to the aforementioned
regulations in compliance with the current requirements of the NPS. Voltage
regulation may be done by changing reactive power flows, thus this service, as the only
one, is not related with balancing active power in the system. The clearance for voltage
regulation comes from bilateral contracts for transmission between the TSO and the
active units. It is calculated based on the operating costs of these control systems. All
three described regulations are compulsory for the each Active Generation Scheduling
Unit.
Working with underload means working under the technical minimum of the unit,
while working with overload is defined as working over the technical maximum of the
unit. Both cases lead the unit to work other than rated parameters which gives rise to
costs. Such a power, delivered or received from the market is always cleared as the
planned balancing power. The payments for this service are specified in bilateral
contracts for each unit and depend on the used power range in this mode.
The second group of the providers consists of these units that are the oldest, the least
effective or not meet the newest environmental requirements (The IED Directive valid
from 1 January 2016). They can deliver the service in the interventional generation
power being simultaneously outside the market. In this group there are also the active
recipients, who operate similar to the active producers on the balancing market,
however their role depends on submitting the balancing offers for reducing load. The
49
interventional power reserve (IPR) is analogous to the strategic reserve, which leads to
withdraw the chosen generation units from the market in order to they could be
activated at the TSO request from a cold start during lack of generation. In other words
such a reserve is used by the TSO in the emergency situations, when the electricity
price reaches almost its maximum value, the so-called Value of Lost Load (VoLL). This
service is sourced by the TSO under public procurement. The winning units conclude
the bilateral contracts with TSO then. The active interventional unit belongs to the TSO
on the balancing market.
Currently this service is testified by the appointed units of the powers stations in Dolna
Odra, Siersza and Stalowa Wola, giving a total of 830 MW reserve.
The interesting, relatively new idea is the Demand Side Response (DSR). The DSR is to
limit energy consumption by the recipient voluntarily and actively according to the
current system need. The TSO can take advantage of the DSR, when the clearing prices
of the DSP deviation are high, what means the low power reserves of the CDGUs. On
the other hand, the recipient finds this service attractive when it is profitable. The DSR
programs are generally divided into two groups: price-based programs and incentive-
based programs.
The price-based programs may be remarkable for retail sellers who prefer decreasing
the energy consumption by their customers during price peaks on the market to paying
extra money for the most expensive energy. Otherwise, a retail seller is subjected to
greater risk related to the wholesale prices fluctuations against the long-term
regulated prices incident to the contracts with end-consumers. As the example is the
tariff with very high prices in certain periods of time. The consumer, informed by the
seller earlier about such critical hours, is able then to reduce his demand what let him
be granted. These prices can be implemented dynamically depending on the prices on
the day-ahead market. In the future, such relationships on the retail market may be
advantageous also for the TSO. The program, working effectively, may allow to make
the demand curve more plane.
The incentive-based programs are connected with the Active Receiving Scheduling
Units on the balancing market. The incentive to participate on this market is a profit
from the accepted offers for reducing load (so-called demand bidding programs).
These programs allow the TSO primarily to reduce maximum peak demand when other
50
methods for balancing are difficult to implement.
The DSR service cannot develop fully without smart metering and the changes in the
current market model based on the cooper plate. The demand side is getting a market
player, who should respond to the right price signals on the market. However the
cooper plate model does not encourage to activate the DSR in different locations of
the country, because the implemented price mechanism applies the homogenous
clearing price of the DSP deviation. Consequently, the financial benefits of the
recipients are averaged. What is more, the active recipients act merely the planning
role, therefore they do not participate in modelling system constraints. It seems to be
worth implementing the nodal pricing building on the security-constrained unit
commitment and economic dispatch (SCUC, SCED). It may be helpful for the local
development of the DSR.
The last ancillary service is must-run generation refers to the uncontrolled generation
units (nCDGUs). The unit, bounded by the contract with the TSO, may be forced to
work when the system safety threatens to collapse. The CDGUs were also contracted
for this service, but now they clear fully from their contract positions on the balancing
market.
3.4. Cross-border trading in the perspective of the single market for electricity in the EU
Poland, implementing the European idea for the integration of electricity trading
across country borders, has active cross-border connections at high voltages with the
selected countries (fig. 19).
51
Fig. 19. Cross-border connections of the NPS Source: own development based on [31]
The cross-border trading when sufficient transmission capacity is available may be a
way for ensuring high competiveness among sellers, which should equalize the prices
on adjacent markets. The EU elaborates the so-called network codes to adopt market
rules of power exchanges to the concept of a common market. A key role in shaping
such a market is Regulation 1222/2015 of 24 July 2015 called Capacity Allocation and
Congestion Management (CACM). It assumes to inculcate the pan-European day-
ahead market based on the single price market coupling mechanism. To allocate
capacity in a coordinated manner, power exchanges are divided into several market
regions. Poland was allocated to the Central Eastern Europe (CEE) region that involves
territorially also: Germany, Austria, the Czech Republic, Hungary, Slovenia, Slovakia,
Croatia and Romania. However this division is only conventional, because Poland runs
auctions both by its northern connections (Sweden, Lithuania) and its southwesterly
ones (Germany, the Czech Republic, Slovakia). Trading with Ukraine is based on the
monthly explicit auctions. Since 13 November 2015 Poland has been assigned to the
other regions: Hansa as the part of Northern Europe and Baltic as the territories of the
Baltic countries.
The daily cross-border transmission capacity among Poland, Sweden and Lithuania is
allocated implicitly through energy transactions on the power exchanges of these
52
countries as a part of the Multi-Regional Coupling (MRC) project followed by the EU.
The economic principle of market coupling using implicit auctions is exporting
electricity from the market with lower prices to the market where it costs more
expensive. In this case the trading session involves the both connections SwePol and
LitPol collaterally. Since Sweden is connected with Lithuania by a submarine power
cable called NorBalt (700 MW), there may be an additional power transit between
them. There are two cases possible depending on the available transfer capacity (ATC)
amounts (figures 20, 21).
Fig. 20. Market coupling with price convergence Source: [2]
The first case results price convergence on two markets when ATC is large enough.
Market A features the lower price than market B has got, therefore some energy is
exported to market B. Consequently, the price on market A will increase (the purchase
curve shifts to the right), while market B gains more energy and the price will decrease.
When both markets are equalized, power flows stop.
Fig. 21. Market coupling with price difference Source: [2]
53
On the other hand, a connection between markets may be congested. Despite the
same working principle, the price difference occurs due to technical constraints.
As it is seen in the above pictures market coupling is a mechanism based on the single-
price trading system to match the lowest sales offers and the highest purchase bids
after aggregation according to the merit order principle. Consequently, there is a
relationship between the market coupling fixed price and the export volume defined
by the Net Export Curve (NEC). An export always causes an increase in the market
clearing price when considered as a market bid. The NEC is a curve that results from
the clearance (fig. 22).
Fig. 22. Net Export Curve Source: [2]
Market coupling based on implicit auctions remains effective until ATC appears.
Because the clearance results from the intersection of aggregated curves from
different exchanges, the question is how to optimize this problem. The objection
function is always the difference between the values of the accepted orders for buy
and sell that should go to maximum. On the other hand, the TSO decides the network
conditions in different plans distributing the loads, thus the matter is to forecast which
sell offers will be accepted at a particular trading hour to maximize social welfare
taking into account load flow network constraints.
Even though implicit auctions are favourable to the MRC project, explicit auctions exist
in the CEE region where Poland is (fig. 23).
54
Fig. 23. The CEE region with the TSO names Source: [20]
All explicit auctions in this region and others are taken by Joint Allocation Office S.A. In
such auctions the players trade the requested and allocated capacity separately on the
involved markets. The flow direction (source – sink) must be determined. There are
four types of auctions: annual, monthly, daily and intraday ones. The auctions with
shorter duration may be more attractive, when long-term auctions are limited by
reductions in ATC. Trading on the spot market requires the high sill for accurate price
forecasting, because sessions last mostly before the prices are fixed on a foreign
market. The players in Poland, due to the geographical location of the country, can
trade in explicit auctions on the markets in Germany (EEX), the Czech Republic (OTE)
and Slovakia (OKTE). According to the TGC all concluded explicit contracts must be
reported to the TSO as the cross-border exchange timesheets. On the cooper plate
power flows derived from such contracts are assigned to the cross-border exchange
scheduling units. They can belong to the TSO or to the market player, but do not take
part in balancing.
The main aspect for implementing the pan-European electricity market is a proper
coordination of cross-border trading taking into account limitations in connections. It
is necessary to prevent unplanned (loop) flows, when cross-border commercial
schedules do not meet physical flows. Consequently, these unallocated flows can
55
disturb other market segments, not participating in transactions. Since the majority of
Europe operates synchronously as the common transmission grid under UCTE, this
phenomenon has a huge impact on its safety. It may be dangerous, when trading in
some regions can reflect transit or equalizing flows in others. They often force the TSO
to increase safety margin and limit ATC. Nowadays, cross-border trading is subject to
loop flows due to dynamic generating units like renewables-based power plants. The
example is cross-border exchange between Germany and Austria in the CEE region.
These countries together with Luxemburg create a single market (DE/AT/LU), where
trading is free of transmission constraints in the neighbouring countries. Because of
that and the transmission network developed incompletely in northern Germany,
unplanned flows appear on the border with Poland and the Czech Republic including
Slovakia and Hungary, when Germany sends significant electricity volumes from
renewables-based power plants to Austria (fig. 24).
Fig. 24. Visualization of unplanned flows in the CEE region Source: [6]
According to [6] trading in the DE-AT market area conforms to about 28% of all
commercial transactions being concluded in the CEE region. This value is definitely the
largest among other cross-border connections, hence it may have a negative impact
on the neighbouring countries, when these transactions are scheduled outside the
allocation procedure. The four transmission operators from the CEE region noted the
highest volume of unplanned flows on the DE-PL border with the record equals to more
than 2,700 MW. The volume passing through Poland is on average approximately
56
1,300 MW, when the DE-AT commercial exchange transactions exceed 3,000 MW.
Such a situation was observed in about one fifth of hours in the specified periods.
Consequently, it limits the power exchange among Poland and both Germany and the
Czech Republic. Considering the DE-PL border, Poland is not able to export power to
Germany physically, because such realised schedules usually stand for unplanned flows
in the opposite direction (fig. 25).
Fig. 25. Unplanned flows on the DE-PL border against realised schedules and measured load flows
Source: [6]
PSE together with 50Hertz has started to exploit a phase-shifter since April 2016 on the
Mikułowa – Hagenwerder connection to control the power flows. Simultaneously the
northern connection (Krajnik – Vierraden) was shut down until 2018 to increase the
operating voltage from 220 to 380 kV. There is also a concept to install a phase-shifter
in Vierraden. Both investments are to improve allocation capabilities on the border. It
can be assumed that Poland will reach its export capacity at 500 MW, when import
capacity will be at 1,500 MW in 2018 [10]. Another option is so-called cross-border
redispatching (CBR). It depends on the bilateral electricity exchange in an opposite
direction than power really flows. Such a mechanism functions on the balancing
market as the unplanned balancing power. It may lead to an increase in the prices,
when peak units must run. Since cross-border redispatching is irregular, there is a risk
57
of price fluctuation. CBR may be supported by multilateral remedial action – MRA.
When Poland is not able to provide enough capacity to be transmitted to Germany,
other European countries can increase their generation determining power flows.
However MRA is less effective than CBR and requires these countries to generate many
more electricity than Germany must decrease to limit unplanned flows.
However unplanned flows, even though they may be partly steered by the special
transformers, result mainly from the bidding zones’ configuration based on the ATC
Market Coupling (ATC MC). This method is based on the algorithm for allocating
transmission capabilities to maximize them between neighbouring market areas in a
region taking into account forecasted power exchanges via other cross-border
connections. However commercial flows remain independent from physical ones,
hence electricity is transmitted on many commercial flow-paths. This discrepancy may
lead to uncontrolled flows beyond schedules like on the DE-PL border.
The alternative method for ATC MC is the Flow-Based Allocation Market Coupling (FBA
MC). As suggested by the name, it allows to convert commercial transactions into
physical flows in connected areas so as to make trading possible in each corner of a
region, but in accordance with technical constraints. It is done by the so-called Power
Transfer Distribution Factors (PTDF), which compose a matrix to correlate a trade
balance with power loads of critical branches of the systems belonging to operators
participating in bidding. The system element is critical, when is sensitive to any
disruptions connected with changes in power flows (cross-border connections, but also
interior transmission grids including transformers).
Consequently, the second method leads to equalize commercial and physical flows
eliminating unplanned flows. It seems to be very sound in theory, but requires the
ACER (the coordinator for energy regulators in the EU) to define such bidding zones,
that are neutral for markets’ liquidity in each country. It might be difficult to do
because of the cooper plate model insensitive to the dynamic generation from RES. In
case of Poland, the solution might be the split of the DE/AT/LU market into individual
national markets under the FBA MC. However it may cause an increase in the
wholesale prices in Austria, when power volumes are limited. On the other hand,
Germany will encounter some difficulties with the overproduction from RES, that can
lead even to negative prices (when sellers pay extra money to get rid of the unbalanced
58
energy).
Both methods are compared on the diagrams in figure 26.
Fig. 26. ATC and FBA Market Coupling methods – comparison Source: [31]
Cross-border trading is a way to increase short-term security of electricity supply, but
it leads to equalised wholesale prices that tend to decrease. This means that only
generators with low variable costs (water, wind, solar, nuclear power plants) may be
competitive on the international front. Poland, as the country where prices are mainly
determined by coal power plants, will be forced to import energy being fully
dependent on interconnectors (not only in case of emergency situations). The question
is if the Polish government should shelter the domestic power plants burning coal,
biomass and gas against being out of the market by limiting cross-border capacity or
work on the flexibility of existing conventional power plants working shorter, but for
higher revenue during peak demand, when renewables-based ones are insufficient or
switched-off.
On the other hand there is observed a strong impact of cheap energy from Scandinavia
produced primarily in water and nuclear power plants, that decreases prices in Poland
when cross-border connections are not congested. It is the most noticeable in the night
valleys, when the demand is the smallest. Then a part of conventional power plants
59
are the most probable to be withdrawn from the market (fig. 27).
PLN/MWh
MW
must-run generation
must-run generation
RES
RES
MW
DEMAND
Lower price during times of high input from renewables
Higher price during times of low input from renewables
Fig. 27. Change in the market price by increase in generation from renewables
Source: own development based on [8]
3.5. Capacity market
Even though Poland develops ancillary services to keep generating capacity at a safe
level, the problem of missing capacity (and missing money consequently) seems to
arise. Since the electricity market is found to be competitive, there is a permanent
oversupply on the market excluding the year 2015, when the TSO implemented the
supply steps in August (the compulsory reduction in energy consumption). In addition,
the total maximum capacity in the NPS crossed a historical milestone equals to 40 GW
in the second quarter of 2016. However, it is mainly for the uncontrolled power plants
with the dynamic output pattern, therefore uncertain to work during peak demand.
On the other hand, conventional power plants are losing market share in the energy
mix due to their age (47% of total is more than 30 years old and other 17% is over 25
years old) and ineffectiveness in meeting the newest environmental standards (BAT
conclusions). According to [26] assuming both the modernization and phasing-out
60
scenarios, it will be the necessity to withdraw generation capacity from 3 to 6.6 GW in
2020 included current and future investments of 5.8 GW total power capacity.
Coal-fired power plants are exposed to be withdrawn from the merit order pricing
system during fixings on the wholesale market, when RES installations produce
electricity at almost zero variable cost moving the equilibrium point into lower prices.
Assuming a hard coal-fired power plant with average active efficiency of 36.4% and
working for the most of the time in a year, its total generation cost is 130 PLN/MWh,
with more than three quarters of variable cost. The less time such a power plant works,
the higher is fixed cost for its operation. It means that these plants should work, when
it is profitable during peak demand, on the balancing market or as a reserve. On the
other hand, they must run, when demand is high and interconnections are congested
or RES plants remain insufficient. Hence they may operate as the operational power
reserve to cover their average fixed cost (the reference price was 41.20 PLN/MWh in
2016) or be fully shut down and work from a cold reserve for only intervention (PSE is
paying about 24 PLN/MW in disposal). Even though coal-fired power plants can earn
delivering ancillary services, they are partly exploited and should be replaced by new
ones. However new investments in the conventional power sector is capital-intensive
with high interest and risk-benefit balance. According to [7] they need to sell electricity
at 260 – 320 PLN/MWh to be worth an investment. But this price is actual only for the
small-scale RES installations designed in the auction system. Even contracts for base
delivery for the years 2017 – 2019 are at the level of 160 PLN/MWh. The longer
contracting does not appear in Poland.
In such a situation it seems worth implementing a market mechanism to provide clear
price signals for renovations and investments in the power sector. However the
question is if all current mechanisms have been considered on the energy only market
to ensure optimal capacity in the system. In a pure energy only market it can be
achieved only by the interaction between available capacity and demand, where there
are no payments for capacity. From the supply-side, the incentive to be on the market
or to invest in new capacity results from scarcity prices, when the prices rocket up to
the VoLL. But it often meets with the political unacceptability for extreme prices for a
long time. The solution may be to introduce Capacity Remuneration Mechanisms
(CRM), when the market is adequate to or to implement the second market – a
61
capacity market.
Capacity Remuneration Mechanisms
Volume based Price based
Targeted Market-wide
Strategic reserve
Capacity obligation
Capacity auction
Reliability option
Capacity payment
Fig. 28. Taxonomy of Capacity Remuneration Mechanisms Source: own development based on [1], [15]
The strategic reserve is closely similar to the interventional power reserve. The
capacity is determined aside the market by an independent body, e.g. a TSO based on
prices on the regulated markets to guarantee security in special circumstances.
Generators offering such a reserve are paid to keep their capacity good to go. The costs
are passed on end-consumers.
Capacity obligations are established for large consumers and suppliers, whose self-
assessed future consumption or supply duties are expected to be higher than the
capacity, set by a reserve margin. Then they must contract such a capacity in case of
shortages purchasing tradable capacity certificates, e.g. on the property rights market
or even on the OTC market, or making direct agreements with generators/consumers.
Otherwise they may be fined.
The another option of the CRM is the forward auction. It is based on offers for capacity
in several consecutive years. After fixing, all successful participants in the auction are
paid for future delivery. Such a system when developed may reshape into a capacity
market, where energy and capacity are contracted separately.
The reliability options (RO) operate as the one-side contracts for differences being risk-
hedging instruments like capacity obligations. Conversely than on the energy only
market, scarcity prices are disadvantageous for contracted capacity providers, because
when they are higher than a pre-set administratively reference price (the strike price
in the CfD), the provider must pay the RO fee gaining no profit from the market. The
second party of the RO – the recipient can purchase electricity at the level of the strike
62
price, because it is always good for him due to reimbursing the negative difference.
The RO are purely financial or can force the issuer, not only to make the payment, but
also to ensure available volumes, when the option is run.
The price-based CRM represents fixed prices for delivering additional capacity. Such
capacity payments may be identified as the operational power reserve. In this case
generators are paid according to their offered quantities to meet the planned reserve
margin.
On the other hand, there is a design for passing from the energy only market to the
commodity markets of energy and capacity. There is the differentiation between
centralised and decentralised capacity markets, while foregoing regulations for
electricity trading remain unchanged. [14]
The centralised capacity market, on the French example, relies on the capacity
certificates payments (capacity obligations). The market is an interface between a
power exchange and electricity retail suppliers, who together with end-consumers are
responsible for the capacity procurement as the obliged parties. They can derive
capacity services from the market, where capacity is traded in the shape of certificates
among the privileged parties. The certificates are defined as the capacity offers of
generators and active consumers (DSR). When successful transferred, they become the
property rights registered on the power exchange. The property rights allow their
delivers to receive the payments. Consequently, these certificates have a financial
nature being transferable from the wholesale to the retail segments under the
supervision of an independent body (TSO, DSO).
However in Poland there is a project under inter-ministry consultations of 4 July 2016
for implementing the centralised capacity market based on the forward capacity
auctions. Such a design was modelled on the British experience. In the UK the applied
mechanism turned out beneficial for the power sector with respect to the stand-still
clause (the European Commission did not dispute that market as not allowed state
aid). In theory, in this model the TSO is the only body for buying capacity. Hence he
announces the periodic capacity auctions to gain capacity in accordance with the
specified market rules. Further he delivers capacity services to retailers and
consumers, that result mostly from regulated tariffs (fig. 29).
63
Fig. 29. Scheme of centralised capacity market Source: [11]
The capacity market proposed by the Ministry of Energy [23] is going to be a
commodity forward market divided into the primary and the secondary markets. On
the market there are only the Physical Entities of at least 2 MW gross total maximum
capacity, that passed the certification process positively. After that, each entity
becomes the Capacity Market Entity privileged to take part in the primary market.
Because this market is composed of main auctions and additional auctions, the
capacity entity becomes the Certified Capacity Market Entity (CCME) depending on the
auction to be a certified player. It is worth emphasizing that a player may be the entity
planned for construction or refurbishment, but non-participating in the other support
mechanisms (including DSR).
There are the two types of auctions on the primary market. The first auction holds in
the fourth quarter in the Y-4 year, i.e. four years before the delivery year (the main
auction). The second (additional) one is closer to the delivery year, in the first quarter
a year before and concerns the quarterly supply. The secondary market operates as
the OTC market, where winning entities are able to trade capacity obligations, when
they suffer from lack of power. The whole market is predicted to last at least 10 years,
but 2 years before the last main auction the Minister of Energy will decide if it should
operate longer.
The auctions are being conducted in the pay-as-clear system in the form of consecutive
rounds until supply fully covers demand with the ex post clearance. The main auction
process is shown in figure 30.
64
Price [PLN/MWh/year]
Maximum capacity price
Power [GW]
Total bidding volume
Round 1
Round 2
Round m
Last round – offered volume is lower than demand
Forecasted demand
Fig. 30. Block diagram for main auction process Source: own development based on [23]
The starting point for auctioning is the demand curve in a function of price. On the
curve there is a point for forecasted demand (available power) defined by the TSO. It
is related to a peak power for a specified period determined by a requirement reserve
margin and others. As in figure 30, there is the maximum price for capacity, when
bidding volume is lower than demand and the minimum price (equals to 0) for the
opposite case. The process is conducted in the form of a Dutch auction, i.e. auctions
with decreasing prices. Each round starts with its opening price for which the
auctioneer declares his available capacity volumes. Because the only buyer is the TSO,
he finishes the process in the round m at the clearing price responding to forecasted
demand. The clearing price is set based on exit offers listed in ascending order. The
exit offer means the minimum price for capacity obligation offering by the entity
leaving a round (but not exceeding the opening price for the next round).
65
CASE A: Supply Curve Bottom Point lies on demand curve
CASE B: Supply Curve Bottom Point does not lie on demand curve and extra capacity volume is lower than extra cost
CASE C: Supply Curve Bottom Point does not lie on demand curve and extra capacity volume is higher than extra cost
Demand curveExit offers ranking in the last round
Demand curveExit offers ranking in the last round
Demand curveExit offers ranking in the last round
Extra capacity
Extra cost
Extra capacity
Extra cost
Price [PLN/MWh/year]
Round m’s opening price
Clearing price
Round m+1’s opening price
Supply Curve Bottom Point
Contracted capacity volume Power [GW]
Price [PLN/MWh/year]
Round m’s opening price
Clearing price
Round m+1’s opening price
Price [PLN/MWh/year]
Round m’s opening price
Clearing price
Round m+1’s opening price
Contracted capacity volume Power [GW]
Power [GW]Contracted capacity volume
Supply Curve Bottom Point
Supply Curve Top Point
Supply Curve Bottom Point
Supply Curve Top Point
Price [PLN/MWh/year]
Round m’s opening price
Clearing price
Round m+1’s opening price
Fig. 31. Block diagram for main auction process Source: own development based on [23]
The method for clearance is the net benefit algorithm. It depends on defining two
points for the highest and the lowest exit prices, the Supply Curve Bottom Point under
66
or on the demand curve and the Supply Curve Top Point above the demand curve
respectively. Because the capacity volume is indivisible, the situation when the bottom
point is on the curve happens rarely. Consequently, there are 3 cases possible (fig. 29).
The TSO buys additional capacity only when extra capacity volume is higher than extra
cost for it (as respective surface area values).
Currently a capacity market in Poland is proposed to be. The obvious advantage of such
mechanism is the possibility for reducing peak demand, when end-consumers are
obliged to pay a capacity fee at a price depending on hourly consumption. It should
also improve consumption management by developing the DSR services, particularly
in the peak hours. In a positive scenario, after an increase in the prices at the beginning
of the market operation, the risk and investment costs can be cut. It will be easier and
cheaper to meet power margin by the TSO, when the first capacity transactions are
concluded. However opponents claim that such market will result in the collapse in the
competition, when the bidding entities are ineffective coal power plants in large part.
In a negative scenario, it may lead to the vanilla market effect. The effect relates to
equal remuneration for all types of generators, when they are not divided into energy
mixes with different opening prices. Although missing capacity problem is resolved,
low-carbon technologies can suffer from underinvestment conceding conventional
ones.
The another issue is the position of Poland in the perspective of the pan-European
market. Because the energy mix is coal-dominated, the majority of the Polish power
plants will operate as peak units to meet the European energy need during peak
demand periods. In general it is disadvantageous to the country, when there is a strong
dependency from cross-border connections and pricing policy on foreign markets.
However immediate investments in the power sector must be launched, because
balancing problems may arise. The capacity mechanisms could be an incentive for sure.
4. FACTORS AFFECTING ELECTRICITY PRICES
The Polish electricity prices are dependent on many factors, which have both national
and international matter. This is direct related to the European legal regulations being
completed by the domestic law. In this chapter the power sector is shown with special
reference to the current energy mix. Its structure determines other derivative costs
67
that cause price fluctuations on the markets.
4.1. Power generating capacity
The Polish power sector is mainly based on fossil fuels with total maximum capacity in
domestic power plants of 39,777 MW (31.12.2015 status).
Fig. 32. Structures of maximum capacity and electricity production in 2015 Source: own development based on [38], [29]
The highest share belongs to the CDGUs, which are dispatched by the TSO. They
represented about 25,141 MW (63.2% of total) in 2015 (the rest is recognized as
68
capacity in the nCDGUs). It is also reflected in the structure of the electricity
production. Coal-fired utility power plants produced 135,447 TWh in 2015 being
responsible for 83.73% of production.
Table 6. List of Centrally Dispatched Generation Units (22.09.2016 status) [13], [27]
Location / Plant name
Owner Generating
units Maximum capacity
Voltage Fuel Notes
Adamów ZE PAK S.A. 5 x 120 MW 600 MW 110 kV lignite planned switch-off from 2018
Bełchatów PGE GiEK S.A.
2 x 370 MW, 1 x 358 MW, 3 x 380 MW, 1 x 394 MW, 5 x 390 MW, 1 x 858 MW
5,440 MW 220, 400 kV
lignite
planned switch-off of 2 x 370 MW from 2017 and 2018 respectively
Dolna Odra PGE GiEK S.A. 3 x 222 MW, 3 x 232 MW
1,362 MW 110, 220, 400 kV
hard coal
Dychów PGE EO S.A. 2 x 28 MW, 1 x 29 MW
85 MW 110 kV hydro
Jaworzno 3 TAURON Wytwarzanie S.A.
5 x 225 MW, 1 x 220 MW
1,345 MW 110, 220 kV
hard coal
Karolin 2
VEOLIA Energia Poznań ZEC S.A.
1 x 112 MW 112 MW 110 kV hard coal
Kozienice 1 ENEA Wytwarzanie S.A.
3 x 225 MW, 3 x 228 MW, 1 x 215 MW, 1 x 230 MW
1,805 MW 110, 220 kV
hard coal
Kozienice 2 ENEA Wytwarzanie S.A.
2 x 560 MW, 1 x 1,075 MW
1,120 MW 400 kV hard coal
planned switch-on of 1 x 1,075 MW from 2017
Łagisza TAURON Wytwarzanie S.A.
3 x 120 MW, 1 x 460 MW
820 MW 110, 220, 400 kV
hard coal
planned switch-off of 1 x 120 MW from 2016 (delayed)
Łaziska 2 TAURON Wytwarzanie S.A.
2 x 125 MW 250 MW 110 kV hard coal
planned switch-off from 2017
Łaziska 3 TAURON Wytwarzanie S.A.
1 x 230 MW, 3 x 225 MW
905 MW 110, 220 kV
hard coal
Opole PGE GiEK S.A.
1 x 386 MW, 2 x 383 MW, 1 x 380 MW, 1 x 900 MW
1,532 MW 110, 400 kV
hard coal
planned switch-on of 1 x 900 MW from 2018
Ostrołęka B ENERGA Elektrownie Ostrołęka S.A.
1 x 226 MW, 2 x 221 MW, 1 x 230 MW
677 MW 110, 220 kV
hard coal
69
Pątnów 1 ZE PAK S.A. 2 x 222 MW, 4 x 200 MW
1,244 MW 110, 220 kV
lignite
Pątnów 2 ZE PAK S.A. 1 x 464 MW 464 MW 400 kV lignite
Płock PKN Orlen S.A.
1 x 600 MW 600 MW 400 kV natural gas
planned switch-on from 04.2017
Połaniec ENGIE Energia Polska S.A.
2 x 225 MW, 4 x 242 MW, 1 x 239 MW
1.657 MW 110, 220, 400 kV
hard coal
Porąbka Żar PGE EO S.A. 4 x 135 MW 540 MW 220 kV hydro
Rybnik EDF Polska S.A.
6 x 225 MW, 2 x 215 MW
1,780 MW 110, 220, 400 kV
hard coal
for sale
Siersza TAURON Wytwarzanie S.A.
2 x 153 MW, 1 x 123 MW, 1 x 128 MW, 1 x 120 MW
677 MW 110, 220 kV
hard coal
planned switch-off of 1 x 120 MW from 2016 (delayed)
Solina PGE EO S.A. 2 x 68 MW, 2 x 31 MW
198 MW 110 kV hydro
Stalowa Wola 3
TAURON Wytwarzanie S.A.
2 x 125 MW 250 MW 110 kV hard coal
planned switch-off of 1 x 125 MW from 2017
EC Stalowa Wola
TAURON Wytwarzanie S.A.
1 x 467 MW 467 MW 220 kV natural gas
planned switch-on from 07.2016 (delayed)
Turów PGE GiEK S.A. 3 x 235 MW, 3 x 261 MW
1,488 MW 110, 220 kV
lignite
EC Włocławek
PKN Orlen S.A.
1 x 491 MW 491 MW 220 kV natural gas
planned switch-on from 03.2016 (delayed)
Żarnowiec PGE EO S.A. 4 x 179 MW 716 MW 400 kV hydro
Żydowo ENERGA Wytwarzanie S.A.
1 x 52 MW, 1 x 51 MW, 1 x 54 MW
157 MW 110 kV hydro
Abbreviations: ZE PAK S.A.: Zespół Elektrowni Pątnów-Adamów-Konin S.A.; PGE GiEK S.A.: PGE Górnictwo i Energetyka Konwencjonalna S.A.; PGE EO S.A.: PGE Energia Odnawialna S.A.
As it is shown in table 6 there are currently five investments in new capacity with a
total of 3,533 MW (in bold). The attention should be given to two construction of the
gas-fired power plants in Płock and Włocławek (CHP plants) conducted by PKN Orlen
S.A., who has not participated in the generation sub-sector by now. In 2015 PGE S.A.
was a leader in this sector delivering 37.3% of total electricity into the network, while
the second group – TAURON Polska Energia S.A. was responsible for more than one
tenth of the sub-sector. A little less share fell the third ENEA S.A. [38]
Next to the aforementioned building there are a few prospective projects for new coal-
fired power plants [38]:
1 x 1,000 MW (Ostrołęka C), co-investment of ENERGA S.A. and ENEA S.A., the cost
70
of 6 billion PLN;
1 x 300 or 1 x 500 MW (Łęczna), co-investment of ENEA S.A. and Lubelski Węgiel
Bogdanka S.A., the cost of 3 billion PLN, coal gasification technology;
1 x 900 MW (Czeczott), co-investment of state-owned companies and a foreign
partner, the cost of 5 billion PLN;
1 x 900 MW (Rybnik), co-investment of state-owned companies (if they buy the EDF
Polska S.A. assets), the cost of 5 billion PLN.
PGE is running also a coal gasification project in Dolna Odra, however no details are
given.
Taking all generators into consideration they would prefer the power exchange for
selling electricity, but often conclude contracts with trading companies as well.
According to [38] the exchange had 47% of share of the total sales of producers, while
trading companies purchased 41% of total electricity from them in 2015.
Fig. 33. Impact of capacity shortages for prices on the markets on 2015-08-11 Source: [27], [33]
Generating capacity should always be available in sufficient quantities to make the NPS
working safe and properly balanced. However when it is not technically possible, the
TSO may be forced to announce the mandatory reduction of energy consumption to
meet a particularly high peak demand. This case has taken place on the 11th of August
2015 from 10 a.m., because significant unplanned shortages occurred in the morning
71
that day and a day earlier. The total shortages were over 4,000 MW with a few units
of the CDGUs switched off including Pątnów 2 (464 MW), Siersza (123 MW), Łagisza
(120 MW), Turów (235 MW), Jaworzno 3 (225 MW), Opole (200 MW), Kozieniece 1
(225 MW), Rybnik (220 MW) and others (see table 6). The largest unit in the country
(a 858 MW unit in Bełchatów) was also shut down. This amount with low wind
generation and high temperatures reflected in prices on the day-ahead market. The
prices soared for the selected hours to over 1,000 PLN/MWh (fig. 33) – some of market
participants, uncertain of demand, decided to buy more energy. However the TSO’s
fiat turned out successful, because prices on the balancing market were quite low.
Otherwise they may reach their maximum.
Fig. 34. Electricity infrastructure and main CDGUs (2011) Source: [19]
Looking at the map in figure 34 there is a view of the main CDGUs in the various
network connections. Created energy is distributed starting from generation
subsystems in the plant areas through the transmission grids at high and the highest
voltage (HV): 110 kV, 220 kV and 400 kV. These connections are managed by one
company – PSE Operator S.A. The target customers are usually supplied by the
distribution grids: the part of 110 kV, medium and low voltage. The whole HV
transmission grids consist of 5,984 km of 400 kV lines and 7,971 km of 220 kV lines
(31.12.2015 status). There is also a switched-off 750 kV line (114 km). Due to the
72
problems in trading on the synchronous profile (DE/CZ/SK), the cross-border exchange
is running mainly via the northern interconnectors: with Sweden – a 450 kV submarine
DC cable (254 km of which 127 km belongs to PSE) and with Lithuania – a 400 kV HVDC
line (163 km of which 112 km passes through Poland).
The condition of the transmission and distribution infrastructures is overall bad and
needs refurbishing. Even though the entire losses are slightly more 6% and let meet
the average in the EU (OECD/IEA statistics for 2013), the highest losses appear in the
old distribution grids, in particular in rural areas. However the main problem is a poorly
developed grid in the north, which limits new investments. Not only it hampers the
plan for building a nuclear power plant, but also the development in renewables-based
installations, when the grid is overloaded. On the other hand, though the public
supports the need for new connections, the majority represents the NIMBY syndrome
(Not in My Backyard) following the idea: everywhere, but except my living place. The
example is the project of the 400 kV line between Kozienice and Ołtarzew. The same
may be referred to new wind power plants.
4.2. Subsidy mechanisms
Operating on the market by generators is predominantly based on the competitiveness
mechanisms, where prices and profit are formed depending on the approved strategy.
This best suits for conventional power plants, which variable costs do not always meet
the clearing price in the merit order. However there are some technologies privileged
in a pile (fig. 35): CHP and renewables-based power plants.
73
PLN/MWh
Var
iabl
e co
sts
of e
ner
gy p
rodu
ctio
n an
d of
fers
on
the
bal
anci
ng m
arke
t
must-run generation
operating with network access
priority
MINIMUM DEMAND11.857 MW
12 June, 5:00 a.m.
MAXIMUM DEMAND22.791 MW
30 June, 1:15 p.m.
RANGE OF DEMAND PATTERN IN JUNE 2016
Fig. 35. Example of merit order for different power plants (June 2016) Source: own development based on [7]
Both the aforementioned technologies participate in trading of the certificates of
origin, hence they have a priority to the transmission and distribution services. It
results from the current implemented regulations of the Minister of Economy and from
the Energy Law Act, which impose the obligations on generators and trading
companies (selling electricity to end-consumers) to purchase the certificates of origin
in sufficient quantities. It is also applied for industrial customers, who use not less than
100 GWh/year for own need. When they do not meet a given level, they can pay the
substitution fee determined by the ERO president, which refers to the average price
on the competitive market. Otherwise they are fined.
4.2.1. Cogeneration
Cogeneration is defined as the concurrent generation in one process of both thermal
and electrical energy, but heat generation is usually leading and electricity is a by-
product. This technology, next to RES, is aimed to primarily improve energy efficiency
according to the Polish document entitled Polityka energetyczna Polski do roku 2030
due to fuel savings. In the document the quantitative objective for cogeneration in
74
energy policy was determined. It has been assumed that the production in high-
efficiency cogeneration will be doubled in 2020 in comparison with 2006. According to
the Energy Law Act high-efficiency cogeneration lets save at least 10% of the primary
energy in fuel over against separated generation or save anything when a plant up to
1 MWe is taken into consideration.
In the light of the above, there are support mechanisms for investment and
maintenance dedicated for high-efficiency cogeneration. The investment programme
is the Operational Programme Infrastructure and Environment for the years 2007 –
2013 and 2014 – 2020 with a total budget for this purpose of over EUR 380 million.
Among the operational support mechanisms are the network services and the system
of the certificates of origin. Energy generated in high-efficiency cogeneration must be
always received and distributed by the DSO in the network to which a cogeneration
unit is connected, when it does not impact on the system safety. However it does not
mean the obligation for a recipient to buy this energy, hence the cogeneration unit
trades its energy on the competitive market. The development in cogeneration is not
still possible without the aforementioned certificates of origin, because there is no way
to generate electricity with almost zero heat demand, e.g. during the summer period
(higher operational costs than for a conventional power plant). Cogeneration is also
less competitive, when heat prices are specified in tariffs and the emission allowance
prices tend to be low.
As shown in table 4 there are the three types of the certificates connected with high-
efficiency cogeneration on the PRM depending on the used fuel. All of them are known
as the yellow certificates (transferable property rights).
The certificate system for cogeneration has been operating since 2007 (excluding lack
of support in 2013 and the part of 2014). It will be finish or prolonged in 2018. Even
though the European Commission acknowledged this system as state aid, it is
compatible with the general European rules of such an aid, because increases energy
efficiency.
In 2014 high-efficiency CHP power plants generated 22,791 GWh of energy, which
accounted for 14.33% of the total gross electricity generation and was lower by 1.32
percentage points than in 2007 (when the system was launched). Over this 8 year
period, the share leveled out, but the total volume from the amortised yellow
75
certificates changed reaching the minimum in 2014, when the support was stopped in
the previous year (fig. 36).
Fig. 36. Share of high-efficiency cogeneration in total electricity generation Source: own development based on [25]
Fig. 37. Prices for high-efficiency cogeneration indices Source: own development based on the data from TGE
Notice: The prices in 2016 were set based on the trading data till 2016-10-20
15,65 16,09 16,33 17,06 16,12 16,24 15,03 14,33
0
20
40
60
80
100
0
20 000
40 000
60 000
80 000
100 000
120 000
140 000
160 000
180 000
2007 2008 2009 2010 2011 2012 2013 2014
Shar
e o
f h
igh
-eff
icie
ncy
co
gen
erat
ion
[%
]
Tota
l ele
ctri
city
gen
erat
ion
[G
Wh
]
Other generation (GWh)
Cogeneration (GWh)
High-efficiency cogeneration (GWh)
Volume from yellow certificates (GWh)
Share of high-efficiency cogeneration in total generation (%)
110,00
121,63 125,00
63,26 63,26 63,00
11,00 11,00 11,00
0
20
40
60
80
100
120
140
2014 2015 2016
Pri
ce [
PLN
/MW
h]
KGMX_POLPX KMETX_POLPX
KECX_POLPX SUBSTITUTION FEE FOR PMGM
SUBSTITUTION FEE FOR PMMET SUBSTITUTION FEE FOR PMEC
76
Considering the prices for consecutive high-efficiency indices during the last three
years (fig. 37) they were lower than the substitution fees set by the ERO President. The
PMGM instrument was the most expensive and the PMEC instrument was the
cheapest, however it is subject to the highest redemption (23.2% in the years 2014-
2018). In general the average electricity price for the installations identified with the
PMGM and PMEC instruments is at the similar level close to the price on the
competitive market, while generation from methane-fired plants or gas-fired plants
from biomass (the PMMET instrument) is more lucrative. In 2014 the average price on
the competitive market was 163.58 PLN/MWh. Methane-fired plants were selling
electricity at 173.64 PLN/MWh and gained profit for the certificate at 60.90 PLN/MWh.
But power plants with <1 MW installed capacity earned the most with the average at
270.53 PLN/MWh (164.89 PLN/MWh + 105.64 PLN/MWh).
4.2.2. Renewable energy sources
The EU countries are obliged to support the development of RES according to Directive
2009/28/WE, where the aim for 2020 is to achieve a RES market share in the EU to 20%
in all energy consumed. This share for Poland is 15%.
To meet the 15% objective in 2020 the certificates of origin were introduced (just as
yellow certificates for CHP power plants). The green certificates may be received by
renewables-based generators, which feed their electricity into the grid. The certificates
of origin are transferable on the market in the form of property rights. The electricity
sellers and huge consumers must purchase these certificates to amortise by the ERO
President in appropriate quantities resulting from the applicable regulations. They can
also pay the substitution fee instead, unless the market price falls significantly below
this fee (then there is the obligation to account only for certificates). Consequently,
this system presents the strong relationship between installed capacity in RES and the
quantitative redemption shaping the property rights prices.
77
Fig. 38. Structure of installed capacity in RES in 2016 (30 June 2016 status) Source: own development based on [39]
Notice: The structure involved those installations, which obtained a sole authorisation to generate electricity
In 2016 the highest share of installed capacity among renewables-based installations
was for wind power plants (fig. 38). This technology has been developing since 2005,
but the most significant growth was observed in years 2011 – 2016, when its share
increased three and a half times. Wind power plants answer also for the highest
electricity volume confirmed by the green certificates. However it is going to decrease
due to the Act of 20 May 2016 on investments concerning wind power plants. This Act
limits significantly surface area for new plants. Comparing the year 2015 with the first
half of 2016 the electricity volume derived from certificates of origin fell more than
three times – from about 10.5 TWh to about 3.3 TWh. [39]
On the other hand, there is the certificates oversupply on the property rights market.
Not only it amounted to more than 20 TWh, but also the last prices are diminishing to
the level of 30 PLN/MWh (October 2016). Theoretically it may be resolved, when the
prices on trading sessions (responsible for one third of the market) are below
20 PLN/MWh. Each certificate allows to deduct the excise duty for electricity in the
amount of 20 PLN/MWh, hence such a situation leads to a profit for buyers [9].
78
Fig. 39. Average prices for property rights for energy from RES and substitution fess in the years 2008 – 2016
Source: own development based on the data from TGE Notice: The prices were correlated based on both the OZEX_A and OZEX indices for the PMOZE_A and PMOZE instruments respectively including only trading sessions. The average price in 2016 provided for all trading sessions till 2016-10-26
As shown in figure 39 the downward trend has been ongoing since 2011 (except the
year 2014), even though the substitution fees have been staying at the similar level. It
was caused primarily by the above-mentioned oversupply in the green certificates (fig.
38). There is the correlation between the significant growth in installed capacity and
the noticeable oversupply level in years 2011 – 2016. The required RES share in total
energy consumption in consecutive years was changed three times by the regulations
in 2005, 2008 and 2012, but taking into account all electricity volumes from the
amortised certificates and the substitution fees, the Minister of Economy’s objective
was nearly always fulfilled.
241,09256,40
266,41278,14
249,18
163,79
199,38
122,50
81,29
248,46258,89
267,95274,92
286,74297,4 300,03 300,03
0
50
100
150
200
250
300
350
2008 2009 2010 2011 2012 2013 2014 2015 2016
Pri
ce [
PLN
/MW
h]
PMOZE_A + PMOZE SUBSTITUTION FEE
79
Fig. 40. Energy volumes from RES in the years 2005 – 2015 Source: own development based on [39], [32]
The subsidy mechanism for renewables-based power plants is currently undergoing a
period of transformation that resulted from the latest amendment to the Law on
Renewable Energy Sources from 22 June 2016. According to this regulation, the
property rights system was replaced by the auction system. The support time for the
both systems is 15 years, but the previously existing system will last no longer than till
31 December 2035.
Up to now renewables-based installations earned extra money selling their certificates
in the form of property rights depending on the market situation. In the current
system, there will be auctions announced periodically by the Ministry of Energy to
purchase a certain volume of electricity based on the specific technology. The
electricity prices will be shaping according to the merit order pricing system, but no
higher than the reference prices for individual installations in the technological baskets
with a capacity below and over 1 MW. It seems the first auction will be organised for
photovoltaic power plants, because as PSE notices, Poland needs about 2 GW installed
capacity in PV to deal with the summer peak demand by the operator.
There are seven technological baskets broken down by different criteria. Energy may
3,103,60
5,10
7,00
8,70
10,40 10,40 10,40
12,00
13,00
14,00
0,00
2,00
4,00
6,00
8,00
10,00
12,00
14,00
16,00
0
5 000 000
10 000 000
15 000 000
20 000 000
25 000 000
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
Ener
gy s
har
e o
f R
ES in
to
tal c
on
sum
pti
on
[%
]
Ener
gy v
olu
me
[MW
h]
Energy volume from RES according to the certificates of origin (MWh)
Energy volume from RES according to the amortised certificates of origin (MWh)
Energy share of RES in total consumption according to the Decree of the Minister of Economy (%)
80
be sold, when generated from renewable energy source in the installation, which [40]:
1) is at the rate of installed capacity utilisation no higher than 3504 MWh/MW/year;
2) uses biodegradable waste to generate electricity;
3) CO2 emission is no higher than 100 kg/MWh and the rate of installed capacity
utilisation is higher than 3504 MWh/MW/year;
4) operates in the energy cluster;
5) operates in the energy collective;
6) uses only agriculture biogas to generate electricity;
7) is different than those mentioned in points 1 – 6.
The maximum reference prices for different fuels in the system are the following:
Fig. 41. Maximum reference prices in the auction system Source: own development based on [30]
Notice: There are the following installations exempted from the auction system: water power plants (>5 MW); biomass, biofuel, biogas, agriculture biogas power plants (>50 MW) excluding those working in high-efficiency cogeneration (<150 MWt); co-combustion systems excluding dedicated co-combustion (with min. 20% of the biomass share or fluidised-bed power plants to 50 MW)
The renewables-based installation in the auction system may consist of many types of
sources connected to different grids, e.g. co-combustion and a wind power plant in
one installation. There are also auctions within the specified groups defined as energy
0 100 200 300 400 500 600
On-shore wind energy (<1 MW)
Hybrid renewables-based installation (<1 MW)
Biogas from waste storage yards
Biomass, biofuels, biogas, dedicated co-combustion
Biogas from a water treatment plant
Other biogas
Waste incineration plants
On-shore wind energy (>1 MW)
Biomass, dedicated co-combustion (<50 MW)
Biomass, CHP dedicated co-combustion (>50 MW and <150 MWt)
Hybrid renewables-based installation (>1 MW)
Biomass, CHP dedicated co-combustion (<50 MW)
Solar energy (> 1 MW)
Geothermal energy
Solar energy (<1 MW)
Hydro-energy (<1 MW)
Off-shore wind energy
Biofuels
Hydro-energy (>1 MW)
Agriculture biogas (<1 MW and >1 MW)
Price [PLN/MWh]
81
clusters and energy collectives. The group may be found to generate and balance
energy from the renewables-based installations within the designated area at the
distribution voltage.
The new system is also available for the units operating on the property rights market,
but there is no option to change the system, when an unit decides to move from one
system to the other. Despite the fact that the accounting rules were changed for
prosumers (they are going to be cleared according to the net-metering principle), only
energy from installations with <500 kW installed capacity may be purchased by the
obliged seller. For the rest installations a producer sells energy on the competitive
market, but has the title to cover the negative balance (when the producer’s offer price
in the winning auction is lower than the average price on the power exchange).
5. ELECTRICITY PRICES IN THE DIFFERENT SEGMENTS OF THE WHOLESALE MARKET
Analysing a structure of any liberalised wholesale market, a price shaping process may
be stated. Nevertheless a market is to maintain a healthy balance between supply and
demand so that the electricity system could be cost-effective with diversified
generation sources. Taking into account the Polish wholesale market (as in other
European countries), price shaping can take place in two ways: first by the short-term
market, which should allow prices to be formed slowly according to current energy
shortages and second by the long-term market, where concluded transactions ought
to guarantee capital for investments.
In this chapter there is the focus on the day-ahead market, which features high
liquidity. It let its players to correct their contract positions based on transactions made
on the forward and OTC markets. The second to analyse is the balancing market with
hourly products. This market operates to address network and plant constraints, hence
it is also shaped by long-term price signals. The analysed period is last 12 months from
November 2015 to October 2016.
The condition of these two markets is going to be a derivative of many factors, that
often lead to price fluctuations or even to price distortions. The market price is
certainly connected with coal and emission allowances prices, since the Polish energy
mix draws on coal. However there is growing evidence of the TSO services, especially
the operating reserve. It causes an increase in prices due to higher system maintenance
82
costs, but does not enhance the system security. On the other hand the system shows
overcapacity. It decreases prices, but results primarily from conventional sources
including ineffective, old plants. The regulations hamper their withdrawal, hence new
investments are limited.
5.1. Prices on the markets
Fig. 42. Prices on the day-ahead market (the IRDN24 index) and on the balancing market (daily average values)
Source: own development based on the data from PSE and TGE
The average IRDN24 index’s price on the DAM was 157.66 PLN/MWh, while on the
balancing market the average clearing price of the DSP deviation was 161.13 PLN/MWh
in the analysed period. Simplistically, they are correlated to each other, however
looking at figure 42 there are certain spans, where prices on the both markets rocketed
significantly being much higher than the average. Such trends took place in January,
June and at the end of the period.
83
Fig. 43. Average monthly domestic power demand Source: own development based on the data from PSE
The average monthly domestic power demand in the system was around 18.6 GWh
with the highest value in January 2016 (25,240 MWh at 6 p.m. on 2016-01-22) and the
lowest one in May 2016 (11,158 MWh at 4 a.m. on 2015-12-27). On the other hand,
the TSO suffered the most from capacity shortages in the months, when the average
demand was relatively low (fig. 44).
Fig. 44. Average capacity shortages of the CDGUs Source: own development based on the data from GPI TGE
Notice: In the figure there are also taken into account the nCDGUs such as: the „Siekierki” (591 MW) and „Żerań” (373 MW) CHP plants in Warsaw, the „Elektrownia Blachownia” (158 MW) power plant in Kędzierzyn-Koźle, the CHP plants in Łódź (105 MW) and Poznań (212 MW) belonging to Veolia
15500
16000
16500
17000
17500
18000
18500
19000
19500
20000
20500
Ave
rage
mo
nth
ly d
om
esti
c p
ow
er d
eman
d
[MW
h]
0
1000
2000
3000
4000
5000
6000
7000
Cap
acit
y sh
ort
ages
[M
W]
Average planned capacity shortages Average unplanned capacity shortages
84
The key issue is to find an appropriate answer for the price rises shown in figure, thus
there is a need to study and compare the data from the platform about the wholesale
market (GPI TGE) and from the last versions of the CDCPs delivered by the TSO.
5.1.1. January 2016
Fig. 45. Prices and power flows in January 2016 Source: own development based on the data from GPI TGE, PSE and TGE
Notice: negative values correspond to capacity shortages or energy export from Poland, while energy import into Poland is positive
85
The first span with the average high prices was January 2016. On the 7th of January at
5 and 6 p.m. there were the maximum possible prices on the balancing market –
1,500 PLN/MWh, what increased the average on that day to 501.22 PLN/MWh.
Conversely, these prices on the 31st of January reached their minimum values (at
4 a.m. 1 MWh cost 70 PLN). It was caused primarily by high wind generation and
relatively low capacity shortages (fig. 45). However the maximum prices are hard to
explain from the above figure. For example on the day before the prices were
significantly lower, although the power flows kept the same level.
Fig. 46. Domestic power demand and prices on the 6th and 7th of January 2016 Source: own development based on the data from PSE
At 5 p.m. on the 6th of January the clearing price of the DSP deviation was
198.43 PLN/MWh, while a day later increased to the mentioned maximum. The first
cause for such a spread resulted from the domestic power demand at that hour. The
difference amounted to 4,659 MWh (fig. 46). During that severe network conditions
the TSO was forced to reach out of ancillary services including intervention work
delivered by the selected pumped-storage power plants. Although the total capacity
shortages on the 7th of January were only 270 MW higher than the day before, the
TSO was devoid of the several important in balancing CDGUs (like in the previous day)
and additionally the 560 MW unit in Kozienice was unexpectedly shut down.
86
Fig. 47. Power and intervention reserves on the 6th and 7th of January 2016 Source: own development based on the data from PSE
Comparing prices on the both spot markets, the balancing market reflects the most
accurately the current network situation, while the DAM is a place, where players trade
energy based on historical data, at the earliest from a day before. Hence significant
price discrepancy may occurred, particularly when the CDGUs must be disabled in
emergency.
5.1.2. June 2016
The next month, when price rises were observed was June 2016 (fig. 48). There were
four days with the average price peaks over 400 PLN/MWh. In these days in particular
hours the prices on the balancing market exceeded 1,000 PLN/MWh. When these
prices rise, it is often connected with an increase in unplanned energy received from
the market. It means that the plans involved system constraints prepared by the TSO
do not meet real power flows or power plants are not able to perform the notified
agreements technically, while the balancing offers are limited.
87
Fig. 48. Prices and power flows in June 2016 Source: own development based on the data from GPI TGE, PSE and TGE
In this case the IRDN24 index followed the clearing price more accurately than it took
place in January 2016 (when it was more profitable to buy energy on the balancing
market). In table 7 there are the selected technical data shown for the hours with the
highest clearing prices during the mentioned peaks.
88
Table 7. Comparison between the days with the highest clearing prices in June 2016
Date 15th 20th 23rd 28th
Hour 12 2 p.m. 2 p.m. 12
Power demand [MWh] 21,280 21,510 22,128 21,818
Clearing price of the DSP deviation [PLN/MWh] 1,071.49 1,429.17 1,284.09 1,200.37
Price on the DAM (fixing I) [PLN/MWh] 438.92 480.01 1,127.84 800.00
Capacity shortages [MWh] 7,530 6,978 7,183 6,033
Wind generation [MWh] 51 477 157 253
Intervention work [MWh] 0 40 80 160
Intervention cold reserve [MWh] 300 128 342 357
Parallel cross-border exchange [MWh] 114 -298 202 409
Nonparallel cross-border exchange [MWh] 466 757 1,242 540
Power reserve over demand [MWh] 1,603 297 1,065 984
Notice: „+” – energy import into Poland, „-” – energy export from Poland
Comparing the above data with the power flows in the days with low prices in figure
48, the factor shaping prices is primarily wind generation. In the peak hours the wind
generation did not exceed 0.5 GWh and generation at the level of about 1.5 - 2 GWh
is already reflected in lower prices (at similar total power demand).
The next factor diminishing prices is nonparallel cross-border exchange (with Sweden
and Lithuania). At 2 p.m. on the 23rd of June Poland imported more than 1 GWh of
energy and it was close to the highest value in the moth (1,359 GWh on 2016-06-07).
However there was little wind and the TSO had to activate the intervention
generations, hence the prices rocketed on the market. It is worth underlying that at
that hour prices on the both market have broken through 1,000 PLN/MWh.
5.1.3. September and October 2016
The last span with soaring energy prices was the end of the period in September and
October 2016 (figures 49 and 50). As in the previous months high prices occurred
during times of peak load: in the afternoon, but also in the evening (on 2016-09-27 or
2016-10-10 at 8 p.m.). On the 27th of September at 8 p.m. the NPS was on the edge of
safety. According to the CDCP on that day the additional power reserve over demand
equaled to 0. Next to the same factors increasing prices as previously: low wind
generation and congested interconnectors, there were also the considerable
unplanned capacity shortages and the noticeable decline in the available nCDGUs’
capacity.
89
Fig. 49. Prices and power flows in September 2016 Source: own development based on the data from GPI TGE, PSE and TGE
90
Fig. 50. Prices and power flows in October 2016 Source: own development based on the data from GPI TGE, PSE and TGE
The unexpected shutdowns happened on 2016-09-27 involved a few units with
120 MW and 200 MW capacity, but even several 300 – 600 MW blocks were out of
work. The total capacity shortage amounted to 7,545 MW. However the most
considerable point turned out the nearly gradually decrease in the total nCDGUs’
generation capacity from 1 a.m. to 11 a.m. (fig. 51). Although the CDGUs and nCDGUs’
91
productions were changing insignificantly in the space of the day, the risk for lack of
capacity led to the maximum price on the balancing market at 8 p.m. (in addition there
was almost no wind in the earlier hours).
Fig. 51. Power demand, wind generation and available nCDGUs’ generation capacity on 2016-09-27
Source: own development based on the data from PSE
What is more, on the following day (2016-09-28) even though the capacity shortages
were 8,160 MW and the power demand maintained at the similar level (22,597 MW),
the clearing price was just 219.00 PLN/MWh due to the greater value of wind
generation (3,341 MWh).
5.2. Wind generation
As shown in the previous subchapter, wind generation is a factor lowering prices,
however similar to others it should be referred to actual power demand when being
compared. Power generation from wind is an unstable energy source, but possible to
be pretty well predicted based on weather forecasts.
92
Fig. 52. Average monthly values for wind generation and the PMOZE_A_POPLX index Source: own development based on the data from TGE and PSE
Although wind turbines, when activated, are very often expected to produce electricity
after fixing, their owners find the green certificates the most encouraging to be on the
market. However the analysed period showed the significant decrease in these prices
(fig. 52). On the 4th of October 2016 the market noted the lowest price in the history
– 20,72 PLN/MWh during the OTC transactions. Simultaneously the highest prices were
at the level of the substitution fee (300,03 PLN/MWh) at the end of the period.
The day with the greatest wind generation was the 2nd of February 2016 with
4,546 MWh as an average hourly value (80% of the installed wind capacity run). Taking
the demand peak at 6 p.m. into consideration (23,205 MW), the wind production
constituted about 18.6%. On the other hand the 5th of November 2015 was almost a
calm day with the average production equal to 114 MW. In this case wind turbines
generated just 164 MW during the highest demand at 6 p.m. being represented for
0.7% of the total hourly consumption. Despite the significant difference in generation,
the clearing price at that hour on 2015-11-05 was 205,89 PLN/MWh (76,88 PLN more
than on 2016-02-02). What is more the TSO had only 70 MW of capacity over demand.
But in 2015 there were no costly intervention ancillary services.
0,00
20,00
40,00
60,00
80,00
100,00
120,00
140,00
160,00
0
500
1000
1500
2000
2500
Pri
ce [
PLN
/MW
h]
Gen
erat
ion
[M
Wh
]
Wind generation PMOZE_A_POLPX
93
5.3. Summary
Analysing prices on the DAM and the balancing market in the period from November
2015 to October 2016, there is a possibility to specify the NPS’s condition. Energy
flowing in the domestic transmission network is priced depending on its load. Prices
were increasing sharply during high peak demand in the afternoon and evening, when
there was noticeable lack of power. Overall, it may be caused by capacity shortages
reducing available CDGUs’ and nCDGUs’ generation capacity, low wind generation and
congested interconnectors, primarily low nonparallel cross-border exchange. The most
dangerous for the system are unplanned capacity shortages of the CDGUs. Because
coal power plants are dominant, arising hydrological problems in hotter months
connected with open cooling for units may accelerate sudden shutdowns. The TSO may
use intervention ancillary services to balance the system, when players’ generation
capacity is lower than their consumption. In this case it increases the clearing prices on
the balancing market like on the 7th of January 2016 at 5 and 6 p.m. (1,500 PLN/MWh).
The above dependence illustrates, that high CDGU’s generation prevents a sharp rise
in prices, even during peak demand (e.g. on 2015-12-16 at 5 p.m. the CDGUs covered
78% of the power demand equal to 24,705 MWh, thus the clearing price of the DSP
deviation amounted to 281.44 PLN/MWh).
The cures for lack of capacity are wind generation and energy imported from other
foreign markets to some extent. Wind turbines, when replace coal power plants for
balancing purposes, decrease prices and allow to keep power reserve at a greater level.
For example on 2016-01-31 due to the highest average daily generation (4,020 MW),
prices on the both market could be low. However wind as a natural source is variable
and may be disadvantageous for conventional power plants. Assuming that turbines
work often during windy nights displacing coal plants, they can encounter the
problems with restarting by day. As well as other renewable-based installations lead
to a decrease in prices. It happens due to imported energy from the northern direction
(parallel cross-border exchange is still limited by unplanned flows). However
nonparallel exchange in the analysed period delivered the maximum amount of only
1,379 MWh. It proves that domestic generation capacity acts all the time a key role for
the TSO.
94
6. GENERAL SUMMARY
This thesis focuses on the Polish wholesale market as a main place, where the
electricity price is being shaped. This kind of market is the most competitive form of
trading. Moreover the report shows different standard market designs. Electricity as a
homogenous product is transferable among the market players. Simultaneously
derivative products are getting more and more popular. Today the electricity prices
are not only a result of variable cost of the most expensive generator. Analysing them
there is a need to take many factors into consideration: subsidy mechanisms, cross-
border flows, capacity shortages, operating and intervention reserves and so on. In the
future there may be a further element resulting from capacity market.
Now the stock market (both the DAM and CFIM) is liquid mainly due to the obligation
for the producers, who concluded long-term energy contracts in the past, to
participate in it. On the other hand the OTC market is growing its volumes, while the
mentioned contracts are gradually phased out.
Since energy supply is delivered primarily by ageing coal-fired power plants, the
question is what the role of Poland will be in the EU, when the pan-European market
starts to operate. Now the Polish energy mix seems to be good for balancing purposes
during peak demand, but technically limited by interconnectors’ throughput. The
current government objective for the power sector is to build new conventional power
plants and make them more flexible in respect of load. Collaterally the new auction
system for renewables-based installations is to support in achieving a binding target of
20% share in 2020. This is being done to limit the risk, when the system is on the edge
of its stability.
7. STRESZCZENIE
Głównym celem pracy jest skupienie się na rynku energii elektrycznej i jego roli w
handlu tym towarem w Polsce. Jednakże w pracy przedstawione są różne rodzaje
hurtowych rynków energii, z szczególnym uwzględnieniem rynku giełdowego, który
wyznacza ceny energii elektrycznej jako punkt odniesienia do zawieranych także umów
dwustronnych poza rynkiem konkurencyjnym.
Polska, postrzegana jako kraj rozwinięty, rozwija mechanizmy rynkowe w handlu
energią w formie wielu instrumentów oferowanych na giełdzie energii – Towarowa
95
Giełda Energii S.A. Dlatego giełda jest szczegółowo opisana w pracy. Handel energią
często wiąże się z jej fizycznym przepływem od sprzedawcy do klienta, co wymaga
bilansowania popytu i podaży jak najbliżej czasu rzeczywistego. W pracy znajduje się
także opis rynku bilansującego, gdzie rozlicza się energię kupioną przez uczestników w
wyniku operacji handlowych z jej fizycznym zużyciem.
Giełda energii to nie tylko handel energią oparty na krajowych mocach wytwórczych i
lokalnym zużyciu, lecz także miejsce współpracy z innymi rynkami zagranicznymi w
myśl koncepcji jednolitego europejskiego rynku energii. Praca zawiera informacje
dotyczące wymiany transgranicznej i jej wpływu na kształtowanie się cen hurtowych.
Polski system elektroenergetyczny wymaga bezpiecznej pracy, w którym energia
powinna pochodzić z przyjaznej dla środowiska generacji po rozsądnej cenie
uwzględniając zróżnicowany miks energetyczny kraju. W myśl tej tezy, w pracy
odwołuje się do obowiązujących aktów prawnych dotyczących odnawialnych źródeł
energii i kogeneracji. Pojawia się także krótki opis ostatniego projektu wdrożenia rynku
mocy.
Część analityczna pracy bezpośrednio nawiązuje do jej tematu. Dotyczy porównania
cen energii elektrycznej na rynku dnia następnego i rynku bilansującego w aspekcie
bieżącego funkcjonowania systemu elektroenergetycznego w różnych przedziałach
czasowych okresu od listopada 2015 r. do października 2016 r.
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