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

<< Back to table of contents << Back to table of contents

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

<< Back to table of contents

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*

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Turów 1-6 Turów 11 Bełchatów1-12

Bełchatów14

Opole 1-4 Opole 5-6

NOX mg/Nm3

0

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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.

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Mill

ion

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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

<< Back to table of contents

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

<< Back to table of contents

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

jakub.frejlich@gkpge.pl Mob.: +48 695 883 902

Krzysztof Dragan Tel: (+48 22) 340 15 13

krzysztof.dragan@gkpge.pl Mob.: +48 601 334 290

Filip Osadczuk Tel: (+48 22) 340 12 24

filip.osadczuk@gkpge.pl Mob.: +48 695 501 370

Małgorzata Babska Tel: (+48 22) 340 13 36

malgorzata.babska@gkpge.pl Mob.: + 48 661 778 955

Bernard Gaworczyk Tel: (+48 22) 340 12 69

bernard.gaworczyk@gkpge.pl 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.