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

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40 000

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2007 2008 2009 2010 2011 2012 2013 2014

Shar

e o

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igh

-eff

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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

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2014 2015 2016

Pri

ce [

PLN

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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

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200

250

300

350

2008 2009 2010 2011 2012 2013 2014 2015 2016

Pri

ce [

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/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

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2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Ener

gy s

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ES in

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[%

]

Ener

gy v

olu

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[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

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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

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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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