PGE BIG BOOK
H1 2017 edition
• PGE data updated as of 2016 YE and H1 2017 • Competition market data updated as of 2016 YE • Incorporated changes in Supervisory Board • Investment process updated • Trading model change • Up-to-date market situation • 2016 YE power system data included • Changes in regulations implemented
(capacity market draft, new RES framework, current ETS IV status, Winter Package, new Industrial Efficiency Act, 2017 ORM parameters)
• LTC court cases status updated and final adjustment • Generation assets data adjusted
What’s new in H1 2017 PGE Big Book?
Table of contents
3
PGE in a nutshell
Corporate Governance
PGE Group strategy & investments
Main business lines description
Power sector in Poland
Regulations
Recent financial and operating results
Financing and rating
Technical appendix
<< Back to table of contents
PGE in a nutshell
Leader of the electricity
sales
Leader in volume of
the electricity generation
Lignite extraction
47.7 m tonnes
Installed capacity
12 749 MW
no. 1 in Poland
Electricity production 53.67 TWh
no. 1 in Poland
CAPEX programme
ensuring business
leadership
Sales to end-users 42.91 TWh
no. 1 in Poland
Distribution lines 286
thous. km
Electricity consumers
5.3 m
no. 1 in Poland
Electricity distribution 34.32 TWh
no. 2 in Poland
5 PGE highlights – 2016 data
7 376
3 337
2 328 2 027
PGE Tauron Enea Energa
Largest & Most Profitable Energy Group in Poland – 2016 data
6
Revenues PLN m
EBITDA PLN m
EBITDA margin
EBITDA of PGE Group PLN million
26% 19% 21% 20%
Source: Financial reports of PGE, Energa S.A., Enea S.A. and Tauron Polska Energia S.A.
6 801
7 310
8 190
8 129
8 228
7 376
2011
2012
2013
2014
2015
2016
28 092
17 646
11 256 10 181
PGE Tauron Enea Energa
PGE Group in the value chain – 2016 data 7
Transmission
Distribution
Wholesale & Supply
• 2 open pit lignite mines (Bełchatów and Turów)
• Lignite output ca. 50 million tons p.a.
• Electricity production net 53.7 TWh
• Installed capacity ca. 12.7 GW
• Sales of heat ca. 18 million GJ
• 2 Lignite-fired power plants
(Bełchatów and Turów)
• 2 Hard coal-fired power plants
(Opole and Dolna Odra)
• Combined heat and power plants – 8 sites (Szczecin, Pomorzany, Gorzów, Bydgoszcz, Zgierz, Kielce, Rzeszów and Lublin Wrotków)
• Hydroelectric power plants (Hydro ca. 97 MW, Pumped-storage ca. 1.5 GW), Wind farms 529 MW
• Activity of PSE S.A.
• Distribution of energy 34.32 TWh
• Distribution grid: 285,701 km
• Number of substations: 92,837
• Final customers 42.91 TWh
• Wholesale market 59.13TWh
• Balancing market 2.26 TWh
Mining
Power generation
PGE 2016 leading market position in Poland 8
ENERGA 3% ENGIE
5% ZE PAK 6%
ENEA 8%
EDF 7%
TAURON 13% PGE
32%
Others 26%
Installed capacities share
ENERGA 2% ENGIE
7% ZE PAK 6%
ENEA 9%
EDF 8%
TAURON 10%
PGE 36%
Others 22%
Net generation share
ENERGA 15%
ENEA 13%
TAURON 25%
PGE 33%
Others 14%
Retail sales share
innogy 5%
ENEA 14%
ENERGA 16%
TAURON 36%
PGE 25%
Others 4%
Distribution volume share
Data: ARE and reports of the companies
Competitive advantages 9
Assets
•Leader in installed capacity and electricity production
•Focused on baseload generation, absolute cost leader in Poland - approx. 70% of power capacity generated from own fuel (2 lignite mines)
•Highly diversified and youngest generation fleet in Poland
•Regulated assets operator (Dolna Odra Power Plant and pumped-storage plants)
•Over 500 MW in wind
•2017 Regulatory Asset Base in distribution: PLN 15.6bn
Strong financials
•Stable revenues
•EBITDA margin at 32% (H1 2017) - highest among Polish power utilities;
•Approx. 1/3 of EBITDA from regulated activities (distribution & heat) under a stable and transparent framework;
•Strong investment grade credit ratings with stable outlook by Fitch and Moody’s
•Plenty of headroom in the balance sheet – net debt/LTM EBITDA at 0.6x as of the end of H1 2017
•CAPEX financing secured
Strategy
•Updated Strategy for 2016-2020 aimed at keeping the leading position on Polish market
•Developing modern conventional electricity
•Developing new technologies and business models
•PLN 34 bn 2016-2020 CAPEX
•Strategic investment options
•Reduction of controllable costs and optimization of maintenance costs
•Flexibility and efficiency of generation units
4 182 365 500
2 230 7 376
Value chain of PGE – 2016 data 10
PGE Group
EBITDA
Renewables Conventional generation
Supply Distribution
10%* 25% 36% Market share 2016
Competitive advantages
• Leader of baseload generation
• Cost-effective fuel base
• Youngest generation assets
• Generation 51.71 TWh
• Heat sold 18.1 PJ
• Onshore wind leader in Poland with 519 MW of installed capacity
• Generation 1.96 TWh
• 2nd biggest customer base – 5.3 million
• Stable regulatory environment
• 34.3 TWh electricity distributed in 2016
• Large SME and mass customer base
• Competences in modelling and forecasting of the energy market
• Asset-based trading allowing further development
• 59.1 TWh on the wholesale market
• Biggest supplier in terms of sales volume 42.9 TWh
33%
57% 7% 30% 5%
End customer market
Supply and distribution data estimated
* Share in RES generation includes biomass combustion and excludes pumped-storage generation
Share in EBITDA
PGE timeline since establishment 11
Corporate Governance
Management team and corporate structure
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Ownership and listing
57.39% State
Treasury
42.61% Other
Shareholders
Turnover (PLN) 8 612 913 380
Average number of transactions per session (pcs) 3 061
Maximum price in year (PLN) 14.39
Minimum price in year (PLN) 9.06
Number of shares and votes (pcs) % of shares and votes
State Treasury 1 072 984 098 57.39%
Other Shareholders 796 776 731 42.61%
Total 1 869 760 829 100.00%
• PGE's shares are ordinary, bearer shares.
• PGE’s shares are listed on the regulated market of the Warsaw Stock Exchange.
• PGE's shares are not privileged.
Company statues provide for special powers for the State Treasury.
As long as it is a shareholder of PGE, State Treasury:
• has the right to appoint one member of the Supervisory Board either by a written statement submitted to PGE at the General Meeting or outside the General Meeting, via the Management Board;
• holds special right with regard to selection of the Supervisory Board members - when appointing members of the Supervisory Board by the General Meeting, half of the members shall be elected from among persons indicated by the State Treasury;
• Supervisory Board selects the Chairman of the Supervisory Board from among its members wherein the Chairman of the Supervisory Board shall be elected from among persons indicated by the State Treasury;
• may demand in writing that the Management Board convene a General Meeting;
• may demand that certain matters are placed on the General Meeting agenda.
13
Management team - profiles 14
Anna Kowalik Chairman
of the Supervisory Board Committees of Audit, Appointment
and Remuneration
Legal counsel. Currently employed in the Ministry of Energy. For many years has worked for Ministry of
Treasury. Experience in supervision of operations of companies with State Treasury shareholdings. Lecturer in the field of the commercial and civil
law.
Radosław Osiński Member
of the Supervisory Board Committees of Strategy and
Development, Appointment and Remuneration
Head of unit in the Department of
Control and Supervision of the Ministry of Energy. In years 1999 - 2016 he has been working at the
Ministry of State Treasury, where he realized tasks involving – inter alia – privatization, corporate governance
and protection of critical infrastructure.
Supervisory Board – profiles 15
Grzegorz Kuczyński Secretary
of the Supervisory Board Committees of Audit and Corporate
Governance
PhD in civil law. Before training as a lawyer he trained as a judge. Since
2007 a partner of Gotkowicz, Kosmus, Kuczyński & Partners Law Firm.
Former assistant professor of the Chair of Civil Law at the Department
of Law and Administration of the University of Gdańsk and an assistant
in the previous years.
Jarosław Głowacki Member
of the Supervisory Board Committee of Strategy and
Development, Corporate Governance
Engineer. Since 2005 Deputy President of Siedlce, responsible for
initiating activities, obtaining European funds and realization of
projects. Experience in evaluation of projects co-funded by the EU.
Employed in City Hall of Siedlce since 1990.
Janina Goss Member
of the Supervisory Board Committee of Audit, Appointment
and Remuneration
Legal counsel. Since 2012 held a position of Management Board
member in Srebrna Sp. z o.o. In years 2009-2010 she was a Supervisory
Board member in Polskie Radio S.A. In years 2006-2009 she was a
Supervisory Board member in TVP S.A., including approx. 2 years at the
position of the Chairman of the Supervisory Board.
Witold Kozłowski Member
of the Supervisory Board Committees of Appointment and
Remuneration, Corporate Governance
Since 1998 has been engaged in local governance, inter alia, as a Secretary of Nowy Sącz District. Postgraduate
studies of Law and Local Government at Polish Academy of Sciences and
postgraduate studies for Administration Personnel at Warsaw
School of Economics.
Mieczysław Sawaryn Member
of the Supervisory Board Committees of Strategy and Development,
Appointment and Remuneration
Since 2014 the Mayor of Town and Community of Gryfino. In years 2011-2014 and 1999-2007 he run his own Legal Office. In years 2006-2011 Mr. Mieczysław Sawaryn was employed in ZEDO S.A., at first as the CEO and
then as the Director of Human Resources and Law, being responsible for consolidation of ZEDO S.A. within
PGE Capital Group.
Artur Składanek Member
of the Supervisory Board Committees of Strategy and
Development, Corporate Governance
Engineer. Since January 2008 held a position of Director of Production at
Finpol Rohr sp. z o. o., where he started to work in June 2007 as a
Production Specialist. During years from 1994 to 2007. he was
running his own business activity - AWI – Przedsiębiorstwo
Wielobranżowe.
PGE Polska Grupa Energetyczna S.A.
the Parent
Corporate Center and Wholesale Company
PGE Systemy S.A.
Shared Services Center
PGE Górnictwo i Energetyka
Konwencjonalna S.A.
PGE EJ 1 sp. z o.o.
PGE Energia Odnawialna S.A.
PGE Dystrybucja S.A.
PGE Obrót S.A.
Generation segments
100% 100% 70% 100%
100%
100%
PGE Dom Maklerski S.A.
Brokerage house
100%
ELECTRICITY DISTRIBUTION
RENEWABLE POWER GENERATION
NUCLEAR PROJECT
SUPPLY CONVENTIONAL POWER
GENERATION
PGE Sweden AB PGE OKK Sp. z o.o.
Shared Services Center
100% 100%
Simplified ownership structure of PGE Group 16
PGE Group strategy & investments
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Redefining the Group’s mission, overall objective and vision 18
Security of supply
Customer
Building value
Economy
PGE Group’s new mission
Increasing the company’s value for the shareholders and the key role in ensuring Poland’s security of power supply
Reliable and active utility and service
supplier
Poland’s most efficient and
flexible energy group
Leader in developing new business models
and lines of business
Leader in generation, actively taking advantage of
growth opportunities
PARTNERSHIP | GROWTH | RESPONSIBILITY
We provide security and growth based on reliability of supply, technical excellence, modern services and partnership relationships
Strategy objectives in a nutshell 19
Maximizing ROIC overall objective
EFFICIENCY AND FLEXIBILITY
DEVELOPING MODERN CONVENTIONAL ELECTRICITY
DEVELOPING NEW TECHNOLOGIES AND BUSINESS MODELS
Opole 5&6 Turów 11
SAIDI, SAIFI
Connection time
Cogeneration
Reduction of* controllable costs
Customer satisfaction
EBITDA - New business operations
Percentage of successful implementations
CAPEX IMO**
Organizational structure Share in RES generation
Biomass co-firing
Flexibility of power plants and utilization of combustion by-products
PLN 3.5bn
New model
>50%
25% in 2030
New development model
On-schedule implementation
-56%
PLN 0.5bn
-40%
* Total reductions in 2016-2020 from current and expected levels of efficiency
** Total reduction of the modernization and replacement expenditures in 2016-2020
CAPEX Program for 2016-2020* - full utilisation of investment potential
20
* Source: PGE Group’s Strategy for 2016-2020
Beyond 2020 PGE Group will be implementing a new CAPEX program , based on selected strategic options, system needs and new market model
By 2020 PGE Group will incur capital expenditures of PLN 34bn
Efficiency improvement will unlock additional investment potential
PGE Group is ready for substantial investments in new lines of business, also abroad
2019 2018 2020 beyond 2020
2017 2016 2015
PLN 34bn
Conventional power generation - existing
Conventional power generation - new Renewables New business
Distribution
Planned capital expenditures
Strategic investments and its financing (1/2) – key projects in pipeline 21
Opole II project
Expansion project Brownfield, will utilize lower unitary cost of production placing two units (2 x 900 MWe) to the left side of Polish merit order
Advancement of the project exceeded 80% (as of H1 2017)
1. Notice to Proceed issued – Q1 2014
2. Unit #5 commissioning – H2 2018
3. Unit #6 commissioning – H1 2019
Ca. 30% of construction works at site completed
1. Notice to Proceed issued – Q4 2014
2. Unit #11 commissioning – H1 2020
Financing model
Project schedule
Investment financed in corporate model assuming on-balance sheet financing and external resources, including bonds, Eurobonds and loan facilities.
Turów project
Replacement Brownfield. New unit (490 MWe) will replace decommissioned units and utilize existing lignite deposits
Current stage of works
Rationale of the project
Strategic investments and its financing (2/2) – key projects in pipeline 22
Gorzów CHP project
Expansion project CCGT unit (140.5 MWe / 100 MWt) diversifies the Group’s energy mix while benefiting from less expensive cost of fuel from local Polish gas deposits
Project completed, commercial operation started on January 31, 2017.
1. Contract awarded – Q4 2013
2. CHP commissioned – Q1 2017
Advancement of the project – ca. 30% (as of Q1 2017)
1. Contract awarded – Q4 2015
2. Commissioning – Q2 2018
Financing model
Project schedule
Investment financed in corporate model
Rzeszów CHP project (ITPOE)
Expansion project Waste-to-Energy installation (7.6 MWe / 20.5 MWt) diversifies the Group’s energy mix and provides entry to new business
Current stage of works
Rationale of the project
Preferential loan from National Fund for Environmental Protection and Water Management and corporate model
√
Strategic options – optimal choice 23
Options to consider:
* SMR - Small Modular Reactors HTR – High Temperature Reactors
2020 2025 2030
Climate policy
tightening
Climate policy easing
Off-shore wind farms
Nuclear power plant
Modern coal-fired power generation
HTR/ SMR*
2035+
Construction of Poland’s first nuclear power plant, following the development of a model guaranteeing economic viability of the investment
Construction of approx. 1 000 MW capacity in off-shore wind farms, based on an auction support system
Utilization of new lignite deposits in case there is a significant easing of the climate policy
Strategic options details – potential and conditional realisation 24
Rationale of the project
Financing model
Project schedule
Current stage of works
Nuclear project Off-shore wind Lignite deposits
Expansion project Built to secure and diversify sources of energy supply. Low emission technology implies lower cost from the perspective of EU climate policy
Expansion project Construction of approx. 1GW capacity in off-shore wind farms on the Baltic Sea in order to diversify sources of energy and contribute to fulfilling Poland’s RES target
Security of fuel supply
Enabling utilization of new lignite deposits as currently exploited open-pit mines are running out of lignite (in 2030 perspective) in case of significant easing of EU climate policy
Expenditures on acquiring mining concessions financed in corporate model
Ongoing works on financing model for the investment
Site characterization (environmental and location study) for two candidate sites
Ongoing works on financing model, engagement of a strategic partner envisaged
Project schedule envisages participation in a RES auction after 2018 (exact date depends on future legal framework)
Preparation of a report on the impact of projects on the environment
The concessions are expected to be awarded in 2018 (Złoczew deposit) and in 2020 (Gubin deposit). Further works are pending administrative and political decisions
Ongoing environmental studies, preparation for a RES auction
Environmental and Site Reports to be prepared by mid 2020. Further works are pending administrative and political decisions
• Modernisation of existing assets
• Comprehensive reconstruction and modernisation of units no. 1-3 at Turów power plant aiming at adaptation to future BAT conclusions, increase of availability and efficiency as well as expansion of each turboset’s nominal capacity by approx. 15 MWe - expected commissioning in 2019
• Modernisations aiming at reduction SO2 and NOx
• Construction of flue gas denitrification installation and flue-gas desulphurisation for OP-230 boilers no. 3 and 4 in Bydgoszcz CHPs Construction of flue gas denitrification installation for OP-230 boilers no. 3 and 4 in Bydgoszcz CHPs – expected commissioning in 2018
• Construction of flue gas desulphurisation and denitrification installations for WP-70 boilers at Lublin Wrotków CHP - expected commissioning in 2018
• Modernisation of the Pomorzany power plant aiming at reduction of NOx and SOx emissions from Benson OP-206 boilers to a level allowing to meet the requirements of future BAT conclusions as well as to ensure that the plant remains in operation until about 2040 - expected commissioning in 2020
• Other tasks
• Restoration of the dam within the surface water intake on Witka river in Turów Power Plant – expected commissioning in 2017
• Construction of installation to transport ash and production and transport of sludge from unit 858 MW in Bełchatów power plant - expected commissioning in 2018
• Change in technology of furnace waste storage for units 1-12 in Bełchatów power plant - expected commissioning in 2018
Other investments 25
Strategic projects as of the end of H1 2017 26
Work progress in Opole II: Overall progress of works exceeded 80%
Incurred CAPEX: PLN 7.6 bn out of PLN 11 bn (net budget)
Status: • technological start-up run of equipment within water
treatment plant - task accompanying Opole project
Work progress in Turów: Progress of works on construction site of ca. 30%
Incurred CAPEX: PLN 0.7 bn out of PLN 4 bn (net budget)
Status: • first components of turbo set delivered • ongoing construction of the cooling tower shell
Opole II project – construction of units totalling 1 800 MW
Turów project – construction of unit of 490 MW
Environmental impact of investments 27
In order to meet the European environmental requirements and limit Group’s influence on environment PGE initiated a wide pipeline of modernization projects of currently operating conventional generation assets, as well as construction of new highly efficient generating units that shall meet the highest environmental standards.
Emissions in existing units – 2016 data Emissions in Turów 11, Opole 5-6 – maximum level for units under construction * Gross production
Already decreased power plants’ emissions (1989-2016) per MWh
• SO2 emissions lowered by 94%
• NOx emissions lowered by 60%
• Dust emissions lowered by 99%
Comparison of emissions rates of developed and existing units
0,4
0,6
0,8
1,0
1,2
Turów 1-6 Turów 11 Bełchatów1-12
Bełchatów14
Opole 1-4 Opole 5-6
CO2 t/MWh*
0
50
100
150
200
250
Turów 1-6 Turów 11 Bełchatów1-12
Bełchatów14
Opole 1-4 Opole 5-6
NOX mg/Nm3
0
5
10
15
20
25
Turów 1-6 Turów 11 Bełchatów1-12
Bełchatów14
Opole 1-4 Opole 5-6
Dust mg/Nm3
0
100
200
300
400
Turów 1-6 Turów 11 Bełchatów1-12
Bełchatów14
Opole 1-4 Opole 5-6
SO2 mg/Nm3
Main business lines description
<< Back to table of contents
PGE trading model change 29
Renewables
CHPs
Power Plants
Supply
Distribution (to cover network losses)
Power Exchange
Households and business
customers
Local producers
Conventional Generation
PGE Group Market
Channel reduced: 15% obligation
while previously 100%
Direct channel developed
Production, supply and sales of electricity to the market
Electricity generated from PGE’s conventional assets under power exchange obligation is traded on the Polish Power Exchange (TGE). The rest of wholesale is traded directly by Supply segment.
Electricity generation from renewable sources and in pumped-storage power plants: (1) is purchased directly by Supply segment if installations located at the area of operation of PGE Dystrybucja (distribution) (2) or purchased by the supplier acting at particular area of operation.
Supply segment, apart from Group wholesale trading of electricity, is responsible for trade of all related products and fuels on domestic and international market as well as sale and supply of electricity and fuels to end-users:
(1) Business customers – enterprises and institutions, which is free market
Tariff A – large industry (high voltage) such as steelworks, mines, large factories Tariff B – Large and medium enterprises (medium voltage) such as shopping malls, hospitals and industrial customers Tariff C – Small and medium enterprises and institutions (low voltage) such as shops, service outlets, farms
(2) Households (TPA) - third-party access (TPA) rule allows sale to households on a competitive market (3) Households and housing cooperatives (G tariff group) which is regulated market.
Additionally Supply segment sells electricity to PGE Dystrybucja to cover network losses related to distribution of electricity.
Distribution segment, run by PGE Dystrybucja, is responsible for distribution of electricity to end-users through the grid and HV, MV and LV infrastructure.
Business Model - Electricity 30
Some business flows including balancing market, international trade and own consumption are not shown
Business Model – Certificates & CO2 allowances
31
Production, supply and sales of certificates to the market
Cogeneration certificates of origin (red and yellow in case of PGE) are generated in CHPs. Green certificates are generated mainly by RES installations, but are also generated in Conventional Generation segment from combustion and co-combustion of biomass in power plants and CHPs.
Trading of certificates pass mainly through the Polish Power Exchange (TGE) Some trading agreements with local suppliers include sale of green certificates together with the electricity sold.
Supply segment is responsible for wholesale trading of certificates on domestic market. Certificates of origin are purchased by Supply segment for Group needs in order to be redeemed respectively to the obligation regarding sales of electricity to end-user (currently Green, Red, Yellow, Purple, Blue and White).
Circulation of CO2 allowances
Internationally traded CO2 allowances are purchased on power exchanges and wholesale trading platforms. Supply segment mainly purchases CO2 allowances to cover emissions of Conventional Generation segment but also trades CO2 allowances. Conventional Generation segment redeems CO2 allowances respectively to its CO2 emission.
CO2 ALLOWANCES
CERTIFICATES
Business lines – opportunities and threats 32
Conventional generation Distribution Renewables Supply
• Termination of PGE’s LTC compensation scheme and related power exchange obligation gives us the ability to buy electricity delivered to final off-takers OTC, internally
• Model of DSO strategy for 2016-2020 being in operation
New tariff model:
- quality parameters added
- OPEX reduction
- new WACC computation model
• Amended RES law brings down the level of the substitutional fee for green certificates
• Approved increase in obligation to redeem green certificates for 2018 and 2019
• BAT regulations to be effective 2021
• Pending regulatory works on Capacity Market
• Winter Package discussion on EU level
• ETS revision process
Dominant position on the market
Significant customer base
Volatility of both electricity prices and green certificates
Increasing competition on retail market
Fully regulated activity
Significant customer base
Infrastructure requiring significant modernization
New model for 2016-2020 reflecting government bond yields compression and quality component in tariff
Youngest generation assets in Poland
Own lignite deposits.
Leadership in generation.
Tight climate policy (CO2, BAT/BREF)
Potential changes to capacity mechanisms
Support for CHPs only until 2018
Electricity prices under pressure
Potential to develop district heating business
Expanding green portfolio assuring number of green certificates
Introduced auction system
Formal and legal barriers during investment process
Oversupply of green certificates
Recent developments important for each business segment
Employment 33
12 073 11 306 10 938 10 648 10 298 10 239
2011 2012 2013 2014 2015 2016
Distribution
21 693 19 638 18 871 17 485 16 706 16 407
6 491 6 380
2011 2012 2013 2014 2015 2016
Conventional Generation (core) Support
44 217 41 277 41 195 39 977 38 877 38 471
2011 2012 2013 2014 2015 2016
PGE Group
1 635 1 491 1 505 1 497 1 390 1 409
612 657
2011 2012 2013 2014 2015 2016
Retail Wholesale, Enesta
PGE Group Conventional generation (like-for-like)
Supply (like-for-like) Distribution
-13%
-15%
Full time employment data
Since Q1’15, as a result of reporting rearrangements, Supply segment includes also Wholesale and Enesta (whereas before it included only Retail).
-14%
-24%
Conventional Generation - overview 34
Our flagship business
• 2 lignite mines, 4 conventional power plants (2 lignite fired and 2 hard coal fired) and 8 CHPs
• The total achievable power generation capacity of 10.7 GWe
• PGE accounts for 78% of Poland’s total lignite extraction
• Apart from internally extracted lignite, PGE uses hard coal, gas and biomass in electricity and heat generation processes
Deposit Resources – as at the end of 2016
[Mg million] Output in 2016
[Mg million]
Bełchatów – Field Szczerców industrial 616 24
Bełchatów – Field Bełchatów industrial 47 16
Turów industrial 310 8
Lignite resources
Long term strategic options
• The above mentioned resources are sufficient to fuel PGE’s power plants for another 20 to 25 years
• PGE is in process of obtaining mining permits for Złoczew and Gubin deposits
• Future conventional investments conditional upon CO2 policy, strategic partnerships and implemented support mechanisms
PGE lignite deposits 35
Gubin
Złoczew*
Szczerców field
Bełchatów field
Bełchatów LP
Turów LP
Turów OCM
Available resources (strategic options)
Active field / open cast mine (OCM)
Lignite fired power plant (LP)
Projected year of termination of extraction
2040
2020 2044
PGE operates two lignite complexes: in Bełchatów and in Turów. Each complex encompasses open cast mine and power plant. Bełchatów mine contains two fields: Bełchatów and Szczerców.
0
10
20
30
40
50
60
20
16
20
18
e
20
20
e
20
22
e
20
24
e
20
26
e
20
28
e
20
30
e
20
32
e
20
34
e
20
36
e
20
38
e
20
40
e
20
42
e
20
44
e
Mill
ion
to
ns
Lignite extraction – illustrative only
Turów Szczerców Bełchatów
* Złoczew – a remote deposit to Bełchatów complex
Conventional Generation – fuel supplies 36
Main fuels:
• Lignite (sourced internally)
• Hard coal
• Gas
Provision of fuel supplies:
• Hard coal supplies secured through long-term contracts; main suppliers include:
- Polska Grupa Górnicza (PGG) – former contract of Kompania Węglowa (KW) – expiration year 2018, price formula includes ARA prices, domestic hard coal price and electricity price
- Jastrzębska Spółka Węglowa (JSW) – expiration year 2017, prices negotiated annually
• Future hard coal contracts:
- An agreement with Polska Grupa Górnicza (former contract of Kompania Węglowa) concluded in August 2013 for supplies of hard coal in years 2018-2038 in order to provide fuel for new units in Opole power plant. Price formula includes average electricity price, average market price of hard coal and average cost of CO2 emission rights
• Gas supplies secured through long-term contracts and supplementary short-term agreements.
- 20-year agreement with PGNiG concluded in October 2013 for gas supplies to Gorzów CHP (starting from the commissioning date of new unit). Gas price lower than tariff provided mainly through access to local sources of natural gas.
CO2 allowances accounting scheme 37
3. Redemption (April)
1. Purchasing of EUA is not a cost itself, it is an exchange of assets. Accounts involved: cash and inventory. 2. The creation of provision is a cost recognition process. 3. Redemption is a settlement process. It is an utilization of assets (EUA inventory) in the process of
settlement with the Regulator.
LTC compensations – final adjustment 38
Year Opole PP Turów PP Gorzów CHP Rzeszów CHP Lublin Wrotków
CHP ZEDO PP
2008 Case closed Case closed Case closed Case closed Case closed Case closed
2009 Case closed Case closed Case closed Case closed Court of Appeal
verdict* Case closed
2010 Case closed Case closed n/a Case closed Case closed Case closed
* verdict of the Court of Appeal of April 27, 2017 Case closed – favourable verdict
Court of Appeal – favourable verdict. ERO President entitled to cassation appeal
Not a subject to LTC compensations
PLN m 2011 2012 2013 2014 2015 2016 2017
Provision for outstanding court cases re LTC from 2008-2010
(1 038)
Reversal of provision based on legally binding verdicts
- 200 337 246 - 173 82
Unsettled LTC disputes – total value 0
The process of establishing the annual adjustment of stranded costs for 2016 was completed on July 31, 2017. According to the decision of the ERO President, the annual adjustment of stranded costs in generating units of PGE GiEK S.A. for 2016 amount to approx. PLN (+)276 million. On August 25, 2017 the ERO President settled the amount of final adjustment of the stranded costs for PGE GiEK S.A. units, totalling PLN (+) 938 million. The final adjustment of stranded costs will have an impact of PLN (+) 1 212 million on reported revenues and EBITDA of the PGE Group in 2017.
30.0
138.2
283.2 311.0
529.0 529,0
0
100
200
300
400
500
600
2011 2012 2013 2014 2015 2016
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
2011 2012 2013 2014 2015 2016
Photovoltaic Biogas Biomass Hydro Wind
Renewables - overview 39
RES installed capacity in Poland MW • Over past 4 years PGE onshore wind installed capacity increased from
30MW in 2011 to 529 MW in 2015.
• New support scheme replaced green certificates regime (for new projects). The auction mechanism rewards only the most efficient and cost-effective technologies.
• In 2015 PGE has completed four wind farms (Karwice, Lotnisko, Resko II, and Kisielice) and expanded capacity by 218 MW y/y.
• Secured support scheme for existing wind farms.
• At the moment there is still uncertainty related to the RES support in 2017/2018 – particularly auction final price and volume to be purchased.
PGE – installed wind capacity MW
Source: ERO PGE’s installed RES capacity FY 2016
Overview
+105% +10%
+70%
+361%
* Including wind farms Lotnisko (90MW) and Kisielice II (12 MW) which had unfinished licensing process as of Dec, 31.
Type No. Of Units Operating
Installed capacity (MW)
FY 16 energy generation (TWh)
Wind* 14 529.0 1.08
Hydro (run-of-river) 29 96.8
0.43 Pumped-storage plants with natural flow
2 291.5
PV 1 0.6 0.02
Biomass CHPs (conventional generation)
2 75.2 0.43
RES TOTAL 993.1 2.24*
Pumped-storage power plants
2 1216.0 0.45
TOTAL 2,133.8 2.69
Change of
support scheme
* Including 0.30 TWh of biomass co-combustion
Supply segment overview 40
• The total size of the power supply market in Poland amounts to approx. 129 TWh.
• The Group supplies to ca. 5.2 million customers.
• Free electricity market for industrial and commercial customers.
• Households are ¼ of the market and customers’ prices are regulated by tariff „G” approved by the ERO.
Supply and wholesale position Supply branches
► PGE has a large customer base and growing sales of electricity
Update of PGE’s trading strategy
• Target to maximize margin on the whole value chain.
• Better risk management related to increased volatility of both electricity prices and green certificates.
• Offer expansion both from the product and services perspective.
• New marketing offers including dual fuel and auxiliary services.
• Focus on customer: account management and support.
Distribution segment overview 41
• Operates in the area of 122.8 th sq. km and supplies electricity to over 5.3 million customers
• Includes supply of electricity to final off-takers through the grid
• Revenues are dependent on unit distribution tariffs that are accepted by the ERO President assuming full coverage of justified costs and market level of return on distribution assets
Electricity distribution network overview
Distribution Position
Key operational data
Operational data Unit 2016 2015
Number of stations pieces 92,837 92,258
Capacity MVA 29,903 29,500
Length of power lines km 285,701 283,804
HV lines km 10,197 10,143
MV lines km 110,798 109,938
LV lines km 164,706 163,723
Grid loss ratio* % 5.8% 5.9%
SAIDI ratio** min 401 442
* ratio calculation: (volume of energy inducted to the grid of the Distribution System Operator –volume of energy taken from that grid)/ volume of energy inducted to the grid of the Distribution System Operator ** ratio calculation: (duration of long and very long breaks x number of off-takers exposed to the effects thereof)/number of off-takers *** PGE position handicapped due to natural conditions (less populated and geographically challenging areas)
► Distribution activities provide regulated stable and predictable cash flows
SAIDI - reduction target
0 100 200 300 400 500
PGE***
ENEA
ENERGA
TAURON
SAIDI 2016 in minutes
SAIDI planned + unplanned
442 401
196
0
100
200
300
400
500
2015 2016 2020
SAIDI (in minutes)
-9%
-56%
Developments on national level
Polish government commitment to the deployment of the Polish Nuclear Power Programme confirmed by:
• Adoption of the Polish Nuclear Power Programme (PNPP) (January 2014)
• Including nuclear power in national energy mix scenarios proposed in the draft of the new Polish Energy Policy until 2050 (PEP 2050) (public consultation started in August 2014)
• Establishing of the Inter-ministerial Advisory Committee for the Deployment of the Polish Nuclear Power Programme at the Ministry of Economy (appointed in October 2014)
Rationale behind the project
• EU climate change policies
• Decarbonisation
• Diversification and increase in security of supply
• Aging conventional generation fleet (baseload)
• PGE Group diversifies its generation portfolio in order to lower CO2 emission
Developments on PGE level
September 2014 - PGE S.A., TAURON Polska Energia S.A., ENEA S.A. and KGHM Polska Miedź S.A. (Business Partners) concluded a Partners’ Agreement on acquiring from PGE 10% of shares in PGE EJ 1 sp. z o.o. - special purpose company responsible for the project. Shareholders agreed to proportionally finance the operations under the initial phase of the project
April 2015 – PGE concluded sale of 30% of shares in PGE EJ 1 sp. z o.o. to the Business Partners
March 2017 – beginning of full-scale site characterization (environmental and location study) for two candidate sites.
Project pipeline
• Execution of site characterization until preparation of Environmental and Location Reports as well as associated tasks to ensure fulfilment of MAEA requirements / guidelines and Polish regulations
• Ongoing education, communication and sponsorship activities by PGE EJ 1 to maintain local support for the investment
• Analysis by Ministry of Energy related to: (1) a model for nuclear technology acquisition, (2) a model for investment financing
• Update of the Polish Nuclear Power Programme and its acceptance by the Polish Government
First Nuclear Power Plant – zero-emission electricity supply for Poland
42
Power sector in Poland
<< Back to table of contents
Poland – electric power system profile 44
47% 78 TWh
31% 51 TWh
8%
6% 3% 3%
Hard coal
Lignite
Wind
Autoproducers (all fuels)
Gas
Biogas & Biomass
Hydro
Biomass co-combustion
Pumped-storage
Photovoltaic
50% 19.4 GW
23% 9.4 GW
14%
4%
3% 2%
2% Hard coal
Lignite
Wind
Gas
Pumped-storage
Biogas & Biomass
Hydro
Photovoltaic
Other
41.2 GW
18
19
20
21
22
23
24
25
26
Jan Feb Mar Apr Mar Jun Jul Aug Sep Oct Nov Dec
Avg. Peak Demand 2015
Avg. Peak Demand 2016
Country consumption: 168.6 TWh (gross)
Country generation: 166.6 TWh (gross)
International balance: 2.0 TWh (net import)
Dynamics of consumption: +2.4%
ARE Data
PSE Data
ARE Data
ARE Data
167 TWh
Electricity demand and supply 45
Source: PSE, 2015
ARE forecast
KAPE forecast
PSE Innowacje forecast
(base scenario)
Power consumption forecasts GDP and power consumption growth
TSO survey – falling system reserve
Rise in demand and simultaneous decommissioning of old capacities are responsible for shrinking reserve capacity
Required capacity reserve wouldn’t be met even if existing units were modernised in compliance with BAT regulations
As the current market design* does not generate proper signals for Polish generators there is a significant blackout risk in mid 2020s
* See more in the slides 47-48
Source: Central Statistical Office of Poland, PSE
Key generation assets in Poland 46
CAPACITIES IN CONSTRUCTION
Kozienice 11, 1 075 MW – hard coal
(ENEA)
Płock CHP, 596 MW - gas
(ORLEN)
Opole 5&6, 1 800 MW - hard coal
(PGE) H2 2018, H1 2019
Jaworzno III, 910 MW - hard coal
(TAURON)
Turów 11, 490 MW - lignite
(PGE) H1 2020
KEY PENDING PROJECTS
Stalowa Wola CHP, 450 MW - gas
(TAURON+PGNiG) 2019
Ostrołęka C, 1 000 MW – hard coal
(ENERGA+ENEA) H2 2023
How the base power price on the Polish market is built up? (illustrative) 47
Power price is set by the marginal power plant in the system on
the variable costs basis
Typically it is hard coal as a fuel
setting the price
Hard coal price is set on the basis of the domestic
market
(PSCMI1 index rather than ARA
index)
CO2 allowances price and some
other minor environmental
costs complement the
price
Mark-up is to cover fixed costs
and to allow generation
profits
…but variable cost for the
marginal power plant depends on
its efficiency in combustion,
Coal price / efficiency
EUA price x emission
Offer price ≥ variable cost
Polish Merit Order in picture – illustrative only 48
RES installations with almost zero marginal cost, come first with guaranteed offtake, supported with RES certificates or in auction system
Pumped-storage units: working
according to TSO needs, separately remunerated
Hard-coal power plants
Average demand
CHPs – treated as „must runs”, while producing heat electricity is a by-product; Additionally supported with yellow or red certificates
Autoproducers – „must run” CHPs generating for industrial purposes with ability to deliver surplus of electricity
Gas-fired units working in condensation
• Marginal cost of thermal power plants driven mainly by the cost of fuel and price of CO2 allowances (see slide 47)
• Great importance of the generation efficiency (newer installations consume less fuel)
• Current supply and demand build up wholesale price of electricity
• Supported units are pushing thermal units out of merit order – lowering the price below variable cost of conventional generation
• Merit order varies during the day (i.a. significantly lower demand in off-peak hours) and between seasons (i.a. less CHPs in warmer months, RES affected seasonally by the weather)
• Fuels division for illustrative purposes – (*) depending on the current market conditions some more effective hard coal units could generate cheaper than less efficient lignite ones
Essentials
Remarks
Distorted market forces 49
• PGE is predominantly base-load generator with high volumes produced
• That is why most important for Group’s results are prices of one-year base contracts,
• Looking ahead one year forward is the most liquid contract
Market distorted due to RES subsidies
New investments are not incentivized and less efficient units might not be
modernized
Probable future shortage of capacity (as illustrated in the slide 45)
Necessity of capacity market introduction to guarantee safety and reliability not provided by the distorted energy-only
market
With growing share of RES wholesale market prices basing on variable cost are
falling down
Electricity Market Development Price of BASE Forward next year
150
155
160
165
170
175
180
Jan
-15
Mar
-15
May
-15
Jul-
15
Sep
-15
No
v-1
5
Jan
-16
Mar
-16
May
-16
Jul-
16
Sep
-16
No
v-1
6
Jan
-17
Mar
-17
May
-17
Jul-
17
162
Source: TGE 159
164
Wholesale prices vs. retail prices 50
Wholesale price of electricity is set on variable cost base
Support schemes (mainly RES support) and distribution costs are allocated in the price paid by the final off-taker
These account for 72% cost for households in Poland whereas in Germany and Denmark for above 90%
Average Prices for Individuals in Region (PLN in 2016) Average Wholesale Prices in Region (PLN in 2016)
Key available interconnections in Poland* 51
UKRAINE 251 MW***
SWEDEN 600 MW
LITHUANIA 500 MW****
SLOVAKIA 831 MW**
CZECH REP. 3,236 MW**
GERMANY 1,843 MW*** 0.97 TWh
0.01 TWh
2.62 TWh
0.07 TWh
0.09 TWh
0.17 TWh
0.37 TWh
0.53 TWh
0.13 TWh
Import 4.82 TWh
Volumes traded in 2016
Export 1.64 TWh Total thermal capacities installed between countries
* Links over 110 kV. Not shown non-operational Białystok-Roś connection with Belarus and Rzeszów-Dobrotwór with Ukraine ** Connections trading availability limited due to circular flows between Germany and Austria – see trading volumes ** * Only Dobrotwór-Zamość line **** Used mainly as an another link to the Swedish system (via SwedLit link- NordBalt)
1.07 TWh
0.44 TWh
Data source: TGE
Crossborder exchange in H1’17 52
UKRAINE
SWEDEN
LITHUANIA
SLOVAKIA CZECH REP.
GERMANY
Import 3.23 TWh
Volumes traded in H1 2017
Export 2.00 TWh
Data source: PSE, own works
0.62 TWh
0.01 TWh
1.54 TWh
0.18 TWh
0.06 TWh
0.08 TWh
0.74 TWh
0.53 TWh
0.40 TWh
0.84 TWh
0.24 TWh
Development of interconnections 53
LITHUANIA
GERMANY
+ 500MW
+ 1,500 MW
+ 500 MW
+1,500 MW
+500 MW
+ 500 MW
Target import capability increase in 2020*
Analysed development of LitPol link beyond 2020
Target export capability increase in 2020*
Installation of phase shifters and grid development projects allowing electricity trading
Target import capability increase in 2022*
Target export capability increase in 2022*
* Target capabilities available after completion of related development processes of both grid operators
District heating overview
Heating and cooling accounts for half of the EU’s energy consumption
European map of district heating
54
Length of district heating networks
District heating networks in Europe Sales of heat to final consumer
0
50
100
150
200
250
300
PJ
0
5000
10000
15000
20000
25000
30000
35000
km
Heat production in Poland 55
22.2
69.7
202.3
Heat production in 2016 (PJ)
Autoproducing CHPplants and non-commercial heat plants
Commercial powerindustry
Heat producers anddistributors
TOTAL: 294.2 PJ
Estimates assuming finalisation of acquisition of EDF assets Source: ARE
• Huge potential of one of the best developed heat markets in Europe
• Largely decentralised sector with a need of investments creates an opportunity
15%
9%
6%
2% 68%
Installed capacity in heat in Poland
PGE + EDF
PGNiG Termika
VEOLIA
TAURON
PozostałeOthers
Regulations
<< Back to table of contents
European Union Emissions Trading System (EU ETS) 57
The purpose is to promote reductions in CO2 emissions
Limit reduced each year. In the system’s Phase III (years 2013-2020) by 1.74% annually, what gives 21% reduction in total
Participants of the system: 28 EU countries + Iceland, Liechtenstein and Norway
EU legislation puts a cap on emissions of greenhouse gases (GHG) to ensure the reduction targets (mainly CO2 for power sector)
Idea
Trading mechanism
Companies buy and sell emission allowances (EUA) in auctions
Allocation of the allowances to be auctioned: 88% EU ETS member states (on the basis of the verified emissions in 2005), 10% least wealthy countries, 2% ‘Kyoto bonus’ for nine states (incl. Poland)
Auctions on specific platforms – mainly German EEX and British ICE. Poland plans to launch its own platform. So far using EEX.
Free emission allowances granted until 2013. From 2013 power generators have to cover full emission with allowances bought – excluding Poland and other new member states (free allowances granted on the basis of modernising the power sector)
These exceptions are known as derogations. The size of derogations for particular installations is determined and proposed by National Implementation Measures
Companies obliged to redeem allowances, respectively to their emissions, by 30 April of the following year. Allowances are then cancelled and taken off the market
Fine for non-compliance: 100 EUR per tonne of CO2 in 2013 with Eurozone inflation indexed yearly
ETS periods
Alternative emission units: CER/ERU (granted for reduction of emissions), exchangeable for EUA 1:1
Maximum volume to be exchanged for EUA: up to 11% of the free emissions granted in years 2008-2012 or up to 4.5% of the verified emissions in years 2013-2020
Phase I: 2005-2007
Phase II: 2008-2012
Phase III: 2013-2020
Phase IV: 2021-2030
Alternative emission certificates
EU ETS market revision – key expected changes 58
Market Stability Reserve (MSR) to be established in 2018 and become operational from 1 January 2019
The MSR is composed of 900 million allowances deducted from auctioning volumes during the period 2014-2016
The intake is currently established at the level of 100 million allowances, which are placed into MSR when the total number of allowances in circulation is less than 400 million
The European Council may decide to increase the intake up to 200 million of allowances
MSR and Backloading
EC proposal for a revision of the ETS directive (July 2015) – follows the conclusions with a few detailed issues still to be discussed
• Main assumptions:
From 2021 onwards the Linear Reduction Factor (LRF) would be established at the 2.2% level, compared to 1.74% currently
• The EP ENVI proposed to increase the LRF to 2.4% but amendment rejected by the European Parliament
The auctioning share at the level of 57% of the total amount of the allowances
2021-2030 derogation period for countries below 60% EU GDP per capita average (at 2013 market prices – Poland within the threshold) allowing to allocate up to 40% of auctioned allowances directly to the energy sector and the national share from the Modernisation Fund (MF). The MF would be composed of the 2% of the total amount of allowances.
• Poland may expect to receive through these compensatory mechanisms (derogation and MF) up to ca. 428 allowances.
• However, due to the strict definition of the incentive effect, additional eligibility criteria (like Emissions Performance Standard in the EP preliminary position) and the governance design – these compensatory mechanisms would not be predominantly addressed to the coal-fired generation units.
Additional allocation of 10% of total EU ETS allowances for countries with GDP per capita below 90% EU average
• Poland will receive ca. 270 million additional allowances as budget proceeds on top of the 700 million received based on historical emissions.
The key decisions in the EP and the Council would be the subject of the compromise, which would be elaborated with the European Commission during the informal trilogue.
EU ETS in 2021-2030 (IV Phase)
CO2 emissions - free allocation 59
Free allocation for 2013-2020
PGE is entitled to receive free emission rights in the third settlement period which runs from 2013 till 2020
• Emission rights for the third settlement period were granted on the ground of Regulation of the Council of Ministers of April 8, 2014 – details provided in the table below
• Amount of allocations adjusted with reference to the current investment schedules
Allocation for PGE Group generators
(in Mg million)
2014 2015 2016 2017 2018 2019 2020 2017-2020
TOTAL free allowances for
electricity & heat generation
30.0* 26.0** 19.9*** 15.1 13.0 10.4 0.4 38.9
* Covered ca. 51% of CO2 emissions in 2014 ** Covered ca. 45% of CO2 emissions in 2015 *** Covered ca. 36% of CO2 emissions in 2016
Industrial Emissions Directive (IED) 60
Regulates standards of the industrial operations
Creating one law concerning industrial emissions – successor of IPPC Directive and LCP Directive
Aims at minimising pollution from various industrial sources throughout the EU
Need of constant monitoring of NOx, SO2 and dust particles emissions
New limits to be set in BAT conclusions (see next slide)
Idea
Influence
New plants have to meet strict emission limits values (ELVs) for nitrogen oxides, sulphur oxides and particulates from 2013.
Existing large combustion plants have to fulfil standards from 2016
PGE assured compliance with IED – environmental investments and use of mitigation mechanisms
Transitional National Plan approved by the European Commission
Opt-out derogations (for installations to be decommissioned before 2023 and working not longer than 17,500h)
Derogations for district heating < 200 MWt
Peak load plants working no longer than 1,500h per year
Main mitigation mechanisms (2016-2020)
Best Available Techniques 61
Describe what are considered to the best available techniques in a specific industry
Delivered by technical working groups and periodically revised (BREF revision process)
Adopted under both IPPC Directive and IED
Concern NOx, NH3, CO, HCl, HF, SO2, Hg and dust emissions and other factors like efficiency
BREF LCP (BAT Reference Document for Large Combustion Plants)
BATC (BAT conclusions)
Chapter of BREF LCP containing information on the emission levels associated with the best available techniques
Provides binding emission limits - company have to fulfil them to get permit to carry out operations
Separate limits for existing and new installations (receiving permit after BREF is published)
Installations have to fulfil requirements in 4 year term after the BAT conclusion is published to get integrated permit
BAT Conclusions significantly tighten permissible levels given by the IED
Potential capital expenditures to comply with new standards
BAT-compliance already assured for Turów 11 project (contract annex signed)
Influence
Process
Final draft of the BREF LCP issued in June 2016
Voting on establishing BAT conclusions in April 2017 – met 65% population threshold (with 65.14% in favour)
Expected publication of BREF LCP – H2 2017, to be in force H2 2021
Winter Package
• Published on November 30, 2016 as a document „Clean Energy for All Europeans”
• Proposal of the European Commission
• Consists of proposed changes with regard to i.a.:
• Electricity Market Regulation & Directive
• Energy Efficiency Directive (EED)
• Renewable Energy Directive (RED II)
• Regulation on the Governance of the Energy Union
• Ongoing consultation process at European Level with final approval expected probably no sooner than end of 2018
• Key issues discussed:
• Binding RES target (EC proposed 27% in 2030 without country targets)
• Energy efficiency improvement target (proposed 30% in 2030) for EU members
• Exclusion of biomass as a RES in power plants (only high-efficient cogeneration)
• Development of interconnections (target of 10% in 2021-25 and 15% in 2026-30)
• Capacity market payments cap of CO2 emissions at 550 kg/MWh
• Department from priority access for RES
62
Capacity Mechanisms in Poland 63
• Operational Capacity Reserve (ORM) – introduced 2014
Centrally dispatched units remunerated ex-post for peak hours if not selling electricity but being available
• Interventional Cold Reserve (IRZ) – introduced 2016
Units in permanent reserve remunerated for being at PSE’s disposal
24.99
25.87
0.83
3.45**
23
24
25
26
27
28
29
30
Max. monthly demand* IRZ ORM
GW
demand
Ca. 17% of demand
* According to TSO coordination plan for 2017 (maximum values in January) ** Model-based size of the ORM, operationally it could be higher or lower
• Mechanisms aimed at assuring capacity needed in the system for delivering reliability
• TSO determines security level – system reserve should remain at 18% of the demand
• International exchange not taken into account when setting reserve level
• Demand reduction (negawatts) – auctioned year on year – as other instrument used by the TSO. In 2015 ca. 200 MW at disposal
• Potential of centrally dispatched pumped-storage of ca. 1.7 GW
• Proceeding capacity market legislation
System reserve essentials
Current capacity mechanisms in details 64
• Centrally dispatched units remunerated ex-post for peak hours if not selling electricity but being available; from 2017 also DSR available to participate in scheme
• The maximum price (PLN 41.79) paid unless the security level is exceeded; if exceeded remuneration lower respectively
• Budget and parameters determined year on year, implied total 2017 budget of ca. PLN 542 m
• Since 2016 not utilised part of the budget has been distributed through ORM-takers (monthly and yearly)
• Detailed parameters comparison:
• Aimed at covering fixed and variable costs of the generation units
• Reserve in 2017: 830 MW
• PGE has signed the agreement with Grid Operator on intervention capacity reserve for units 1 and 2 in Dolna Odra power plant, with a total capacity of 454 MW
• The agreement covers the years 2016 and 2017, with an option to extend for a further two years, till the end of 2019
• Grid Operator shall pay PLN 24 average per hour, for each MW of power at the disposal
• Units 1 & 2 in Dolna Odra power plant have been granted derogations in the amount of 17.5 thousand hours to be used in the period 2016-2023. This limit shall be used depending on the needs of NPS
• Siersza units 3 & 6 and Stalowa Wola unit 8 (both TAURON) as a remaining part of the IRZ (in total 376 MW)
2017 2016 2015
Hourly budget (BGOR) PLN 144 070.61 PLN 128 758.72 PLN 106 246.72
Required hourly quantity
(WRM) 3 447.49 (MWh) 3 451.09 (MWh) 4 155.37 (MWh)
Reference price (CRRM) 41.79 PLN/MWh 41.20 PLN/MWh 37.28 PLN/MWh
ORM hours in year 3 765 3 780 3 810
Operational Capacity Reserve (ORM)
Interventional Cold Reserve (IRZ)
Capacity Market as projected 65
• Centralized capacity auction system (UK and US experiences based) • Market-wide and quantity-based • Targeted at long-term security of electricity supplies (investment incentive and DSR stimulant) • First auction planned in 2018 with 2021 delivery
Certification of participants
•Technology neutral but differently supported capacities excluded
•Interconnected capacities included in form of ticket auctions
•Qualification mandatory for all eligible generation capacities in Poland
•Lodged collateral before auction
Auction Parameters
•Determined by TSO (capacity demand curve, maximum prices for price takers, capex for new and modernized units, number of rounds)
•Potentially allowed baskets – stimulation of new investments and modernizations
•Evaluated by ERO President
•Approved by Ministry of Energy
Primary
Market
•Main auction (5 year ahead of delivery, for full calendar year)
•Supplementary auctions (1 year ahead of delivery, for each single quarter)
•Dutch auction (descending clock format) run on a pay-as-clear basis
•Winning units conclude agreements with TSO and are obliged to be ready to deliver capacity when “stress period” announced (when capacity reserve available lower than required)
•Price setters (new or modernized units and DSR) and price takers (existing units) - bidding up to a predetermined threshold
•Capacity Agreement duration (for Main Auctions): 1 year, but New units (up to 15 years) and Modernized (up to 5 years)
Secondary Market
•Secondary capacity obligation trading (ex-ante)
•Volume reallocation (ex-post within 10 days after execution)
Delivery and Settlement
•Monitoring and Verification
•Remuneration (monthly basis)
•Penalties for non-delivery (when applied transferred to over deliverers)
•Stress period announcement by TSO - 8 hours ahead in Regular Mode, 4 hours ahead in Emergency Mode (conditional exemption allowed due to technical conditions)
RES support schemes from 2016 (illustrative only, pending law changes) 66
e.g. grouped generators of different RES technologies operating locally
Existing Installations commissioned until July 2016
New Installations commissioned until July 2016
Biomass co-combustion (undedicated) Hydro >5 MW Other RES
GREEN CERTIFICATES
AUCTIONS For existing installations
Possibility to change support
scheme
No support from 2016 1 MWh = 0.5 certificate 1 MWh = 1 certificate
15-year support (since commissioning or since the
beginning of the system: 2005)
* Prosumer gets a discount for the part of the electricity taken from the grid (not paying power and distribution price, just RES fee and transitional fee), not larger than 0.8x or 0.7x of the volume fed into the grid
Prosumers (non-business micro installations)
≤ 1 kW > 1 kW Coeff. 0.8x
Net metering*
Coeff. 0.7x
AUCTIONS For new
installations
Capacity factor >40%
Auctions to be announced selected from 7 predetermined
baskets
Capacity factor >40% and
CO2≤ 100kg/MWh
Biodegradable waste
Agricultural biogas
Energy clusters
Energy cooperatives
Other installations
≤ 1 MW
> 1 MW
Baskets similarly determined as for new installations
BLUE CERTIFICATES (agricultural
biogas)
EXISTING UNITS ≤ 1 MW >1 MW
CF>40%* & CO2≤ 100kg/MWh** 1.48 -
CF>40% 1.66 10.50
Agricultural biogas 1.15 2.12
NEW UNITS ≤ 1 MW >1 MW
CF>40% & CO2≤ 100kg/MWh 0.54 0.54
CF>40% 0.83 10.50
Agricultural biogas 8.19 3.51
Biodegradable waste - 4.64
Other 4.73 5.18
20
100 100
40
150
300
Hydro Biomass Agriculturalbiogas
Biodegradablewaste
Onshore wind Photovoltaics
RES support scheme in 2017 as projected (pending law changes) 67
Obligation to redeem green and 2016-introduced blue certificates
Total RES obligation of 16% constitutes of: Green Certificates 15.4 and Blue Certificates 0.6% (2018: 17.5% & 0.5% 2019: 18.5% & 0.5%)
Substitution payment 300.03 PLN/MWh – the same for both types of certificates. Substitution payment available if the average market price is higher and there are certificates on the market. New amendment limits its level to 125% of the last year market price.
2017 Volumes announced (in TWh)
Financing scheme for auctions: RES fee for final consumers 3.70 PLN/MWh
* CF – Capacity Factor >40% defined as 3 504 MWh/MW/a year ** Emission rate interpretation excludes pure biofuels what leaves space for hydro only *** Assumed capacities illustratively only. Final results will differ – respectively to technologies bidded in baskets
New capacities expected in 2017 auctions*** (in MW)
Green & Blue Certificates Scheme
Two auctions in June, 29-30
Cogeneration Support 68
Based on certificates of origin - three types of certificates
Yellow (gas-fired units or total installed capacity of CHP below 1MWe)
Purple (units fired with methane from hard coal extraction or from biogas)
Red (CHPs over 1 MWe and using any other type of fuel)
Support resumed in 2014 and functional until 2019 (for yellow and red ones, purple operational continuously)
The certificates are given to the utilities that run highly efficient CHPs when co-generating heat and power
Companies selling electricity to final consumer obliged to obtain certificates of origin and to present for redemption to the regulator (detailed percentage obligations below) or make a substitution payment (prices below)
Reduced obligation for big energy-intensive industrial consumers
System
Substitution payment
Obligations
2014 2015 2016 2017 2018
Obligation
Red 23.2% 23.2% 23.2% 23.2% 23.2%
Yellow 3.9% 4.9% 6.0% 7.0% 8.0%
Purple 1.1% 1.3% 1.5% 1.8% 2.3%
2014 2015 2016 2017 2018
Substitution payment (PLN)
Red 11.00 11.00 11.00 10.00 9.00
Yellow 110.00 121.63 125.00 120.00 115.00
56.00 56.00 Purple 63.26 63.26 63.00
Obligation applies to the volume of electricity sold to final consumers (excluding big industrials presenting certificates for redemption on their own)
Strategic support for development of district heating market
Report by the Ministry of Energy „Directions for development of innovations in energy” (May 2017) indicates the legitimacy of:
Increasing the share of cogeneration as an environmentally effective way of using fossil fuels
Financial support for expansion of the district heating network
We assume that support for highly efficient cogeneration will be continued in long-term perspective :
The certificate system of support for highly efficient cogeneration will expire by the end of 2018. Declaration by the Ministry of Energy implies that after 2018 support for that technology will be continued
Conceptual works on the auction system are ongoing in the Ministry of Energy, system shall be similar to auction-based RES support scheme, provided by the RES Law
According to the Ministry of Energy, the proposed system shall be disclosed shortly (i.a. statement of RES Department Director in May 2017 – support concepts prepared and currently discussed, introduction and notification before the current scheme is over)
69
New Industrial Efficiency Act 70
New Act replaces 2011 legislation and enters into force October 1, 2016
Basing on white certificates, granted to entrepreneurs for proven efficiency improvements
Companies selling electricity, heat or gas to final consumer obliged to present White Certificates for redemption to the regulator or make a substitution payment
1 toe (tonne of oil equivalent) saved = 1 white certificate
1 GWh ≈ 86 toe
System essentials
Key changes
Easier to receive white certificates – granted on application, tender process abolished
Obligation may be fulfilled with energy efficiency audits (no need of issuance and redemption of certificates in that case)
Removed restrictions for EU-ETS installations
White certificates also for improvement in energy processing
Ability to receive certificates, if previously not granted, for realized projects (from January 1, 2014)
Higher substitution payments: PLN 1 000/toe (2016), PLN 1 500/toe (2017), and +5% a year afterwards
Limited ability to pay substitution payments (as % of the obligation): 30% (2016), 20% (2017), 10% (2018); unless proven inability to buy certificates priced below substitution payment
Energy audits requirement for big companies (every 4 years)
Obligation
1.5% volume savings in energy sold to final consumers
Either in form of redemption of white certificates or realization of projects resulting in improvement in final consumer’s efficiency (proven by the energy efficiency audit)
Obligation to be fulfilled until June 30 of the next calendar year
999 860 882
1 050 1 065 1 170
1 008 1 041 1 057
2 597 2 638 2 908
2015 2016 2017
Regulated revenue composition* (PLN m)
Return on RAB Amortization Transmission costs Other costs
5 655 5 604
6 017
Fundamentals of the distribution business 71
RAB development* (PLN m)
WACC
2015 2016 2017
7.197% 5.675% 5.633%
2015 2016 2017
95% 100% 100% Return on RAB:
14 618 15 069 15 647
1 655 1 203 1 582 1 004
RAB 2015 CAPEXrecognized
Deduction RAB 2016 CAPEXrecognized
Deduction RAB 2017
* Based on a Tariff
New Tariff Model in Distribution (2016-2020) 72
• End of the current model (for years 2012-2015)
• Inclusion of quality indicators should ensure effective improvement in investments
Idea
2016-2020 Return on capital
ROC = RAB * WACC * Q * RC
Q – quality coefficient RC- regulatory coefficient
Quality regulation (Q) – range: 0.85-1.00
• SAIDI, SAIFI and connection time goals
• Separate for each DSO
• To be included in 2018
Regulator’s adjustment ability (RC) – range: 0.9-1.1
• Separately for each DSO
• To offset extreme weather conditions and innovations of DSOs
• 1.00 in 2016
OPEX and Network losses coverage
• Assumed 10% OPEX reduction (in 5-year period), with 2.5% increase justified with the growing business scale
• Network losses coverage model changed – less costs justified as a result
Parameter Previous
model Tariff for
2016 Tariff for
2017
Risk free rate (%)* 3.961 2.952 2.914 External capital risk premium (%)
1.00 1.00 1.00
Cost of external capital (%)*
4.961 3.952 3.914
Asset beta 0.400 0.400 0.400
Equity beta* 0.800 0.724 0.724
Equity risk premium 4.60 4.20 4.20
Cost of equity (%) 7.641 5.993 5.955
Share of external capital 0.50 0.50 0.50
Pre-tax WACC, nominal
(%)* 7.197 5.675 5.633
* values updated quarterly
New WACC computation model
Recent financial and operating results
<< Back to table of contents
2 002 1 998 1 822
1 321
1 643
2 590
1 948 1 497
1 312 1 273 1 123
-171
895
1 665
1 201 731
Q3'15 Q4'15 Q1'16 Q2'16 Q3'16 Q4'16 Q1'17 Q2'17
EBITDA
EBIT
Focusing on key financial results 74
* Recurring = excluding significant one-off items , ** Basis for the dividend computation according to the previous Dividend Policy,
*** As at December 31, 2016, **** latest available reported data (e.g.. Q2’16 figure was taken from Q2’17 report, etc.)
PLN m H1’17 H1’16 Y/Y 2016 2015 Y/Y
Sales revenues 10 620 13 666 -22% 28 092 28 542 -2%
EBITDA 3 445 3 143 10% 7 376 8 228 -10%
Recurring* EBITDA 3 366 2 881 17% 6 151 7 511 -18%
EBIT 1 932 952 103% 3 512 -3 589 n.a.
Recurring* EBIT 1 895 1 497 27% 3 292 4 733 -30%
Net profit to equity (reported) 1 497 546 174% 2 568 -3 032 n.a.
Net profit to equity ex. Impairment** 1 531 1 267 21% 3 363 4 290 -22%
EPS (reported) 0.80 0.29 176% 1.37 -1.62 n.a.
EPS ex. Impairment** 0.82 0.68 21% 1.80 2.29 -21%
Net cash from operating activities 3 282 2 857 15% 6 391 6 777 -6%
CAPEX 2 595 3 690 -30% 8 152 9 450 -14%
Net debt end of period 4 718 5 152*** 5 152 2 637
Current credit ratings
Rating Outlook
Fitch BBB+ stable
Moody’s Baa1 stable
Key measures – last 8 quarters****
Development of 2016 EBITDA by major value drivers 75
717
294
300
182
141
390
14
177
103
176
332
75
1 225
2015 EBITDA REPORTED
One-offs
2015 EBITDA RECURRING*
Wholesale price of electricity
Volume of electricity**
Hard coal with transport
Biomass
CO2 cost
Regulatory services
Margin on retail market
RES support***
Return on distribution****
Capitalised cost of lignite extraction
Other
2016 EBITDA RECURRING*
One-offs
2016 EBITDA REPORTED
* Recurring = excluding significant one-off items ** Including generation-related environmental costs *** Since Q3 2016 includes cost of blue certificates **** Including network losses
PLN m
8 228
7 511
6 151
7 376
Development of H1 2017 EBITDA by major value drivers
262
80
364
46
63
89
22
86
69
101
65
32
79
H1 2016 EBITDA REPORTED
One-offs
H1 2016 EBITDA RECURRING*
Wholesale price of electricity
Volume of electricity**
Hard coal with transport
Biomass
CO2 cost
Regulatory services
Margin on retail market
RES support***
Return on distribution****
Capitalised cost of lignite extraction
Other
H1 2017 EBITDA RECURRING*
One-offs
H1 2017 EBITDA REPORTED
76
* Recurring = excluding significant one-off items ** Including generation-related environmental costs *** Since Q3 2016 includes cost of blue certificates **** Including network losses
PLN m
3 143
2 881
3 366
3 445
TWh
Generation volume by type of fuel – 2016 Y/Y 77
53,67
37,35
11,30 5,02
55,58
38,74
11,81
5,03
TOTAL lignite hard coal other
2016 2015
2,33
0,45 0,43
1,08
0,73
2,05
0,57 0,36
0,82
1,23
nat. gas pump. hydro wind biomass
-3% -4% -4% 0%
14% -21% 19% 32% -41%
Lignite: unit 1 in Bełchatów limited to 1500 hours of work per year Hard coal: overhaul at unit 6 in Dolna Oldra Power Plant, lower utilization of units by TSO Natural gas: electricity generation in Lublin Wrotków CHP beyond the heating season, due to favorable fuel price Biomass: the RES Act reduced undedicated co-combustion support Wind: harvest from the previous year’s capacity expansion (218MW added in H2’15)
27,88
19,98
5,22 2,68
25,42
16,89
5,78
2,75
TOTAL lignite hard coal other
H1 2017
H1 2016
TWh
Generation volume by type of fuel – H1 2017 Y/Y 78
Lignite: overhaul burden at Bełchatów power plant curtailed by 8 ths hours y/y. Return of units no. 3 and 6 following medium overhauls and unit no. 10 modernised in the base period. Hard coal: overhaul burden increased by 3.8 ths hours y/y. Medium overhaul of unit 3 in Opole and units 5 and 7 in Dolna Odra. Natural gas: new gas-steam unit at Gorzów CHP commissioned in January 2017 Pumped-storage: lower demand from TSO Wind: favourable weather conditions Hydro: improvement of hydro conditions
Biomass: declining prices of green certificates hamper the economics of production
10% 18% -10% -3%
11% -31% 8% 19% -62%
1,46
0,18 0,26
0,62
0,16
1,31
0,26 0,24
0,52 0,42
natural gas pump hydro wind biomass
H1 2017
H1 2016
Capital expenditures 2016 79
Significant projects CAPEX in 2016
Opole II PLN 3 467 m
Refurbishment and modernisation in Bełchatów
PLN 518 m
Turów 11 PLN 498 m
Modernisation of distribution assets PLN 979 m
New developments in distribution area PLN 742 m
24%
52%
2%
21%
1%
68% 32%
Modernisation and maintenance New projects
Conventional Generation – new projects
Conventional Generation – modernisation, maintenance & other
Renewables Distribution Supply & other
• Capital expenditures in Conventional Generation the leading importance of the Opole II project
• The largest CAPEX in Distribution for connection of new customers and tasks around ”Medium and low voltage grid”
• Projects in renewables limited to maintenance of existing assets vs. last year intensive developments
TOTAL CAPEX
PLN 8.2 bn (-14% Y/Y)
PLN 1 721 m
PLN 144 m
PLN 108 m
PLN 4 248 m
PLN 1 931 m
Investments in generating capacities incl. Conventional Generation, Renewables and Distribution
Co
nve
nti
on
al
Gen
erat
ion
D
istr
ibu
tio
n
Capital expenditures H1 2017 80
Significant projects CAPEX
in H1 2017
Opole II PLN 1 018 m
Turów 11 PLN 129 m
Cogeneration unit in Gorzów CHP
PLN 58 m
Modernisation of distribution assets PLN 341 m
New developments in distribution area PLN 288 m
26%
47%
1%
24%
2%
66% 34%
Modernisation and maintenance New projects
Conventional Generation – new projects
Conventional Generation – modernisation, maintenance & other
Renewables Distribution Supply & other
• Continued construction of units in Opole and Turów dominates the CAPEX in Conventional Generation segment
• Distribution segment - the highest expenditures for connection of new off-takers and MV and LV power networks
• Investments in Renewables limited to maintenance of existing assets
TOTAL CAPEX
PLN 2.6 bn (-30% y/y)
PLN 629 m
PLN 28 m
PLN 1 221 m
PLN 685 m
Investments in generating capacities incl. Conventional Generation, Renewables and Distribution
Co
nve
nti
on
al
Gen
erat
ion
D
istr
ibu
tio
n
PLN 58 m
Financing and rating
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Financing model of PGE Group 82
Dividend policy and historical dividend payments 83
0,76 0,65
1,83
0,86 1,10
0,78
0,25 0,00
2,23
1,68
2,64
1,72
2,20 1,95
2.29*
1.80*
2009 2010 2011 2012 2013 2014 2015 2016
Dividend per share (PLN) Earnings per share (PLN) *EPS adjusted for impairments
Dividend policy (changed in May 2017) Distribution of profit for 2016
Because of ambitious development program, with a view to limit the increase of debt level, the Management Board recommends to suspend payment of dividend from the profit for years 2016, 2017 and 2018. After that period, the Management Board intends to recommend dividend payment at the level of 40-50% of the consolidated net profit attributable to the equity holders adjusted by the value of impairment loss on property, plant and equipment and intangible fixed assets. Each individual dividend payment will depend, in particular, on the Company’s overall debt, projected CAPEX and acquisitions. The dividend policy will be periodically verified.
The Annual General Meeting of June 27, 2017 decided to allocate the Company's entire net profit for the financial year 2016 in the amount of PLN 1,597,678,012.98 to the Company's supplementary capital.
Approx. 0.89 PLN attributed to
sale of Polkomtel
Debt development by quarters 84
Gross debt and net debt (PLN m)
• External long-term debt is mainly drawn by PGE Polska Grupa Energetyczna S.A. (the parent company) and PGE Sweden AB (Swedish SPV for Eurobonds issues). Some historical investments loans exist in PGE GiEK S.A. (Conventional Generation company)
1 586
2 706 2 405 2 522 2 718
4 660 4 802 5 045 4 811 4 822 4 838 5 409 5 414
5 945
9 467 10 014 9 837 9 760
-2 530 -2 922
-2 313
-3 031
-2 386 -1 921
-1 020 -1 018
266 462 101
2 637
4 171 4 447 4 191
5 152 5 243 4 718
-4 000
-2 000
0
2 000
4 000
6 000
8 000
10 000
12 000
Gross debt Net debt
Debt Structure and Liquidity (as at June 30, 2017) 85
Fixed vs floating debt (drawn debt)
Bank loans repayment schedule (PLN m)* Drawn Debt by currency*
* Illustrative only, assumption of full utilization of available bank loans (syndicated loan, BGK, EIB loans and EBRD loan)
Value EUR 500,000,000 EUR 138,000,000
Tenure 5 years 15 years
Maturity date June 9, 2019 August 1, 2029
Coupon 1.625% annual 3% annual
Rating BBB+ (Fitch); Baa1 (Moody’s) BBB+ (Fitch)
ISIN Code XS1075312626 XS1091799061
Issues under the EMTN program
* Including hedging transactions
0
200
400
600
800
1 000
1 200
1 400
1 600
1 800
2 000
Floating 8%
Fixed92%
Debt maturity profile 86
Debt maturity profile (PLN m) as at June 30, 2017
0
400
800
1 200
1 600
2 000
2 400
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Financing structure 87
• In order to manage liquidity and capital expenditures of the PGE Group a range of external financing instruments is used: Bonds’ programs, Investment credits, Preferential credits, Current account credits
0
1 000
2 000
3 000
4 000
5 000
6 000
BOŚ NFOiŚ NIB WFOiŚ Currentaccountcredit
Domesticbonds'
program
EMTNprogram
Syndicatedloan
BGK EIB EBRD
Drawn Undrawn
0
1 000
2 000
3 000
4 000
5 000
6 000
7 000
8 000
9 000
10 000
Current accountcredit
Bonds Credits(preferential)
External loans
Drawn Undrawn
PGE cash position provides… 88
Financial strength has been confirmed by rating agencies
… plenty
of headroom
in the balance sheet
H1 2017 Q1 2017
Gross Debt (PLN m) 9 760 9 837
Net debt (PLN m) 4 718 5 243
Net Debt/LTM EBITDA 0.61x 0.70x
Net Debt/Equity 0.11x 0.12x
MOODY’S FITCH
Long-term company rating (IDR) Baa1 BBB+
Rating outlook Stable Stable
Date of rating assignment September 2, 2009 September 2, 2009
Date of the latest rating confirmation November 2, 2016 August 5, 2016
Senior unsecured rating BBB+
Date of the latest rating change August 4, 2011
Date of the latest rating confirmation August 5, 2016
Long-term national rating AA (pol)
Date of rating assignment August 10, 2012
Date of latest rating change August 3, 2016
PGE ratings vs other Polish utilities 89
Source: Bloomberg, updated on September 5, 2017
PGE ratings vs European utilities 90
Source: Bloomberg, updated on September 5, 2017
Technical appendix
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Lignite deposits 92
Location Deposit Average value of
heat content kJ/kg
Resources as at end 2016 (mn tonnes)
Output in 2016
(mn tonnes)
Assumed decommissioning
geological industrial
Bełchatów Bełchatów Field 7,579 - 47.47 16.24 ~2020
Bełchatów Szczerców Field 7,560 - 616.11 23.94 ~2040
Turów Deposit I 9,729
- 309.85 7.50 ~2044 Turów Deposit II 9,523
Turów Deposit III 9,070
Złoczew Złoczew* 8,230 625 539
License to be granted
Gubin Gubin* 9,435-10,225** 1,087 858
* Deposits not exploited so far ** Industrial field no. 4
Conventional Generation Units (1) 93
Location Unit no.
Achievable Power Capacity
(MWe)
Achievable Thermal
Capacity (MWt)
Commissioning/modernisation
Planned decommissioning
Main fuel
Bełchatów Power Plant
1 370.0 1982 2018*
2 370.0 1983 2018**
3 380.0 1984/2008 2030
4 380.0 1984/2010 2031
5 380.0 1985/2011 2032
6 394.0 1985/2011 2032
7 390.0 1985/2012 2033
8 390.0 1986/2013 2033
9 390.0 1986/2016 2034
10 390.0 1987/2016 2034
11 390.0 1988/2014 2035
12 390.0 1988/2015 2035
14 858.0 2011 2040
TOTAL - 5 472.0 396.0 LIGNITE
* From 2016 working as a peak load, max. 1 500h/year ** Potential extension analysed
Only electricity generation units specified
Conventional Generation Units (2) 94
Location Unit no.
Achievable Power Capacity
(MWe)
Achievable Thermal Capacity (MWt)
Commissioning/modernisation
Planned decommissioning
Main fuel
Turów Power Plant
1 235.0 1998 2035
2 235.0 1998 2036
3 235.0 2000 2037
4 261.0 2004 2039
5 261.0 2003 2038
6 261.0 2005 2044
TOTAL - 1 488.0 219.0 - - LIGNITE
Opole Power Plant
1 386 1993 2036
2 383 1994 2038
3 383 1996 2041
4 380 1997 2040
TOTAL - 1 532.0 102.5 - - HARD COAL
Only electricity generation units specified
Conventional Generation Units (3) 95
Location Unit no.
Achievable Power Capacity
(MWe)
Achievable Thermal Capacity (MWt)
Commissioning/modernisation
Planned decommissioning
Main fuel
Dolna Odra Power Plant
1* 222.0 1974 2019
2* 232.0 1974 2019
5 222.0 1975 2035
6 222.0 1976 2035
7 232.0 1976 2035
8 232.0 1977 2035
TOTAL - 1 362.0 100.8 - - HARD COAL
Pomorzany CHP
1 67.1 1960 2040
2 67.1 1960 2040
TOTAL - 134.2 323.5 - - HARD COAL
Szczecin CHP
1 68.5
2000/2011 2045
TOTAL - 68.5 162.1 - - BIOMASS
Only electricity generation units specified
* Units operating under Interventional Cold Reserve scheme
Conventional Generation Units (4) 96
Location Unit no.
Achievable Power Capacity
(MWe)
Achievable Thermal
Capacity (MWt)
Commissioning/modernisation
Planned decommissioning
Main fuel
Lublin Wrotków CHP
1 155 2002 2033 Gas
2 76 2002 2033 Gas
TOTAL - 231.0 627.0 - - GAS / HARD COAL
Gorzów CHP
1 32.0 1958 2023 Hard coal
2 65.5 1999 2030 Gas
3 145.8 2017 - Gas
TOTAL - 243.3 249.4 - - GAS / HARD COAL
Kielce CHP
1 10.8 2008 2038 Coal
2 6.7 2014 2038 Biomass
TOTAL - 17.5 300.4 - - COAL / BIOMASS
Conventional Generation Units (5) 97
Location Unit no.
Achievable Power Capacity
(MWe)
Achievable Thermal
Capacity (MWt)
Commissioning/modernisation
Planned decommissioning
Main fuel
Bydgoszcz CHP EC II
(total) 183.0 627.0 1971-99/2002* 2022-37
TOTAL - 183.0 564.0 - - HARD COAL /
FUEL OIL
Zgierz CHP TG1** 16.7 1967 2022
TG2** 20.4 2014 2040
TOTAL - 37.1 111.0 - - LIGNITE /
HARD COAL
Rzeszów CHP
1 (BGP)
101.0 2003 2032 Gas
2 (BGS)
29.0 2014 2039 Gas
TOTAL - 130.0 498.3
- - GAS / HARD COAL
Only electricity generation units specified
* 2002 – Turboset no. 2 (35 MWe) retrofitted ** Only one working turbine available
RES units - wind 98
Unit Achievable
Capacity (MW) Commissioning
Kamieńsk 30.0 2007
Pelplin 48.0 2012
Żuromin 60.0 2012
Jagniątkowo (former Lake Ostrowo) 30.6 2007*
Karnice 29.9 2009*
Malbork 18.0 2007*
Kisielice 40.5 2006*
Galicja 12.0 2009*
Resko I 14.0 2013
Wojciechowo 28.0 2014
Lotnisko 90.0 2016**
Resko II 76.0 2015
Kisielice II 12.0 2016**
Karwice 40.0 2015
TOTAL 529 -
* In PGE operation from 2013 ** Licensed since beginning of 2016. First electricity generated during start-up in 2015
RES units – hydro (1) 99
Unit Achievable Capacity
(MW) Commissioning*
Dębe 20.00 1963
Tresna 21.00 1967
Porąbka 12.60 1953
Myczkowce 8.30 1962
Smardzewice 3.56 1974
Raduszec Stary 2.98 1952
Oława 3.20 2014
Grajówka 2.60 1969**
Gorzupia II 1.42 1998
Dobrzeń 1.60 2008
Przysieka 1.32 1962
Krapkowice 1.26 2007
Krępna 1.26 2004
Januszkowice 1.40 2003
Rakowice 2.00 2006
Żagań II 1.19 1963
Bukówka 0.84 1993
Zasieki 0.82 1969**
Zielisko 1.28 1969**
* Re-commissioning date applied for installation commissioned before WW II ** Acquisition date from ZE Jelenia Góra
RES units – hydro (2) 100
Unit Achievable Capacity
(MW) Commissioning*
Gubin 1.01 1957
Żagań I 0.90 1969**
Sobolice 0.65 1969**
Szprotawa 0.65 1998
Małomice 0.45 1969**
Kliczków 0.59 1994
Nielisz 0.32 1997
Żarki Wielkie 0.62 1966
Myczkowce (small hydro) 0.16 2007
Gorzupia I 0.60 1969**
TOTAL HYDRO 94.58 -
Solina 200.20 1968
Dychów 91.30 1936
TOTAL PUMPED-STORAGE
NATURAL FLOW 291.50 -
Żarnowiec 716.00 1983
Porąbka-Żar 500.00 1979
TOTAL PUMPED-STORAGE 1 216.00 - * Re-commissioning date applied for installation commissioned before WW II ** Acquisition date from ZE Jelenia Góra
RES units - photovoltaic 101
Unit Achievable Capacity
(MW) Commissioning
Żar 0.60 2015
TOTAL PV 0.60 -
Abbreviations used 102
CHP Combined Heat and Power Plant DSO Distribution System Operator ERO Energy Regulatory Office
EU ETS European Union Emissions Trading Scheme GHG Green House Gases
IEA International Energy Agency
IED Industrial Emissions Directive LTC Long Term Contracts
MSR Market Stability Reserve
NPS National Power System
NTP Notice To Proceed
ORM Operational Reserve Mechanism RAB Regulatory Asset Base
RES Renewable Energy Sources SAIDI System Average Interruption Duration Index TPA Third Party Access
TSO Transmission System Operator VLP Voluntary Leave Program
Investor Relations Team
103
Jakub Frejlich Tel: (+48 22) 340 10 32
[email protected] Mob.: +48 695 883 902
Krzysztof Dragan Tel: (+48 22) 340 15 13
[email protected] Mob.: +48 601 334 290
Filip Osadczuk Tel: (+48 22) 340 12 24
[email protected] Mob.: +48 695 501 370
Małgorzata Babska Tel: (+48 22) 340 13 36
[email protected] Mob.: + 48 661 778 955
Bernard Gaworczyk Tel: (+48 22) 340 12 69
[email protected] Mob.: +48 661 778 760
104 Disclaimer This presentation has been prepared by the management of PGE Polska Grupa Energetyczna S.A. (the “Company” or “PGE”) and other entities and is furnished on a confidential basis only for the exclusive use of the intended recipient and only for discussion purposes. This document has been presented to you solely for your information and must not be copied, reproduced, distributed or passed (in whole or in part) to the press or to any other person at any time. By attending this meeting where this presentation is made, or by reading the presentation slides, you agree to be bound by the following limitations.
This presentation does not constitute or form part of and should not be constructed as, an offer to sell, or the solicitation or invitation of any offer to buy or subscribe for, securities of Company, any holding company or any of its subsidiaries in any jurisdiction or an inducement to enter into investment activity. No part of this presentation, nor the fact of its distribution, should form the basis of, or be relied on in connection with, any contract or commitment or investments decision whatsoever.
We operate in an industry for which it is difficult to obtain precise industry and market information. Market data and certain economics and industry data and forecasts used, and statements made herein regarding our position in the industry were estimated or derived based upon assumptions we deem reasonable and from our own research, surveys or studies conducted at our request for us by third parties or derived from publicly available sources, industry or general publications such as newspapers.
This presentation and its contents are confidential and must not be distributed, published or reproduced (in whole or in part) by any medium or in any form, or disclosed or made available by recipients to any other person, whether or not such person is a Relevant Persons. If you have received this presentation and you are not a Relevant Person you must return it immediately to the Company. This presentation does not constitute a recommendation regarding the securities of the Company.
This presentation and any materials distributed in connection with this presentation are not directed to, or intended for distribution to or use by, any person or entity that is a citizen or resident or located in any locality, state, country or other jurisdiction where such distribution, publication, availability or use would be contrary to law or regulation or which would require any registration or licensing within such jurisdiction.
This presentation includes “forward-looking statements”. These statements contain the words “anticipate”, “believe”, “intend”, “estimate”, “expect” and words of similar meaning. All statements other than statements of historical facts included in this presentation, including, without limitation, those regarding the Company’s financial position, business strategy, plans and objectives of management for future operations (including development plans and objectives relating to the Company’s products and services) are forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties and other important factors that could cause the actual results, performance or achievements of the Company to be materially different from future results, performance or achievements expressed or implied by such forward-looking statements. Such forward-looking statements are based on numerous assumptions regarding the Company’s present and future business strategies and the environment in which the Company will operate in the future. These forward-looking statements speak only as at the date of this presentation. The Company expressly disclaims any obligation or undertaking to disseminate any updates or revisions to any forward-looking statements contained herein to reflect any change in the Company’s expectations with regard thereto or any change in events, conditions or circumstances on which any such statement is based. The Company cautions you that forward-looking statements are not guarantees of future performance and that its actual financial position, business strategy, plans and objectives of management for future operations may differ materially from those made in or suggested by the forward-looking statements contained in this presentation. In addition, even if the Company’s financial position, business strategy, plans and objectives of management for future operations are consistent with the forward-looking statements contained in this presentation, those results or developments may not be indicative of results or developments in future periods. The Company does not undertake any obligation to review or confirm or to release publicly any revisions to any forward-looking statements to reflect events that occur or circumstances that arise after the date of this presentation.