podwyższona Tuesday, May 29, 2018 | update podtrzymana Power Utilities obniżona Poland, Czech Republic Eight Reasons Why You Should Buy Polish Utilities WIG-Energy 2,305
Polish energy stocks have sunk in recent months, and we see this as a WIG 58,330 wonderful buying opportunity. This view may go against all evidence to 2018E P/E 7.7x the contrary, including Poland’s current energy policy, which relies 2018E EV/EBITDA 4.7x heavily on investment by state companies, alongside an expected sustained rise in prices of emission allowances (EUAs), and a sector-wide dividend freeze, but we can give eight solid arguments to support our Sector Outlook position. First of all (1), a factor which we believe can create major value European electricity prices are trading at all-time for utility shareholders is the strong rebound in free cash flow expected highs after an upturn spurred by recovering prices of in the next five years, with positive effects on equity value. It is also carbon allowances and rallying energy commodities. worth noting the recent push against Poland’s nuclear project (2), which Prices on Poland are following the trend, with power contracts for next-year deliveries having crossed has no unanimous backing within the government ranks. Further, there is PLN 210/MWh. The strengthening fundamentals for potential for positive surprises if the new capacity market works better generations are expected to trigger upward earnings than assumed. Moreover, on a surprisingly sharp upturn in power prices revisions, though it is important to remember that (4), the clean-dark spreads of power generators, in particular vertically- due to hedging the current price movements will not integrated and new coal-based installations, have widened to much more boost margins until 2020. sustainable levels. At the same time, renewable energy producers are benefitting from rising prices of green certificates (5), and distributors WIG-ENERGY vs. WIG may see WACC raised next year (6). Note that the WIG-ENERGY index at the moment is trading at an EV/EBITDA ratio 20% below its 3-year 4,000 average, showing a 50% discount to Stoxx Utilities (7). Last but not least, Polish utilities offer sound financial positions (8) evidenced by the pts fact that if they were to offer a 5% dividend yield their net debt would not have to rise more than 5% (0.1x EBITDA). 3,500
European utilities rise on higher energy prices Electricity prices in Germany have rebounded nearly 30% from their February 3,000 lows, driven by a 13% increase in the prices of coal, combined with a 25% surge in the prices of natural gas and a 60% upturn in the prices of EUAs, triggered by the planned reform of the EU Emissions Trading System (ETS). Accordingly, even as treasury yields widen, the EURO STOXX Utilities index has outperformed the 2,500 broad market by a margin, gaining 6%. WIGENE
Polish utilities yield to political pressure... WIG The WIG-ENERGY index is down 25% year to date, crumbling under the 2,000 uncertainty created by the Polish Energy Ministry and its various public plans for very capital-intensive projects, including a nuclear power station, that,
unfortunately, do not make much sense from a business point of view, and look
Feb-18
Aug-17
Nov-17 May-18 potentially prejudicial to the interests of the minority shareholders of state-owned May-17 companies. The Polish power sector has become a toxic asset in the eyes of investors, who at the moment tend to overreact on any hint of bad news fir the sector while mostly ignoring any good news.
...even as fundamentals strengthen Were it not for politics, Polish utilities would be moving firmly upward right now, Target Price Rating buoyed by improving market conditions, including the upward-trending power Stock new old new old prices on the local market, and regulatory changes which boost the earnings outlook of renewable energy producers and distributors. Our belief is reflected in CEZ* 458.38 449.51 sell sell the fact that our 2019 earnings forecasts for the sector are 7% higher than the ENA 12.62 11.78 buy buy consensus forecasts. It is also important to note that, as the end of a long investment cycle in the power sector nears, Polish generators can be expected to ENG 15.58 14.91 buy buy achieve much stronger cash flows in the next five years, with the OCF surplus set PGE 13.60 12.89 buy buy to increase to a projected PLN +11bn in 2018-2022 from PLN -8bn in 2014-2017. TPE 2.76 2.73 buy hold New capacity mechanisms Current Target Upside/ Stock Expectations as to the positive effects of the capacity market and new Price Price Downside mechanisms for cogeneration and renewable capacity payments rare low creating CEZ* 551.00 458.38 -16.8% room for positive surprises. Capacity auctions in our view can generate an extra PLN 1.2bn a year for the power sector. On top of that, free cash flows over the ENA 9.57 12.62 +31.9% next decade might be boosted by investment incentives in the form of free EUA ENG 9.00 15.58 +73.1% allocations budgeted at EUR 4-5 billion. PGE 9.28 13.60 +46.5% P/E P/CE EV/EBITDA P/B TPE 2.01 2.76 +37.5% Company 2018E 2019E 2018E 2019E 2018E 2019E 2017 *CZK prices, otherwise all PLN prices CEZ 20.8 19.3 6.9 6.6 8.5 8.1 1.2 Enea 4.6 3.5 1.8 1.6 4.0 3.5 0.3 Analyst: Energa 4.7 4.5 2.0 2.0 3.4 3.3 0.4 PGE 5.7 5.6 2.7 2.6 3.5 3.3 0.4 Kamil Kliszcz +48 22 438 24 02 Tauron 2.7 3.3 1.2 1.2 3.8 4.3 0.2 kamil.kliszcz@mbank.pl
Contents
1. Market Update ...... 3 1.1. Central Europe –Germany & Czech Republic ...... 3 1.2. ETS Reform Rundown ...... 4 1.3. Polish Market Update ...... 5 2. Expectations For the Capacity Market ...... 8 3. Status of Ostrołęka C Project ...... 11 4. The Polish Nuclear Project ...... 11 5. The Czech Nuclear Project ...... 12 6. Cogeneration Incentives ...... 12 7. Enea's Coal Gasification Project ...... 13 8. Coal Prices Bounce Back ...... 14 9. Distribution Update ...... 16 10. Renewables Update ...... 17 10.1. Green Certificates ...... 17 10.2. Changes in Renewables Legislation ...... 18 10.3. Revival of Offshore Wind Projects ...... 18 10.4. PGE's Takeover Bid On Polenergia ...... 19 11. Trade Profits Normalize ...... 19 12. Energa's Court Fight With Wind Farms ...... 21 13. Improving FCF ...... 21 14. SOTP Analysis ...... 21 15. Performance ...... 22 16. Relative Valuation Charts ...... 26 17. mBank Forecasts vs. Analysts' Consensus ...... 28 18. CEZ Valuation Update ...... 29 19. Enea Valuation Update ...... 36 20. Energa Valuation Update ...... 43 21. PGE Valuation Update ...... 50 22. Tauron Valuation Update ...... 57
2
Market Update There were no major developments last year when it comes to CEE cross-border trade, with Germany and the Czech
Republic both remaining net exporters. Germany's Central Europe – Germany & Czech trade balance was stable in 2017 as higher local demand Republic soaked up all extra production. The planned split of the Germany/Austria pricing zone in October 2018 can shift the German electricity consumption continued to increase balance in the coming years, but it is hard to predict to what for the third year straight in 2017, but at 0.8% after an extent. 0.1% rise in 2016 the recovery from the pullback of 2011- 2014 is still ongoing. This despite an acceleration from 1% Net electricity exports from Germany (TWh) to 3.4% in the annual growth rate of local industrial 60 production, offset by slow-rising demand from other sectors (services, transport, and households account for 55% of 50 total power consumption in Germany). 40 Similarly, a stronger 2017 manufacturing momentum failed 30 to boost demand for electric power in the Czech Republic, 51.8 53.7 54.0 with usage up a mere 1.5% versus 2.2% the year before. 20 The sluggish rise in power consumption can be blamed in 33.8 35.6 23.0 part on milder weather, but another part of the equation if 10 17.7 the universal a push toward better energy efficiency in light 14.3 6.3 of rising power costs. 0
2010 2011 2012 2013 2014 2015 2016 2017 Adding to the consumption squeeze observed in both 2009 Germany and the Czech Republic is a flattening of Source: AGEB household demand (with per-capita usage in both countries now close to the EU average). The 1.1% rise in German power generation last year was overwhelmingly led by renewable energy (wind Against this backdrop, our long-term prediction is that +34%, solar +4%), supported by beneficial weather annual growth in power consumption in the CEE region conditions and a 3-4% increase in installed capacity, while will hover in the 0%-2% range. conventional plants generated lower volumes due to capacity shutdowns (nuclear -10%, hard coal -16%, brown Growth in electricity usage vs. industrial production coal -1%). in Germany and the Czech Republic German electricity production by source (GWh) 7% 6% Germany 6% 600 4% 96 99 99 5% 95 500 39 38 40 4% 36 2% 57 79 77 3% 400 103 59 60 78 2% 0% 82 300 109 107 1% 101 85 -2% 200 0% 92 87 80 72 -1% -4% 100 144 143 139 138 -2% 0 -3% -6% 2014 2015 2016 2017
Lignite Nuclear Hard Coal NatGas
4Q 12 3Q 13 2Q 14 1Q 15 4Q 15 3Q 16 2Q 17 1Q 12 Wind Solar Other Industrial production (lhs) Power consumption (rhs) Source: Bloomberg
10% 6% With weather conditions even better so far this year, Czech Republic German wind farms and solar parks produced 23% 8% and 14% more power, respectively in the first FOUR 4% 6% months of 2018, and with the nuclear energy volume up 22% from a low year-ago base hard coal (-21%) and 4% 2% natural gas (-21%) have been have been pushed out 2% of the merit order (the displacement of conventional is 0% additionally reinforced by planned closures of gas-based 0% capacity and a shift of lignite capacity to the reserve). -2% -2% The cost-competitiveness of coal-fired power in recent -4% months has been undercut by an upturn in prices of -6% -4% carbon allowances and coal (bringing the clean-dark spread in 2019 into the negative territory), with no signs of
a turnaround in the foreseeable future given the shift
4Q 12 3Q 13 2Q 14 1Q 15 4Q 15 3Q 16 2Q 17 1Q 12 towards cleaner energy, and the pending reform of the EU's Industrial productiton (lhs) Power consumption (rhs) emissions trading mechanism (ETS).
Source: Eurostat, AGEB, BDEW, ERU The extent of German power overproduction is best illustrated by the ratio of installed capacity to average consumption, currently at 2.3x, or at a still-high 2.1x
3
after adjustment for the planned closure of 9.5 GW of ETS Reform Rundown nuclear capacity in 2022. This compares to a Polish multiple of 1.6x. Peak power demand in Germany ranges The key themes of the planned overhaul of Europe's carbon between 72 and 79 GW depending on the season, and market can be summarized as follows: during that time coal is often allowed back in the merit order ▪ From 2019, part of the excess EUAs in the EU ETS will to fill the gaps, with the role of gas-fired installations set to be backloaded to the Market Stability Reserve (MSR) diminish further in the years ahead after already decreasing provided the surplus exceeds 833 million allowances (at its share in total production from 14.5% to 13.2% in the last the end of 2016 it stood at 1,694 million). In 2019-2023, eight years. the backloaded EUAs will be equivalent to 24% of year
t-2 surplus, followed by a reduction to 12% in 2024- Installed capacity by source (GW) and scheduled 2030. This on top of already backloaded EUAs, which will shutdowns and startups of conventional capacity also be transferred to the MSR (300 million in 2019 and (MW) in Germany 600 million in 2020), and unused EUAs sitting in the New Installed Capacity Entrant Reserve (currently at 336 million, expected to
200 29 34 decrease to 300 million by the end of 2020). 28 29 30 ▪ From 2024, any surplus of EUAs in the MSR over the 40 41 43 49 previous year's total auction volume will be permanently 150 38 cancelled. 45 50 51 100 39 60 ▪ The linear reduction factor (LFR) will be reduced from 1.74% in 2013-20 to 2.2% in 2021-30, decreasing EUA 28 29 30 30 23 supply from 48 to 38 million. 50 26 28 28 25 23 ▪ The ETA overhaul, assuming EU carbon emissions 12 11 11 10 8 21 21 21 21 17 decrease at the annual rate of 1.2% forecast by 0 Sandbag, in the base-case scenario should reduce 2014 2015 2016 2017 2020P the EUA surplus from 1.7 to 0.8 billion tonnes by 2024. Lignite Nuclear Hard Coal NatGas The following chart shows the base-case reduction Wind Solar Other scenario vis-à-vis for our EUA price forecasts. 2000 Forecast of EUA surplus (mmt) and prices (EUR/t) 1000 2400 30 0 2000 25 -1000 1600 20 -2000 1200 15 -3000
-4000 800 10
-5000 400 5
0 0
2016 2017
2018P 2019P
Closures Additions
2009 2010 2011 2012 2013 2014 2015 2016 2017
2008
2019P 2020P 2021P 2022P 2023P 2024P 2025P 2026P 2018P Source: BnetzA, BDEW, Netztransparenz EUA surplus (lhs) EUA price (rhs)
When it comes to prices, the main trends shaping the Source: Sandbag, estimates by Dom Maklerski mBanku European electricity markets in the coming years will be movements in energy commodities and emission ▪ In a scenario where EU emissions decrease by 2.8% a allowances (EUAs). We assume coal and natural gas will year (the "low-emissions" scenario) which is not maintain their long-standing correlation to crude oil, and as unlikely given the efforts towards clean power and for EUAs their prices will most likely rise further after greater energy efficiency, the EUA surplus would the planned ETS overhaul. decrease much less to a target 1.6 billion in 2024 from 1.7 billion today: German electricity prices (EUR/MWh) vs. EUA prices (EUR/t) Forecast of EUA surplus in base-case vs. low- emissions scenario 48 16 2400 44 14 2000 40 12 10 1600 36 8 1200 32 6 800 28 4 400 24 2
20 0 0
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
2018P 2019P 2020P 2021P 2022P 2023P 2024P 2025P 2026P
Jul-14 Jul-15 Jul-16 Jul-17
Jan-14 Jan-15 Jan-16 Jan-17 Jan-18
Oct-14 Oct-15 Oct-16 Oct-17
Apr-15 Apr-16 Apr-17 Apr-18 Apr-14 Base-case surplus Low-emissions scenario EUA price (rhs) EEX 1Y contract (lhs) Source: Sandbag, estimates by Dom Maklerski mBanku
Source: Bloomberg, estimates by Dom Maklerski mBanku
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▪ Sectors less exposed to carbon leakage (including Polish Market Update district heating systems), and those at the highest risk of relocating production outside the EU, will receive free Polish electricity consumption is tied closely to EUA allocations of 30% and 100%, respectively, until manufacturing growth because the two main consumer 2026. groups are small manufacturers and low-voltage ▪ Ten eligible EU member states, including Poland and commercial operations, which over the last five years the Czech Republic, are allowed to offer up to 40% (or increased usage by 18.1% and 9.2%, respectively. 60% under a "solidarity" fund consisting of unused Household power consumption is seen to converge to EU EUAs) of their auctionable EUAs for free to their local averages, and although in 2017 it unexpectedly fell 2.2%, it energy producers as investment incentives. Details is expected to regain modest momentum going forward are forthcoming, but as a rule energy efficiency- (CAGR in the last two years was 0.4%) considering that promoting projects worth more than EUR 12.5m will take today's per-capita usage represents only 48% of the part in free EUA auctions, with the free allocation capped EU average. at 70% of each project's cost. ▪ Poland's free EUA pool under the derogation rules has Projection of electricity consumption vs. GDP growth been set at 0.27-0.4 billion, worth EUR 3.6-5.3bn at for Poland current prices, and the Czech Republic can hand out 7.5% 0.11-0.17 billion free allowances with a current value of 6.0% EUR 1.4-2.2bn. For comparison, note that the current capitalizations of Poland's largest utilities 4.5% are less than EUR 7bn. Even with an allowance for 3.0% the accumulation of state aid rule this amount can 1.5% significantly boost the sector's FCF. 0.0% ▪ The EU plans to set up a modernization fund, fueled by proceeds from sales of 2.0-2.5% of total EUAs, to -1.5% help further energy projects to the exclusion of coal- -3.0% based installations. Consisting of 0.31-0.39 billion EUAs, -4.5% the fund's budget at current prices would be about EUR
4-5bn.
1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
2019P 2020P ▪ We have revised upward our 2018-2020 price forecast 2018P for emission allowances by an average 40% to reflect Growth in power consumption Growth in GDP the planned reduction of oversupply and the recent Source: PSE, GUS, P – projections by Dom Maklerski mBanku upward shift in current EUA prices. Yearly power consumption is significantly influenced by the European Price Forecast Update weather, which was the main reason behind the modest acceleration in usage to an annual rate of 2.1% in 2017 Assuming coal prices edge slightly upward in 2019, and despite much faster economic expansion. stabilize at a slightly lower level in subsequent years, and taking into account rising EUA prices, we have raised our Based on a 1.9% y/y rebound in usage recorded in the year 2018-2021 projections for German power prices by 11%. to date, curbed by a cold March, our prediction for 2018 At the updated level the forecast prices are 2% lower than is for a further acceleration to 2.2% in the annual the current EEX forward curve because of lower assumptions power consumption assuming no major temperature as to EU prices (EUR 15/t in 2021 vs. EUR 16/t on the spot anomalies in the rest of the year. market). Beyond 2018, assuming progress in EU convergence and Our price forecast vs. EEX forward curve (EUR/MWh) continued economic expansion at the official forecast rate of 44 3.3% in 2019-2021, power consumption is projected to increase at an annual rate of 1.6%. 40 Monthly electricity usage in Poland (GWh)
36 -1.1% +6.7% 2016 2017 2018
32 15,000 +3.0% -0.9% 28 13,000
24 11,000
20 9,000
7,000
2018P 2019P 2020P 2021P mBank forecast Current EEX price 5,000
Source: Bloomberg, estimates by Dom Maklerski mBanku
July May
April
June
March
August January
October
February
December November
September
Source: PSE
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When it comes to supply, the Polish energy mix has been The changing merit order puts pressure on clean dark undergoing a change over the last few years, reflected in spreads (CDS) on coal-fired electricity, but the pressure a steady decline in the share of hard coal-based is not as great as foreseen by some. Per our calculations, in installations (down to 48% in 2017 from 57% in 2010), 2017, CDS in year-ahead contracts decreased 5% to PLN alongside a rise in the share of wind farms (up from 1% to 48/MWh, and this year it may shrink by a further 7%. over 8.4%), which do date have replaced about 13TWh of conventional energy in the merit order. Reliance on hard Until recently we thought 2020 could see the spread slump coal is set to decrease further in 2018, though the change more sharply (-20%) with the launch of two large new coal- versus 2017 will be less dramatic due to high wind energy based plants, but at the current POLPX prices the implied production last year, combined with planned closures of spread is close to or higher than the one set in 2018 lignite-fired installations, the launch of a new 1000 MW hard contract.We have raised our 2019 CDS forecast to PLN coal-fired facility, and recent additions of natural gas-fired 46/MWh, implying a 4% increase from 2018. This will generators. benefit vertically-integrated generators and operators of high-efficiency installations with Polish electricity production by source variable costs almost PLN 40/MWh lower. 4M'1 4M'1 (TWh) 2016 2017 Y/Y Y/Y 8 7 Electricity prices after carbon vs. 2018 hedge* Utility power 140.7 141.8 1% 48.0 48.8 -2% 150 plants 145 thermal power plants, 138.3 139.0 1% 46.9 47.9 -2% 140 incl. 135 hard coal 81.3 79.9 -2% 27.5 27.7 -1% 130 brown coal 51.2 52.0 2% 16.0 18.0 -11% 125 natural gas 5.8 7.2 24% 3.3 2.2 52% 120 hydropower 2.4 2.8 15% 1.0 1.0 9% 115 Captive 10.1 10.1 -1% 3.6 3.7 -3% power plants
Renewables 11.8 14.0 19% 4.5 4.8 -7%
Oct-15 Oct-16 Oct-17
Jun-16 Jun-17
Apr-16 Apr-17 Apr-18
Feb-16 Feb-17 Feb-18
Dec-15 Dec-16 Dec-17
Aug-16 Aug-17 Total 162.6 165.9 2% 56.0 57.3 -2% Electricity price adj. for CO2 2018 hedge
Source: PSE *Weighted average 1Y FWD 2018 contract price adjusted for the average price of carbon allowances in 2017 Polish generators faced increased competition from Source: Estimates by Dom Maklerski mBanku cross-border imports in 2017 (with the trade balance at -2.3 TWh in volumes and -3.3 TWh in trade) due to better Polish electricity prices have outperformed German prices and greater activity on the German border. The prices since the beginning of the year, reflected in a negative balance could widen this year versus a lower 2017 widening spread, as they caught up with rising prices of Q1 comparable base, when a nuclear outage in France sent carbon while the German counterpart came under pressure spot prices in Western Europe higher, increasing the from falling prices of coal. Coal prices in Poland display a attractiveness of Polish electricity. Statistics for the first built-in inertia vis-à-vis ARA quotes because most buyers four months of 2018 already show a close to 2 TWh order their deliveries a year in advance. At the current level, increase in net imports over the comparable year-ago the official price quotes for thermal coal are still lower period. The average daily imports from January to April than at ARA (PLN 10.6 vs 12.4/GJ). The PL/DE spread is approximated 1 GW gross and 0.7 GW net. From 2019, the additionally reinforced by Poland's capacity mechanisms total cross-border import capacity will be 1.8 GW, and its (the 'ORM' operating reserve of 3,540 MW and the 'IRZ' cold future growth will be decided by the government. Current reserve), which cut into commercial supply and hike up plans are for interconnectors with Ukraine and Germany, set wholesale prices. The 2018 budget for ORM payments was to add raised by PLN 30m to PLN 570m. We estimate very roughly 2 GW to the import capacity, after plans for a second link to that the various capacity payments add between PLN Lithuania have been scrapped. 15-16 and PLN 18 to the price of a megawatt hour in wholesale. It is important to keep in mind when Net electricity exports from Poland (TWh) considering Poland's limited import capabilities that our 12 11.0 capacity reserve is immeasurably smaller than Germany's.
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8 5.4 6 5.2 4.5 4 2.8 2.2 1.4 2 0.7 0.3 0.1 0
-2 -2.2 -2.0
-4 -2.3 -2.3
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 4M 2017 4M 2018 Source: PSE, Dom Maklerski mBanku
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Poland vs. Germany electricity price spread If we add the potential maintenance closures of major (1Y fwd contracts, PLN/MWh) installations (1-3 GW in total) to permanent shutdowns 220 60 through 2021, budgeted at 2.8 GW, the conclusion is that 200 50 the most recent capacity additions to the tune of 6 GW 180 40 are just enough to close the gap in the grid, and their impact on the operating rates of existing generators may be 160 30 limited. The new installations should put pressure on 140 20 the prices of electricity due to their higher efficiency 120 10 (which at the current levels could roughly bring down the 100 0 costs of coal and emissions by as much as 80 -10 PLN 37/MWh), but this pressure has not materialized so far, 60 -20 more than five months since the launch of a 1,075MW generator last December by Enea. We have nevertheless
tried to factor the impact of more efficient installations into
Jul-13 Jul-14 Jul-15 Jul-16 Jul-17
Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18
Oct-13 Oct-14 Oct-15 Oct-16 Oct-17
Apr-14 Apr-15 Apr-16 Apr-17 Apr-18 Apr-13 our price forecasts for 2020, by assuming contraction of spread Price in Poland Price in Germany PLN 3 in profit margins per megawatt hour ("clean Source: POLPX, Bloomberg dark spread").
In theory, the supply pressures faced by the Polish Net clean dark spread projection for new and power grid should ease in the coming years as planned existing coal-based power generators (PLN/MWh) new power plants come on line (see the following diagram). 90 In 2019, the benefits of new capacity will be tempered by the planned closure of several obsolete plants, but by 2020 80 the capacity reserve will become noticeably higher. The 70 prospective changes in the merit order may have, however, 60 a limited impact on the wholesale prices, first of all due 50 to the introduction of a capacity market with a bridge mechanism (the assumptions for the capacity market are 40 presented in more detail further in the report), and second 30 of all, due to the intensified repair downtimes connected 20 with the process of adjustment to BAT/BREF conclusion 10 requirements and a potential overhaul of 200 MW 0 currently under consideration. With new emission caps not 2015 2016 2017 2018P 2019P 2020P set to enter into force before August 2021, power plants still have 3.5 years for adjustment. Assuming roughly that the CDS, old installations CDS, new installations bulk of the 28 GW of installed coal-based generation Source: Projections by Dom Maklerski mBanku capacity requires retrofitting, and the average downtime per generator is three months, this would imply that Poland As for prices, we have revised our forecasts for 2019 may be facing annual capacity gaps as high as and 2020 upward by an average 17%, in line with the 2,000MW each year in the period from 2018 to 2021. expected rise in prices of carbon allowances. From 2021, This not taking into account the possible full overhauls of we predict that a fully-functioning capacity market, and 200 MW units, which experts say will take 24 months in each the resulting discontinuation of the operating reserve, will case. If 30 out the 54 generators were to be shut down for put a dramatic squeeze on electricity prices, to the tune retrofit, this would mean the loss of an additional 1,000MW of PLN 17/MWh. of generation capacity each year between 2018 and 2030.
Forecast of wholesale electricity prices in Poland With all that said, the current overhaul schedule versus POLPX market prices (PLN/MWh) administered by Poland's grid operator PSE does not provide for this extent of maintenance closures. As of 220 November 2017, the capacity set for closure in 2018 210 and 2019 was only 500-900 MW higher than in 2017, 200 but PSE sent out another survey to generators at the 190 beginning of 2018, which means an update is forthcoming. 180 Projection (eop) of Poland's available capacity 170 reserve (ex. rapid BAT/BREF retrofit) (MW)* 160 6,500 150 6,000 140 5,500 130 5,000 2019P 2020P 2021P 4,500 Projected price POLPX price 4,000 Source: POLPX, projections by Dom Maklerski mBanku
3,500 3,000 2,500
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
2007
2019P 2020P 2021P 2018P *the diagram accounts for the loss of the capacity already shifted to the cold reserve in 2016 (physically these generators will be shut down in 2019, but commercially they are no longer in use) Source: Projections by Dom Maklerski mBanku
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The implications of these projections on the earnings of Power prices (ex. carbon) for a lignite-fired power listed power utilities (euro EBIDA per megawatt hour) are plants as follows: 150 145 Projection of unit EBITDA from generation (incl. 140 heat, renewables, and mining, EUR/MWh) 135 30 130 125 25 120 20 115 15 110 10
5
Oct-15 Oct-16 Oct-17
Jun-16 Jun-17
Apr-16 Apr-17 Apr-18
Feb-16 Feb-17 Feb-18
Dec-15 Dec-16 Dec-17 Aug-17 0 Aug-16 Source: POLPX, Dom Maklerski mBanku, CEZ ENEA ENERGA PGE TAURON
2016 2017 2018 2019 2020 ▪ TAURON is eyeing higher margins this year thanks to high spot power prices and higher revenue from the cold Source: Dom Maklerski mBanku reserve. In 2019 margins will be stable, and in 2020 despite an expected downshift in power price we ▪ CEZ faces contraction in the unit generation margin in anticipate further earnings growth fueled by a new coal- 2018 from a high year-ago base due to lower allocation based installation. of free EUAs. However, the total core EBITDA will probably be slightly higher than last year thanks to a Projection of renewable energy as a pct. of total mix higher nuclear power output. In 2019-20 we anticipate 45% improvement on rising sales prices, new capacity, and 40% acquisitions of renewable energy installations. 35% ▪ ENEA is trying to cool the market's expectations as to 30% 2018 generation profits, but we are confident it will 25% improve earnings this year thanks to rising green 20% certificate prices and an increasing operating rate at 15% the recently completed 1000 MW plant. In 2019, we 10% anticipate further acceleration thanks to continuing rises 5% in prices of electricity and coal, underpinned by increasing plant availability and vertical integration with 0% the LWB coal mine. 2020 might see tighter margins amid CEZ ENEA ENERGA PGE TAURON less favorable macro conditions. 2015 2016 2017 2018 2019 2020 Source: Dom Maklerski mBanku Power prices (ex. carbon) for a 45% coal-fired power plant 180 Expectations For the Capacity
170 Market
160 The Polish Parliament passed the legislation paving the way 150 for the establishment of a capacity market mechanism in December 2017. The key objectives of the new marketplace 140 can be summarized as follows: 130 ▪ The timeline: May 29th, 2018, marks the end of a 120 certification process for all Polish generators over 2MW.
In June we expect to learn the particulars of this year's
Oct-15 Oct-16 Oct-17 Jun-17
Jun-16 capacity auctions (including the estimated demand, the
Apr-16 Apr-17 Apr-18
Feb-16 Feb-17 Feb-18
Dec-15 Dec-16 Dec-17
Aug-16 Aug-17 price caps, the slope of the demand curve, the capital Source: POLPX, Dom Maklerskio mBanku expenditure thresholds for new and refurbished capacity, and the limits on imported capacity). The dates ▪ ENERGA is set to see a slight uptick in margins in 2018 of the three main 2018 auctions, for deliveries in 2021, led by renewables, offsetting downward pressure from 2022, and 2023, are November 15th, December 5th, and coal-based capacity. In 2019 unit EBITDA will rebound December 21st. thanks to higher prices of power and green certificates ▪ The cost to consumers: The capacity market will be coupled with relatively high renewables volumes. In financed by end power consumers via a capacity charge 2020, our assumptions as to production and wholesale incorporated in the transmission tariff. In our baseline prices indicate a narrower margin. scenario for capacity charges, we assume that the fee ▪ PGE's earnings this year are not comparable to last per megawatt hour for end users will average year's due to the acquisition of EDF in November 2017. PLN 30–32 (experts assessing the impact put the cost at We assume lower coal-based volumes, higher costs of PLN 34-35 for households and PLN 29 for businesses coal, and lower EUA allocations. In 2019, PGE will benefit except for the heavy industry), partly offset by an from a slightly wider spread in coal and improved expected PLN 17 drop in wholesale prices and the availability, partly offset by declines in cogeneration. In elimination of operating and cold reserve surcharges 2020 PGE faces a tighter CDS on brown coal coupled (PLN 4-5), with the net charge not likely to exceed with a lack of free EUAs while their prices continue to PLN 10/MWh (1.7% of the current average household bill rise. and 3% of the bills of commercial consumers).
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▪ No tiered pricing: The original idea to apply tiered Projection of demand and supply at 2021-2024 pricing in capacity auctions has been abandoned, but capacity auctions (GW) generators are to be grouped by existing, refurbished, 2021P 2022P 2023P 2024P and new installations, subject to different contract 25 lengths of one year, five years, and fifteen years, respectively. The categorization will be based on capital 20 expenditures in the five years prior to the first delivery (or from January 2014 for the first auction in 2018). The 15 CAPEX requirements are forthcoming, but the expectation is for minimum eligible CAPEX of 10 PLN 3.0m/MW for new installations, and PLN 0.5m/MW 5 for refurbished installations. ▪ DSR capacity: The capacity market mechanism 0 includes participation from certified demand-side
response (DSR). In 2016, the Polish grid operator PSE
supply supply supply supply
demand demand demand had at its disposal 182 MW of DSR capacity, and in 2017 demand the available capacity was 361 MW during summer time Reduced installatons Capacity contracts and 315 MW during winter time. This year, PSE ordered Demand (ex. imports & DSR) PLN 500MW of DSR capacity with a budget of PLN 215m, Source: Projection by Dom Maklerski mBanku and looking at the bids this will be the extent of DSR participation this year. ▪ Capacity payments: Even with dates already set ▪ Imports: Foreign generating units are allowed to enter for the first auctions this year, there is no way to the Polish capacity market on the basis of ticket auctions predict how much Polish generators stand to gain in via cross-border interconnectors or through direct hard currency from the capacity market. For this participation in auctions. Their caps will be established reason we are providing a reiteration of the on an annual basis based on ENTSO-E adequacy calculations of a year ago, which do not factor in the forecasts. The first auction for foreign generators will be expected fall in wholesale power prices. held in 2020, for deliveries in 2025, but interconnector ▪ UK leads the way: At the four auctions held in the capacity will be eligible for 2021-2024 auctions. Poland's UK so far since the introduction of the capacity import capacity may increase from the current 1.8 GW market, the prices in zlotys at the first three ranged to 3.8 GW in 2025. from PLN 104,000 to PLN 120,000 per MW, but this ▪ Demand forecasts: The complex formula for year's auction cleared at a dramatically low price of forecasting demand for capacity auctions per our ca. PLN 40,000, removing any incentive to invest, calculations indicates that auction orders in 2021 may be and triggering calls for a reform. for 20.9 to 22.3 GW, rising to 21.4-22.8 GW in 2024. ▪ Overheads vs. cold reserve payments: According to our estimates, a marginal power plant in the merit Projected demand forecast at 2021 capacity auction order incurs average overhead of ca. PLN (GW) 1Q 2Q 3Q 4Q 200,000/MW per year against cold reserve capacity Peak demand 28.5 24.9 25.6 28.3 payments of roughly PLN 180,000 budgeted for Installed cogeneration capacity -6.0 -2.0 -2.0 -6.0 2018. ▪ Return guarantees: The amount of yearly state Installed renewable capacity -3.1 -2.7 -1.6 -3.7 support needed to ensure neutral NPV of a new coal- DSR -0.5 -0.5 -0.5 -0.5 based generator at the current clean-dark spread is Interconnectors -1.2 -1.2 -1.2 -1.2 PLN 350,000/MW. Reserve (10% of peak demand) 2.8 2.5 2.6 2.8 ▪ Impact on consumers: The Energy Ministry estimates the impact of the capacity market on end Reserve (15% of peak demand) 4.3 3.7 3.8 4.2 electricity consumers at PLN 3.2 billion (after taking Demand (10% reserve) 20.6 21.1 22.9 19.8 into account the expected decrease in wholesale Demand (15% reserve) 22.0 22.3 24.2 21.2 prices), implying an annual cost of PLN 140,000- Source: Projection by Dom Maklerski mBanku 150,000/MW depending on auctioned volumes. ▪ Mock auction outcomes: A mock auction in May ▪ Supply at first auction: Poland's installed coal-based 2017 by Deloitte and Energoprojekt-Katowice for generation capacity was 34.75 GW in December 2017. year-one power deliveries based on draft legislation Adjusted for non-eligible capacity, planned capacity (4.8 planned at the time cleared at the following prices: GW through 2021), and planned closures PLN 332,000 per MW for new capacity, PLN 187,000 (-2.8 GW), this leaves about 30 GW of capacity that can per MW for refurbished capacity, and PLN 113,000 be put up for auction. After adjustment for an 83% per MW of existing capacity. Note that the original availability factor, year-one supply decreases to about bill has been amended since. 25 GW, implying 15% oversupply relative to the demand forecast. In the future, we anticipate increasing demand In our calculations of possible future capacity payments, we coupled with closures of non-BAT compliant units. decided to continue to use the Deloitte simulation after a According to PSE, approximately 20% discount and assuming a PLN 17 drop in the wholesale 2.7 GW of capacity will be taken off line in 2020-2030, per-MWh price. We will be able to update our models once but this should be compensated for by new units the parameters of the upcoming auctions become public, provided the planned projects are put into effect. and after planned new capacity volumes are established in the first auction.
9
Projection of 2024 revenues from capacity payments 2017 revenue from capacity payments (incl. cold and 2024 decrease in net operating reserves) installed capacity wholesale EBITDA (PLN m) capacity revenue price boost (MW) Enea 104 Enea 5,066 792 -509 284 Energa b/d Energa 1,042 200 -117 83 PGE* 611 PGE 11,028 1,882 -1,408 474 Tauron 206 Tauron 3,784 648 -326 322 *incl. EDF Poland Source: Companies, estimates by Dom Maklerski mBanku Total 20,920 3,522 -2,360 1,162 ▪ Impact on consumer behavior: Large commercial Source: Estimates by Dom Maklerski mBanku energy consumers might want to shift peak usage to off- ▪ Accumulation of state aid vs. free emissions: Under peak hours or build captive power plants to save on EU rules, state aid allocated as part of the capacity energy bills after the introduction of the capacity market. market mechanism is cumulative in that it adds to any In the long term, this could potentially lead to tightened aid received in previous years, such as the free emission peak-base spreads and idle capacity. allowances granted in 2013-2020. This calls for the ▪ Balancing market pricing: The Polish government application of an adjustment factor for each installation promises to abolish all price restrictions in the balancing which benefitted from free allowances in the past market from 2021 to allow for a better reflection of the (payment per 1MW=auction price of 1MW/year-state demand/supply balance (the right signals and incentives aid/(generation capacity*years duration of the capacity for market participants). Balancing based on marginal contract). We have summarized the free emission prices will result in big price volatility, affecting the allowances received by Polish utilities in the following predictability of the revenues of peakload units, and table. The last column shows the size of the state aid increasing portfolio risks for traders. relative to the “old” capacity that can be put up for auction. Assuming annual capacity payments of PLN Winter Package Update 190,000/MW, the utilities would have to pay back between one and two annual payments to the old fleet. EU member states agreed on certain aspects of the However note that the cumulative aid rule applies only proposed “Clean and Secure Energy for All to allowances granted to an installation as incentive to Europeans” at the end of 2017, including the upgrade; aid does not have to be returned where the postponement to 2030 of restrictions as part of the capacity free emissions were a reward for other investment (e.g. market mechanism on generators with emissions higher distribution networks). In this context, PGE with its large than 550 g CO2/kWh. The final version of the co-called distribution CAPEX finds itself in a relatively comfortable “winter package” is to be passed by early 2019, which position. At the other end is Tauron, which invested the means the new rules will not affect the terms of Polish bulk of the eligible money in generation capacity and capacity auctions. The ongoing discussion on the extent might have to return part of the free EUAs (we assume of the future emission restrictions, however, is sure to 75% of 2013-20 allocations). dampen sentiment for Polish utilities in the coming months.
Free emission allowances allocated in 2013-2020 Million Value PLN 1,000/MW put BAT Upgrades
tonnes (PLN m) up for auction* Enea 36.1 994 182 Under the BAT reference documents published last August, Polish utilities have until 2021 to comply with the Best Energa 8.2 233 342 Available Techniques and reduce their emission rates to PGE 181.7 5173 495 the required levels. The total cost to the industry is Tauron 42.9 1130 349 estimated at PLN 10-11 billion, of which only about PLN 4 billion attributed to listed power generators ZEPAK 7.0 198 151 (the rest has to be spent by district heating networks). This *Value of state aid divided by estimated “old” capacity eligible to take part in capacity auctions implies an average cost per MW of Source: Estimates by Dom Maklerski mBanku PLN 0.2-0.5 million, which might not be enough to fulfill the upgrade caps under the capacity market, suggesting the ▪ Impact on merit order: The introduction of the stringent BAT requirements might be deemed not capacity market will cause medium-term changes in the economically feasible. The current plans of the listed merit order by increasing the share of gas installations utilities as regards total investment in BAT with lower overheads than coal-based generators. This compliance are as follows: PGE+EDF PLN 1.9bn, Enea should support prices on the wholesale market. PLN 0.5bn, Tauron PLN 0.9-1.0bn, but some of the ▪ Discontinuation of availability payments: The utilities have already spent a portion of their respective introduction of the capacity market entails the budgets. The four-year compliance deadline is tight, and discontinuation of the cold reserve and other “rent”-type assuming most of the 28.5 GW total Polish coal-based availability payments. capacity has to be upgraded, necessitating downtime of three months each, the grid might be facing an annual capacity shortfall of 2,000 MW in 2018-2021 (not yet reflected in official maintenance schedules). The tighter supply can have a positive effect on wholesale prices. The oldest installations have to keep in mind the next BAT review, expected around 2027, and they might decide to go over and above the current requirements in planning the upgrades for the next four years.
10
2018 Operating Reserve Budget Sensitivity analysts of Ostrołęka C’s NPV to electricity prices* and capacity payments Raised By PLN 30m Electricity Price
-1 056 160 180 205 250 300 350 The operating reserve that Poland’s TSO wants to have at its disposal in 2018 is 18% of the average peakload demand, 140 -3,814 -2,651 -1,338 787 3,141 5,495 i.e. 18% x 24.3 GW= 4.4 GW adjusted for 160 -3,700 -2,538 -1,241 879 3,233 5,587 830 MW set aside in the cold reserve, making for 3.54 GW 180 -3,587 -2,424 -1,148 971 3,325 5,679 on auction this year. The price cap is PLN 42.6 (vs. PLN 41.8 in 2017 auctions, in the end cleared at PLN 36.6 200 -3,474 -2,313 -1,056 1,062 3,417 5,771
PLN/MWh). The total annual operating reserve budget Capacity payments (PLN 1,000/MW) 220 -3,361 -2,203 -965 1,154 3,508 5,862 has been raised by PLN 30m this year to PLN 570m. *After the expiration of the capacity market (during the payments period the price drops by PLN 20/MWh) Source: Estimates by Dom Maklerski mBanku Status of Ostrołęka C Project The Polish Nuclear Project The following is a status update and NPV study on the
“Ostrołęka C” 1,000 MW coal-based power plant project, Poland’s nuclear power plant project, first announced in which is owned 50-50 by the two listed state utilities Enea 2009, seems to be gaining momentum under the leadership and Energa. of Energy Minister Krzysztof Tchórzewski, however his
vision for the project, in particular as regards its financing, ▪ The SPV formed by Enea and Energa to manage the for now looks vague and not backed by any official policy, project selected as the general contractor a giving rise to confusion and uncertainty which weighs on consortium of GE and Alstom Power based on a price market sentiment for Polish utility stocks. The latest state of quote of PLN 5.05 billion net, implying a cost per MW of play as of this writing can be summarized as follows. PLN 5.05m, consistent with the historical averages paid ▪ The owner of the nuclear project is PGE EJ, an SPV in earlier projects. After adjusting the cost upward by set up in 2010, controlled by the state utility PGE with a 15-20% to reflect inevitable overbudget, we arrive at 70% stake, and co-owned by 10% stakeholders KGHM, total net capital expenditures on the Ostrołęka C project Enea, and Tauron. The initial budget of PGE EJ on a pro- of PLN 6 billion. rata basis is PLN 1bn. Its capital is ca. ▪ The selection of general contractor has yet to be PLN 340m. approved by both supervisory boards, and both sets of ▪ One of the two potential locations of the future power shareholders have to give their go-ahead for the stations currently under consideration is expected to be project. These decisions will probably not be made until picked in 2019-2020. after Ostrołęka C wins the first capacity auction in December and secures the financing. Otherwise, Enea ▪ An official go ahead for the power station is expected and Energa will have to consider scrapping the project to be given this year, however the process might be put altogether. The companies have capped the initial off until after local government elections in October. expenditure up to the time a go-ahead is given to start According to the media, proponents of nuclear power construction at PLN 450m, of which about PLN 200m has might have to wait for a better time. already been spent. ▪ PGE has been considered to be the nuclear project’s lead ▪ With capacity of 1,000 MW and a load factor of 75%, until recently, when the state refiner PKN Orlen was Ostrołęka C can generate 6.6 TWh of electricity a year reported to have expressed an interest in getting with an efficiency of 46%. Its annual coal usage is involved, while PGE focuses on building offshore wind projected at 2.5mmt, and its emissions will approximate farms. PKN later denied these reports, revealing a lack 0.69t/MWh. of enthusiasm for the nuclear project on the part of any of the rumored leads. ▪ Energa signed a 10-year coal supply contract with the state miner PGG in December 2016 on behalf of ▪ The planned capacity of the nuclear power plant, as well Ostrołęka C. The 2mmt-a-year volume will be priced as its size, cost, and timing, have changed frequently depending on the new generator’s profitability, and the over the past years, but per the latest statements by pricing formula provides that the parties will share any Minister Tchórzewski his vision might be for an capacity payments and free emissions. Further details installation with 3.0-5.0 GW of nuclear-sourced are not available at this point, but the price formula generating capacity, to be finished by 2040 (with 1.0- secures at least a portion of the future power plant’s 1.5 GW coming on line by 2030) at a cost of PLN 70-80 clean-dark spread. Much depends on whether PGG will billion (EUR 3.7-4.2m/MW). According to Minister be willing and able to subsidize Ostrołęka C’s coal fuel Tchórzewski, the plant should be financed by its state- during times of weaker profits. owned stakeholders, preferably from their own internal cash resources and without the use of expensive debt. ▪ The following is calculation of the net present value of In another interview, the Minister suggested any bank Ostrołęka C depending on changes in power prices and financing could be coordinated with the plant’s capacity payments. It assumes a constant coal price of amortization period, i.e. 60-80 years. PLN 11/GJ, and a fixed CO2 price of EUR 14/t. In the base-case scenario, built into our valuation models for ▪ Looking at nuclear projects in other parts of the Enea and Energa, the NPV is approximately PLN -1.1 world, which are nearing completion, ventures like this billion in total, or PLN -0.53 billion each with LTV will inevitably fall behind schedule and go over budget. assumed at 70%. The average cost of these projects (see table below) at EUR 6m per megawatt is significantly higher than the EUR 4m envisioned by Minister Tchórzewski, who is probably not taking into account capitalized costs, which can inflate the original budget by as much as 30%. Further, the duration of each of these projects has averaged ten years, which would put Poland on a very tight schedule if it is to finish the first reactor by the 2030
11
deadline. The levelized costs of electricity (LCOE) of the 65bn, equivalent to 23% of its current market cap. benchmark installations for 7% WACC is EUR 60-90 or According to our calculations, renewables and PLN 250-380 per megawatt hour compared to the PLN distribution account for about 44% of CEZ's annual 200 LCOE assumed tentatively by Poland. EBITDA. Assuming proportional division of debt after the spin off the renewables business would have to be Nuclear projects across the world: an overview valued at 9.5x 2017 EV/EBITDA if the interests of
,
, minority shareholders are to be protected. This is a
,
, realistic assumption looking at the valuations of similar
ia
II
enterprises, but given the potential state-held share
, UK overhang it might be viewed as aggressive.
USA
C
France
Finland
Paks
Slovak Hungary Based on the little we know about the nuclear project
Hanhikivi ▪
Mochovce,
Watts Bar 2
Hinkley Point Flamanville 3 and CEZ's involvement in it, assuming no help from the Capacity (GW) 0.9 2.4 1.2 3.2 1.6 1.2 state, CEZ stands to have CZK 35bn shaved off its value per 1 GW (EUR 42/MWh power, CAPEX @EUR CAPEX (EUR bn) 5.4 12.5 6.8 24.1 10.5 6.7 5.5m/MW, WACC 7%), equivalent to 13% of the current CAPEX (EUR/MW) 5.73 5.21 5.63 7.53 6.56 5.76 market cap. At these levels the project would not break Launch 2019 2027 2024 2025 2018 2015 even at less than EUR 80 per megawatt hour of power.
Duration (years) 11 10 11 9 11 9 NPV of a 1GW nuclear reactor depending on Source: Estimates by Dom Maklerski mBanku electricity price and LTV (CZK bn) Electricity price (EUR/MWh) ▪ For the Polish nuclear project, assuming a constant -35 35 37 42 45 50 60 power price of PLN 205/MWh, and assuming bank debt will account for 70% of the total financing (PLN 23bn 0% -59.7 -58.0 -53.9 -51.4 -47.3 -39.1 total CAPEX), with 90% load factor, 7% WACC, and 5% 30% -51.7 -49.9 -45.6 -43.1 -39.0 -30.7 cost of debt, we estimate today’s net present value per LTV 50% -46.7 -44.8 -40.3 -37.6 -33.4 -25.2 1 GW at a negative PLN 4.7bn. The NPV does not turn positive until the assumed electricity price is more than 70% -41.7 -39.8 -35.2 -32.4 -28.0 -19.6 PLN 350/MWh, a level close to the upper end of the LCOE 80% -39.2 -37.3 -32.6 -29.9 -25.4 -16.9 limit calculated for the projects nearing completion in Source: Estimates by Dom Maklerski mBanku Europe. In the baseline scenario, four 1GW reactors could generate negative NPV of nearly PLN 19bn for the Planned Incentives For High- power sector. NPV of a 1GW nuclear reactor depending on Efficiency Cogeneration electricity price and LTV Electricity Price ▪ The Polish Energy Ministry finally came out with draft legislation in March to replace the expiring support -4 920 160 180 205 250 300 350 scheme for combined heat and power plants with 0% -9,333 -8,692 -7,890 -6,447 -4,843 -3,240 a new scheme. After a final round of consultations, the 30% -7,994 -7,332 -6,530 -5,087 -3,484 -1,880 Ministry hopes the bill will be passed by the end of June. The framework proposed in the draft legislation LTV 50% -7,160 -6,457 -5,624 -4,181 -2,577 -974 (not likely to change much in the final version) can be 70% -6,335 -5,618 -4,749 -3,274 -1,671 -67 summarized as follows: 80% -5,924 -5,203 -4,324 -2,821 -1,217 386 ▪ To be eligible for the program, combined heat and Source: Estimates by Dom Maklerski mBanku power plants (CHPs) have to agree to feed 70% minimum of their heat output into district heating The Czech Nuclear Project (the incentives available to captive CHPs will be proportional to their supplies to district heating). The Czech government is still in the process of studying ▪ Support for new and repowered installations will various options for financing its nuclear project. Currently come in the form of pay-as-bid auctions for premium the state utility CEZ operates four 1.9 GW nuclear tariffs. Auctions will be technology- and capacity specific generators in Dukovany, built in 1985-87 and licensed (with grouping into natural gas fuel, solid fuel, and other through 2035, and two generators 2 GW generators built in and by three capacity range of 1-5MW, 5-20MW, and 20- 2000-03 and licensed through 2020-22, with options to 50MW). Plants with less than 1 MW of installed capacity extend to 2050-60, in Temelin. The plan for the nearer will receive guaranteed premiums, plants over 50 MW future is to build two new generators in Dukovany which will be considered on a case-by-case basis, and plants could replace the existing installations in 2035. In the more over 300 MW will have to obtain permission from the distant future new generators might also be built in Temelin. European Commission to partake in the scheme. Support ▪ The government appointed a special panel to come up will be given for a period of 15 years. The auction with a financing formula for the project by the end of budgets and maximum bids will be set by the Energy 2018. The two leading ideas are for CEZ to build the new Ministry. installations with its own cash plus possibly some form ▪ Support for existing and upgraded installations will of backing from the state, or for CEZ to spin off and hand come in the form of premiums paid on top of the market over to the state a dedicated vehicle which will lead the prices of electricity, varying depending on capacity and project. technology used, offered for the remainder of the ▪ CEZ has put forth a proposal for its split into two units, original 15-year support period since the allocation of one grouping conventional generation, trading, and the first CHP (or "yellow") certificates. The payments will mines, to be taken over by the state, and the other be subject to adjustments for age (with older CHPs consisting of renewable energy assets, in which the receiving less money). For installations undergoing government would take a 51% stake. CEZ estimates that upgrades, the support period can be extended by three the split could generate additional value as high as CZK to seven years depending on CAPEX as a proportion of CAPEX needed for a greenfield CHP.
12
▪ Financing for the scheme will come from a special Enea's Coal Gasification Project cogeneration fee set by the energy regulator, and included in the transmission tariff. Assuming 3 GW of Enea is the only Polish utility that is still considering new cogen capacity, the cost to the state is estimated at investment in coal gasification (IGCC) technology. The PLN 1.6-2.0bn max (PLN 13-16/MWh to end users). leading option under consideration which has emerged from Payments to existing CHPs are planned at ca. studies conducted to date is a 300-500 MW IGCC plant PLN 0.9bn in 2019, and in subsequent years they will with a 60% capacity factor located in the vicinity of the LW decrease in line with expiring support periods and in line Bogdanka coal mine. The cost depending on technology with adjustments for the age factor. This compares to used is estimated in the range of 2018 subsidies in the form of cogeneration certificates of EUR 2.4-4.0m/MW (EUR 0.7-2.0bn total) compared to ca. PLN 1.56bn (PLN 12.6/MWh to end users). The total EUR 0.8m/MW for a gas-fired installation. Using the spread additional cost of the new system to consumers is between the generation cost of a megawatt hour of coal- projected at PLN 7-10/MWh (1.3%-2.9% of current based energy versus natural gas-fired energy (see diagram energy bills). below), production of gas fuel from coal is not likely to ▪ Model assumptions for new installations: The start making financial sense in the near future, though ministry has presented two alternative sets of in the long term it could become more profitable depending assumptions for the calculation of the potential costs of on prices of carbon allowances and coal. Even at the low end the auction system for new capacity. Below are the main of the per-MWh cost range (EUR 2.4m), the spread at which parameters for >50 MW gas-based cogeneration an IGCC project would break even would have to be EUR (current support for these types of sources is equivalent 30/MWh (vs. EUR 7/MWh now), not likely to be achieved to almost 75% of the system costs). The main with just higher emissions prices, but only through a sharp differences between the baseline and conservative fall in coal prices relative to natural gas prices (this spread option are CAPEX: PLN 4.15m v. peaked in early 2014 at EUR 27/MWh). All in all, we do PLN 4.25m/MW and power prices: PLN 190 v. not expect Enea to move forward with the high-risk PLN 165/MWh. The first option implies a premium of PLN IGCC project in the foreseeable future. 104/MWh for gas cogeneration, and the second option implies a premium of PLN 134/MWh. We have also made Cost per 1 MWh of coal vs. natgas-fired energy a calculation using current prices of electricity, natural (EUR/MWh) gas, and emissions, assuming the support foreseen in 60 the baseline option. 50 IRR estimate for a >50MW cogeneration project using state-recommended options and current 40 energy prices 30 Option I Option I Option II (draft (current (draft 20 proposal) prices) proposal) 10 availability factor 83% 83% 83% load factor 45% 45% 45% 0
CAPEX (PLN m/MW) 4.2 4.3 4.3
Jul-13
Jan-11 Jan-16
Oct-14
Jun-11 Jun-16
Apr-12 Apr-17
Feb-13 Feb-18
Mar-15
Dec-13 Sep-17
Power price (PLN/MWh) 190 210 165.1 Sep-12
Aug-15
Nov-11 Nov-16 May-14 Carbon price (PLN/t) 38.2 63.0 38.2 Spread NatGas Coal
Natgas price (PLN/MWh) 103.7 102.0 103.7 Source: Bloomberg, estimates by Dom Maklerski mBanku Support (PLN/MWh) 104 104 134 Cost of debt 5% 5% 5% LTV 70% 70% 70% IRR 6.7% 8.9% 7.3% Source: Estimates by Dom Maklerski mBanku
▪ The calculations above indicate that the assumed returns on the new projects are close to the regulatory levels of returns on capital set for distribution (currently 6.02%). This does not make for a generous incentive given the profile of risks in generation compared to network investment, but keep in mind that the CAPEX assumptions in the calculations above (PLN 4.15- 4.25m/MW vs. PLN 3.6m/MW in recent large projects in Płock and Włocławek), and the fixed-cost assumptions (PLN 200,000/MW vs. sector average of PLN 180,000/MW) are quite conservative. Support for existing installations under the new mechanism is set to decrease 30-40% relative to the current revenues from cogeneration certificates, and the utility which stands to be hurt the most by this is PGE which in 2017 generated revenue from yellow and red certificates of PLN 0.3bn (or PLN 0.40-0.45bn including EDF CHPs, representing 5-6% of EBITDA). For others, cogeneration payments account for a marginal portion of annual EBITDA.
13
Coal Prices Bounce Back On Tighter The United States increased coal production in 2017 to capitalize on higher prices, and the 8% higher output Supply resulted in a surge in exports. This year local producers have already curbed output by 6% compared to last year, Prices for European year-ahead coal have rebounded including due to decreasing demand from the domestic to $90/t after a downward correction to $70/t. The power sector (forecast at -4% by the EIA), not offset by futures curve has started to show contango for the first time increasingly milder emission restrictions. since 2016, indicating that the market is no longer pricing a structural oversupply. US coal production and usage (YoY change)
ARA coal price ($/t) 30% 100 20%
90 10%
80 0%
70 -10%
60 -20%
50 -30%
40 -40%
30
Jul-14 Jul-15 Jul-16 Jul-17
Jan-14 Jan-15 Jan-16 Jan-17 Jan-18
Oct-14 Oct-15 Oct-16 Oct-17
Apr-14 Apr-15 Apr-16 Apr-17
Jul-14 Jul-15 Jul-16 Jul-17
Jan-14 Jan-15 Jan-16 Jan-17 Jan-18
Oct-14 Oct-15 Oct-16 Oct-17
Apr-15 Apr-16 Apr-17 Apr-18 Apr-14 Production Consumption
Source: EIA ARA spot ARA 1Y FWD
Source: Bloomberg Russia has also reduced exports in recent months, with monthly shipments from October 2017 to April 2018 only It is not clear if China will remove the restrictions 3% higher on average than in the comparable year-ago placed on domestic coal production and imports. Prices period compared to increases of 14% registered between registered a sharp increase in the second half of 2016 after January and October 2017. With that said, data for March a 9.5% drop in domestic coal output in the wake of volume and April indicate that Russian mines are starting to respond caps, coupled with a 40mmt surge in imports. Prices to rising ARA prices. remained stable throughout 2017, but in the first quarter they embarked on an upward trend again after a 16% y/y Russian coal exports (mmt) rise in imports. Recently some Chinese ports have been 18 reported to have imposed curbs on incoming coal shipments as a way of boosting local prices, with imports in April 16 expected to be as much as 20% lower than the January- March average as a result. This is bound to affect global 14 prices considering that China accounts for more than a half of world coal consumption. The consensus for the whole 12 year is that prices might register a small dip versus 2017 as a 3% rise in local production will be accompanied by a 1.7% 10 uptick in demand. With that said, we believe local supply is 8 conditioned on global prices hovering in the $70-80 range. 6 China coal production and imports (mmt)
1200 80
Oct-13 Oct-14 Oct-15 Oct-16 Oct-17
Jun-13 Jun-14 Jun-15 Jun-16 Jun-17
Feb-14 Feb-15 Feb-16 Feb-17 Feb-18 Feb-13 1100 70 Source: Bloomberg
1000 60 Coal prices are also shaped by the markets for substitute 900 50 fuels, especially natural gas. Henry Hub prices at the moment are 35% above their five-year average, and the 800 40 price of a thermal unit from coal is slightly higher. US prices 700 30 dictate prices in Europe, which are not likely to move much higher from the current levels under these circumstances. 600 20 What could push prices further, however, are current trends in oil prices and speculation about increased gas exports 500 10 from the US to China. Summing up, our baseline scenario
assumes stable ARA prices kept in check by marginal costs
2Q 13 3Q 13 4Q 13 1Q 14 2Q 14 3Q 14 4Q 14 1Q 15 2Q 15 3Q 15 4Q 15 1Q 16 2Q 16 3Q 16 4Q 16 1Q 17 2Q 17 3Q 17 4Q 17 1Q 18 1Q 13 of increasing supply in the coming years. By 2020 seaborne coal demand is expected to increase by nearly 50mmt, but Production (lhs) Imports (rhs) the extra supply will come mainly from Indonesia and Source: Bloomberg possibly the US. For now, most major producers say they are keeping investment in check and plan to keep volumes at stable levels.
14
Spot ARA prices vs. US natgas prices The lag inherent in Polish coal prices is slowly disappearing, with the tighter supply and rising ARA prices starting to 200 influence prices agreed for forward deliveries to power 180 plants. An index tracking the prices at which thermal 160 power plants, which have greater exposure to spot prices, order their coal fuel, shows a 20% rebound in the 140 average bid compared to a rise of 10-15% so far 120 reported by electricity generators.
100 ARP coal price index for electricity vs. heat 80 generators 60 12.5 12.0
11.5
Jul-14
Jan-12 Jan-17
Oct-15
Jun-12 Jun-17
Apr-13 Apr-18
Feb-14
Mar-16
Dec-14
Sep-13
Aug-16
Nov-12 Nov-17 May-15 11.0 10.5 ARA rice ($/toe) US gas price ($/toe) 10.0 9.5 Source: Bloomberg 9.0 8.5 Trends in the Polish coal market are shaped by shifts in 8.0 global markets, but with a lag stemming from the fact that 7.5 most supplies are fixed under long-term contracts indexed
to ARA benchmarks, or alternatively to domestic electricity
Jul-14 Jul-15 Jul-16 Jul-17
Jan-14 Jan-15 Jan-16 Jan-17 Jan-18
Oct-14 Oct-15 Oct-16 Oct-17
Apr-15 Apr-16 Apr-17 prices or official quotes for thermal coal. Local factors have Apr-14 kept prices rising higher last year thanks to tightened supply Heating plants Power plants after a wide-reaching overhaul of the Polish coal industry Source: Polish Industrial Development Agency (ARP) which resulted in the closure of several mines. In 2016 Polish coal production was 3% or 2mmt lower than in the We expect the Polish coal market to solidify its correlation previous year, and in 2017 it fell by a further 7% or 5mmt, with the global market going forward amid a stabilizing of which 4mmt represented by thermal coal. This coincided demand/supply balance which weakens the impact of local with steady demand from utility power plants, resulting in factors. We predict that demand for coal from utility power an undersupply and depletion of domestic coal reserves plants will remain stable at 35-36mmt a year. to the lowest level in ten years. Demand for coal from Polish power utilities Polish coal inventory (mmt) (TWh) ‘16 ‘17P ‘18P ‘19P ‘20P 10 Coal-based energy 80.2 79.1 80.5 83.4 82.3 9 8 "Old" installations 80.2 79.1 73.9 72.2 59.2 7 "New" installations 0.0 0.0 6.6 11.2 23.1 6 Coal usage (mmt) 35.4 35.0 35.1 36.0 34.6 5 Source: Estimates by Dom Maklerski mBanku 4 3 Production of thermal coal should also remain stable all 2 things considered, with PGG continuing to improve its 1 financial standing as shown in the following table. 0 2018 earnings forecast for PGG
(PLN m) 2016* 2017 2018P
Jul-07 Jul-08 Jul-09 Jul-10 Jul-11 Jul-12 Jul-13 Jul-14 Jul-15 Jul-16 Jul-17
Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Revenue 5,631 7,946 8,921 Source: ARP Coal output (mmt) 24.0 30.0 30.5
Poland's largest coal producer, the state-owned PGG, Revenue per tonne 235 265 292 missed its production target last year by about 3mmt Payroll costs 2,358 3,159 3,474 because of financial struggles. This year, PGG is confident it Headcount 31,560 42,283 42,283 can meet the 30.5mmt target with a CAPEX budget raised to PLN 2.6bn from PLN 1.8bn spent in 2017, as coal prices Avg. salary 6,225 6,225 6,848 increase. Other cash costs 2,691 2,788 2,976
Unit cash cost (PLN/tonne) 112 93 98 Thermal coal production in Poland EBITDA 582 2,000 2,470 (million metric tons) 2016 2017 2018P EBITDA per tonne (PLN) 24.3 66.7 81.0 LWB 9.0 9.1 9.0 Net income -332 86 467 PGG 24.0 30.0 30.5 CAPEX 597 1820 2558 KHW 9.0 - - *ex. KHW JSW 5.3 4.1 4.1 Source: Estimates by Dom Maklerski mBanku Tauron 6.4 6.5 6.0
Others 3.6 3.4 3.4
Total 57.2 53.0 53.5 Source: Companies, estimates by Dom Maklerski mBanku
15
We assume the Polish price of thermal coal will average Polish 10Y bond yields PLN 10.5/GJ in 2018, trading virtually on a par with European prices. In future years, we expect prices to 4.0% stabilize at a slightly higher level above PLN 11/GJ, with rising prices of carbon emissions and China’s import 3.5% restrictions potentially curbing the uptrend relative to other energy commodities (oil and gas). 3.0%
Coal prices in Poland vs. ARA (PLN/GJ) 2.5%
16 5 2.0% 15 4 14 3 1.5% 13 2
12 1
Jul-15 Jul-16 Jul-17
Jan-15 Jan-16 Jan-17 Jan-18
Mar-15 Mar-16 Mar-17 Mar-18
Sep-15 Sep-16 Sep-17
Nov-15 Nov-16 Nov-17
May-16 May-17 May-18 11 0 May-15
10 -1 Source: Bloomberg 9 -2 8 -3 The outlook for 2018 looks good for Polish power 7 -4 distributors thanks to a raised risk-free rate (6.01% vs. 6 -5 5.63% in 2017), and faster growth in regulated assets (PLN +2.2bn or +4.3%), which, combined, could add over PLN
0.3bn to the aggregate EBITDA for the year. The actual
Jul-13
Jan-11 Jan-16
Oct-14
Jun-11 Jun-16
Apr-12 Apr-17
Feb-13 Feb-18
Mar-15
Dec-13
Sep-12 Sep-17
Aug-15
Nov-11 Nov-16 May-14 boost might be lower, however, given the regulator’s aggressive assumptions as to volumes, with Energa spread ARP PLN/GJ ARA 1Y PLN/GJ potentially missing the target now that its former customer,
Source: ARP, Bloomberg, Dom Maklerski mBanku PKN Orlen, has built its own power supply. In addition, network losses could go up this year due to high spot power prices (assumed at PLN 172/MWh this year in the regulatory Distribution Update tariff meanwhile the YTD spot average is PLN 187/MWh).
Polish power distributors generated aggregate So far, the utilities in our coverage seem to be on track adjusted EBITDA 5% (PLN 0.2bn) higher in 2017 than to achieving our 2.1% EBITDA growth scenario for in the previous year, driven by investment in regulatory 2018 after increasing the aggregate earnings by PLN 65m assets (with the RAB of the four listed distributors up by or 3.2% in the first quarter. 3.9% or PLN 1.9bn year over year to PLN 51.1bn). After a small reduction in WACC the benchmark return on assets Analysis of 2019E Distribution EBITDA sensitivity to increased by PLN 90, and it accounted for 40-45% of the risk-free rate EBITDA growth. The other drivers included a 2.9% rebound Risk-Free Rate
in volumes and a reduction by an average 8% of costs of network losses. 3.00% 3.25% 3.50% 3.75% 4.00%
ENEA 1,112 1,134 1,156 1,179 1,201 Historical and projected returns on network assets (adj. EBIT/RAB) EBITDA ENERGA 1,687 1,722 1,756 1,790 1,824 PGE 2,329 2,375 2,420 2,466 2,511 8%
2019E TAURON 2,424 2,471 2,519 2,566 2,613 7% Source: Estimates by Dom Maklerski mBanku
6% As for 2019 outlook, assuming the benchmark riskfree rate approaches 3.3% at the end of September 2018, WACC will 5% be kept unchanged next year. The average 18-month bond yield is currently 3.4%, but yields in the past month 4% were in the range of 3.0%-3.4%. This reassures us in our assumptions, especially with interest rates increasingly 3% likely to remain unchanged this year. Accordingly, we delay 2015 2016 2017 2018P 2019P expectations of a WACC hike to 6.3% to 2020 (risk free benchmark 3.5%). With RAB growth expected to be slower ENEA ENERGA PGE TAURON WACC (PLN +1.5bn in 2019, Source: Companies, P –projections by Dom Maklerski mBanku PLN 1.2bn in 2020), Distribution EBITDA cannot be expected to show dynamic shifts in the coming years. The actual returns vary from the returns implied by the formula (EBIT=RABxWACC) on a case by-case basis, but in 2017 only Energa showed a noticeable positive deviation from the average due to the delayed launch of a captive facility by the refiner PKN Orlen, shifts in billing, and a slightly higher WACC on certain assets. PGE deviated on the downside due to differences in amortization.
16
Power supply reliability rates for Poland case at 2% of revenue there might be a dent in EBITDA of up to 5.3%. On a case by case basis, the negative impact SAIDI 2015 2016 2017 would be 2.2% Enea, 4.2% Energa, 1.8% PGE, and 3.5% 700 Tauron. Maintenance of interrupted quality and further 600 reductions in the quality indicators will become a greater challenge in 2020. 500 400 Free cash flow vs. RAB: Distribution business* 3.5% 300 3.0% 200 2.5% 100 2.0% 0 1.5% ENEA ENERGA PGE TAURON 1.0%
0.5% SAIFI 2015 2016 2017 6 0.0% -0.5%
5
2016 2017
2019P 2020P 2021P 2022P 2023P 4 2018P ENEA ENERGA PGE TAURON 3 *EBITDA-tax-CAPEX Source: Companies, P –projections by Dom Maklerski mBanku 2 Future cash flows from distribution will differ greatly 1 between the different utilities depending on planned capital investment. At PGE and Tauron, FCF yield (EBITDA less 0 CAPEX and tax as a percentage of regulatory assets) is ENEA ENERGA PGE TAURON expected to normalize at 3%, while Energa will not Source: Companies, P –projections by Dom Maklerski mBanku reach that level until 2023, the year when Enea might achieve FCF yield of 1.5% after a period of ramped-up The 2018 distribution tariff for the first time includes expenditures. a quality tariff (based on 2016 quality indicators). The targets for Polish utilities is to reduce the SAIDI and SAIFI values by 50% from 2014 to 2020 and to cut time to grid. Renewables Update The Q factor can be used to adjust returns on RAB by up to 15% per year or by a factor equivalent to 2% of regulated Green Certificates revenue depending on the extent of violation. With all utilities fulfilling the requirements in 2018, the Q factor in Polish renewable energy certificates (RECs) rebounded the 2018 tariff is 1.0. In 2019, however the factor could last year after an increase in the redemption requirement increase after weather-induced interruptions experienced and a changed formula for calculating the substitution fees during 2017 by virtually all power suppliers. Companies are paid in place of RECs. From 2018 this parameter is 125% of currently negotiating force majeure allowances with the the average REC price for the prior year (i.e. 125% x PLN regulator. 38.3 = PLN 47.8/MWh). However REC prices on the POLPX exchange despite a high surplus have been lifted well above SAIDI – planned outages that limit (to PLN 70/MWh currently and a 200 PLN 80 all-time high) because of an inability to pay substitution fees and speculative buying. Assuming stable REC prices, the 2019 model substitution fee would be 150 PLN 84/MWh, creating a loop in the market game which encourages spot purchases.
100 Polish REC prices (PLN/MWh) 250 50 200
0 ENEA ENERGA PGE TAURON 150 2014 2015 2016 2017
Source: Companies 100
Enea is the only utility to disclose its grid connection statistics in the format requested by the regulator, but 50 based on available data we believe both Enea and PGE are able to easily fulfill the requirements. 0
All in all, the quality regulations are not expected to
Jul-15 Jul-16 Jul-17
have much influence on the future profits of Polish Jul-14
Jan-14 Jan-15 Jan-16 Jan-17 Jan-18
Oct-14 Oct-15 Oct-16 Oct-17
Apr-15 Apr-16 Apr-17 Apr-18 Apr-14 power generators unless the regulator does not agree to a Source: POLPX compromise as regards force majeure-led outages, in which
17
In the context of financing renewable energy via the Historical and projected renewable energy auction capacity market mechanism, the supply of RECs in will be volumes stable through 2019, and start to decline in 2020 as the Auction Source Capacity GWh ~MW support periods comes to an end. By then prices will start to Dec-16 solar < 1MW 1,567 70 be shaped by demand, which in turn will depend on energy consumption by end users. According to our calculations, Dec-16 biomass < 1MW 825 10 the whole REC surplus should disappear by 2021. Dec-16 hydropower < 1MW 417 21 Accordingly, we assume a linear increase in prices to PLN Jun-17 solar < 1MW 4,721 200 100/MWh in 2022 (the maximum level set in legislation is PLN 300/MWh). Jun-17 hydropower < 1MW 312 16 2018 wind, solar < 1MW 16,065 489 REC production vs. demand (TWh) 2018 wind, solar > 1MW 45,000 1370 25 150% 132% 126% 2018 biogas, biomass < 1MW 25,011 317 121% 115% 117% 2018 biogas, biomass > 1MW 61,209 776 20 103% 120% 2018 hydropower < 1MW 3,750 190 87% 85% 95% 2018 hydropower > 1MW 5,400 274 15 77% 78% 90% 73% 68% Source: URE, P – projections by Dom Maklerski mBanku
10 60% Polish legislators are working on further concessions for future wind farm capacity projects, as well as planning 5 30% auctions for renewable capacity, with the 2018 targets looking quite ambitious given the dramatic drop in clean energy investment in Poland in the last two years. It 0 0% is estimated that small and large wind farms and solar farms
will be able to sell about 1.7 GW of new capacity (the
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
2019P 2020P 2018P maximum price for wind is PLN 350/MWh, and for solar it is Cogeneration Wind PLN 400/MWh), with a further 1.0-1.5 GW to be ordered Biomass Hydropower from hydropower plants and biogas and biomass installations (of which there are few). The change of policy Other Supply as % of demand Source: URE, p – projections by Dom Maklerski mBanku on the part of the Polish government in respect to renewable energy might result in greater support in the future. This trajectory will have a varying impact on different utilities due to their differently sized renewables capacity. Revival of Offshore Wind Projects Our calculations are summarized in the following table, which shows that Enea and Energa stand to be the two Investment in offshore wind energy ground to a halt about biggest beneficiaries of the reversal in the trend on two years ago in the wake of various obstacles created by REC prices. the Polish government to hinder new capacity additions, but as the national energy policy shifts away from coal investors Projected change in 2018-2020 renewable revenues are preparing to resurrect previously shelved projects. Renewable Energy Revenue Change 2017 in as a % Based on valid concessions, the wind turbine capacity Total RECs Revenue current of ▪ prices EBITDA* that might be built off the Baltic shore by 2030 is Enea 2.3 1.9 447 601 4.1% 6 GW. Energa 1.5 0.7 284 368 3.7% ▪ The first 600 MW wind farm, planned by Polenergia, could be ready by 2022. PGE has plans to bring PGE 2.5 1.6 481 635 2.0% 1 GW of wind capacity online by 2025. Tauron 1.3 1.1 259 346 2.4% ▪ PGE estimates the cost of a 1GW windfarm at *including higher costs of biomass PLN 12-14bn or EUR 2.8m-3.3m/MW, one-third of which Source: Estimates by Dom Maklerski mBanku are costs of connection to the grid. According to
calculations by WindEurope, the average wind farm Changes In Renewables Legislation CAPEX in 2017 was EUR 3m/MW, but new projects in Denmark and the Netherlands are priced at Poland has introduced a number of changes to its EUR 2.7m/MW. Note that as reference turbine capacity renewable energy laws in recent months to ensure is scaled up from 8 MW to 10 or even 12 MW, the costs better compliance with EU requirements. We have of building a wind farm will decrease by as much as committed to increase the renewables share from 11.3% in 15%-20% (according to BVG Associates). 2016 to 15% in 2020, but according to Ecofys we can reach ▪ Wind farms in Poland are eligible for state auctions 13.8% max by the deadline, which would be subject to fines where the reference feed-in tariff is currently set at as high as EUR 1bn a year under so-called statistical PLN 350/MWh. This compares to LCOE for wind farms transfers. currently launched in Europe of PLN 460/MWh (EUR 110-120/MWh), expected to decrease well below EUR EUR/MWh (Borselle EUR 73/MWh, Vesterhav EUR 64/MWh, Horns Rev EUR 95/MWh) by 2020 to as low as EUR 50/MWh (Kriegers Flak) in line with developing infrastructure, operator scales, and increasingly more efficient technology.
▪ The table below shows our calculations of the net
present value of an 1,000 MW offshore wind farm
in the Baltic Sea depending on the amount of feed-in
18
tariff (PLN 350/MWh in the base-case scenario) and Trade Profits Normalizing After CAPEX (EUR 3m/MW in the base-case scenario). Our assumptions are for a load factor of 45%, a service life 2017 Surge of 30 years, OPEX of EUR 20/MWh, and a sales price post feed-in tariff incentives of PLN 205/MWh. Using these Polish power traders achieved above-average profit assumptions, for a PLN 12.6bn project, we arrived at a margins in 2017 thanks to higher volumes and, more net present value of PLN 64m, and an internal rate of importantly, to falling prices of green certificates not passed return of 5.2%. For a project developed at a 10% lower onto end consumers. With all utilities operating renewable cost, the NPV increases above PLN 1 billion, energy sources with which they deal on an arm's length and the IRR is 7.3%. basis, the higher margins generated by their trading operations were accompanied by lower profits from NPV of a 1,000 MW Baltic wind farm depending on generation. The Polish utilities in our coverage energy payments and CAPEX generated aggregate 2017 trading EBITDA 30% Feed-In-Tariff (PLN/MWh) higher than in the year before, but there were differences on a case-by-case basis. PGE improved its 6366.2% 310 330 350 370 390 trading profits the most last year thanks to cheaper RECs
) 2.4 786 1,382 1,978 2,574 3,170 combined with a less aggressive customer acquisition
2.7 -171 425 1,021 1,617 2,213 strategy. The opposite was true for Tauron, striving to win
/MW 3.0 -1,128 -532 64 660 1,256 back the customers lost in 2016. In case of Enea and
m Energa, trading profits last year were hurt by charges CAPEX 3.3 -2,085 -1,490 -894 -298 298 related to long-term REC purchase contracts and last-resort
EUR ( 3.6 -3,043 -2,447 -1,851 -1,255 -659 supplier obligations to purchase renewable energy at prior Source: Estimates by Dom Maklerski mBanku year's prices.
PGE's Takeover Bid On Listed EBITDA margins (adj.) from electricity trading of Polish utilities (PLN/MWh) Energy Group Polenergia 25 25 21 18 19 On 22 May 2018, PGE announced it had offered to purchase 20 100% of shares in the listed energy group Polenergia 18 for PLN 16.29 per share in a tender offer set to launch 15 13 on 13 July and end on 20 September 2018. In an 10 accompanying statement PGE said it viewed the potential 10 acquisition of Polenergia as the fastest way to achieve 5 balanced inorganic growth, and that it considered a tender offer to be "the most transparent manner of presenting its 0 intentions" and an invitation to begin negotiations with -2 Polenergia's shareholders. Polenergia has not responded to -5 the invitation as of this writing. Its stock price (PEP) ENEA ENERGA PGE TAURON averaged PLN 14.36 in the last six months, and an average 2014 2016 2017 1Q'17 1Q'18 of three analysts' valuations puts its value at PLN 19.1 per Source: Companies, estimates by Dom Maklerski mBanku share. Trading margins are set to normalize this year in our ▪ Polenergia owns 243 MW of wind turbine capacity, a opinion, but in case of Enea and Energa the elimination of 116 MWe gas-based CHP, 300 MW of renewable projects supplier-of-last-resort functions, coupled with a lack of REC- (225 MW onshore wind farms, 31.5 MW biomass plants, related charges in case of the latter, will play a mitigating and 40 MW solar plants), and role. In the first quarter of 2018, the aggregate trading 1,200 MW of planned offshore wind capacity (a 50:50 JV EBITDA of the four Ppolish utilities in our sample showed with Statoil). Its regulated distribution assets have a flat growth from the same period the previous year, with value of PLN 86m. PGE and Tauron reporting negative growth. The sales ▪ In 2017 Polenergia generated EBITDA of PLN 182m margins for the period were weighed down by higher costs (47% wind farms, 40% CHP, 9% distribution, 7% of REC redemption, estimated to have grown by PLN 150m trading), ending the year with a net debt of overall year over year, and expected to put a continuing PLN 706m. strain in future quarters versus a lower year-ago base (a ▪ The future profit outlook is positive given rising prices REC currently trades above PLN 70/MWh compared to PLN of electricity and green certificates, though under the 22 in Q2 2017 and an average of PLN 36 in Q2-Q4 2017). new cogeneration support mechanism Polenergia's PLN On the other hand, base effects this year are working in 15m-a-year capacity payments are set to drop by 30- favor of Energa, which estimates that the release from last- 40%. resort supplier obligations, coupled with canceled ▪ PGE's bid implies an acquisition at 7.4x 2017 obligations to buy RECs from wind farms, all things held EV/EBITDA, but in future years the ratio would be constant can boost its 2018 EBITDA by PLN 0.2bn (in Q1 the lower as Poleneria's wind farms improve profitability. y/y rebound amounted to PLN 60m). Enea has decided to continue setting aside reserves for potential wind farm The acquisition is a reasonable step on PGE's part ▪ claims. which would allow the Company to expand its
competencies in interesting areas just as Poland puts
into effect a market for renewable energy capacity. With
that said, the size of the potential deal would surely
change how PGE is perceived by investors. In addition,
the potential of Polenergia's assets might become
watered down once absorbed into PGE's portfolio, which
the market values at very low EV/EBITDA ratios.
19
Prices of renewable energy certificates (PLN/MWh) Number of customers switching electricity suppliers in Poland 40 45,000 30 40,000 35,000 20 30,000 25,000 10 20,000 15,000 0 10,000 2010 2011 2012 2013 2014 2015 2016 2017 2018 5,000 0 white (efficiency)
purple (methane & bio-methane)
2010 2011 2012 2013 2014 2015 2016 2017 red (biogas) yellow (natgas) Source: URE
green Source: Eestimates by Dom Maklerski mBanku A factor which could weigh on electricity trading profits this year are rising power prices, with current spot quotes well With electricity usage on the rise in Poland (+2.8% in the above the year-ago levels as well as having topped the year- first three months of 2018), power generators do not have ahead contract prices agreed in 2017. The peak-base spread to resort to aggressive pricing practices to grow sales has slightly widened as well. The surprise surge in prices, volumes, as evidenced by first-quarter sales statistics (see not accounted for in the 2018 hedging strategies, assuming following diagram), which show that Enea was the only one a need to buy 5% of trading volumes on the sport market, to report a noticeable rebound in sales to business can boost the costs relative to the average 2018 customers in the period. wholesale contract price by as much as PLN 150m.
YoY change in retail electricity sales volumes 2016-2018 POLPX spot-base index (PLN/MWh) 200 20% 17% 2016 2017 1Q'18 15% 180 12% 10% 9% 10% 7% 160 3% 4% 4% 5% 5% 2% 140 0% 120 -5% -6% -10% 100 -11% 1Q 2Q 3Q 4Q -15% 2016 2017 2018 ENEA ENERGA PGE TAURON Source: POLPX Source: Companies
Under these circumstances, we expect the aggregate The improved sales prospects are a result partly of 2018 Trading EBITDA of the four utilities in our industry consolidation, represented by last year's mergers coverage to show flat growth from the previous year, between Enea and Engie Poland and between PGE and EDF thanks only to a rebound anticipated at Energa. In future Poland. years, we predict profits from trade will stabilize at slightly Projection of 2018 net positions in generation (TWh) lower levels closer to the respective ten-year averages (TWh) Generation Retail Difference recorded by each company. This prediction is based on an Enea 24.6 18.2 6.4 updated price outlook for electricity, which indicates downward pressure on profits from household sales with Energa 4.0 20.7 -16.8 pass-through of rising wholesale prices, REC costs, and PGE 67.0 41.0 25.9 reinstated renewable surcharges, likely to be suppressed by Tauron 16.0 35.5 -19.5 the regulator. Source: Estimates by Dom Maklerski mBanku At the price current levels, the cost per megawatt hour Further, Polish power consumers continue to demonstrate a of supplying power to household consumers can be high propensity to switch suppliers, with an estimated expected to increase by as much as PLN 40-45, implying a 12% of end users in the first three tariff groups having 9% hike in the average energy bill. For any PLN 10/MWh switched so far. Looking at the German switch ratio of ca. extra cost not factored into the retail tariff, the EBITDA 20%, going forward the Polish switch rate should rise at a setback faced by utilities can reach PLN 45m (1.5% of total slower rate. 2019E EBITDA) in case of Enea, PLN 55m (2.4% of total annual EBITDA) in case of Energa, PLN 95m (1.3% of total EBITDA) in case of PGE, and PLN 95m (2.8% of total EBITDA) in case of Tauron. In 2019, by the same token, the average margin might tighten by PLN 2/MWh.
20
Energa's Court Fight With Wind Projection of EBITDA less CAPEX for Polish power utilities* Farm Operators 7,000
6,000 In 2017, Energa decided to terminate contracts for long- 5,000 term fixed-price energy purchases from 22 wind farms 4,000 based in Poland. The owners of all these installations 3,000 responded with lawsuit, claiming that the termination was 2,000 unlawful. Although it faces many months of legal wrangling, 1,000 Energa hopes to settle at least some of these cases out of 0 court. In short, the current state of affairs can be -1,000 summarized as follows. -2,000
▪ In a statement last October, Energa assessed that, had
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 the contracts with the 22 wind farms not been canceled, 2010 it would have faced losses to the tune of *Enea, Energa, PGE, Tauron PLN 2.1 billion assuming a price per green certificate of Source: Estimates by Dom Maklerski mBanku PLN 43/MWh. It also set out plans to recover a portion of the losses incurred in 2013-2017 (estimated at SOTP Analysis PLN 700-800m), but his would have to be accompanied by adjustments to the profits it had earned on these contracts in prior years, when it purchased clean wind The recent sell-off on Polish utility stocks, which went power cheaper than the market prices at the time. against their improving earnings prospects, further widened the discount at which these companies are valued by the ▪ Energa estimates that the cancellation of the wind farm market. The extent to which the sector might be contracts will boost its 2018 profit from trading by undervalued can be assessed by making a sum-of-the- PLN 110m compared to 2017. However, with green parts analysis with the following underlying certificate prices averaging PLN 36.5/MWh in 2017, while assumptions: the fixed contractual prices ranged from PLN 180 to The distribution business valued as an amount equal 190/MWh, assuming an average capacity factor of 25% ▪ for the 22 wind farms the boost could be even higher to the value of regulatory assets (the EV/EBITDA implied (1.1 TWh x PLN 150/MWh=PLN 170m). by this approach is shown in the following table). ▪ Energa revealed recently it was in settlement talks with ▪ The value of the trading business calculated as a the largest of the 22 wind farms, representing combined multiple of 2018-2020E EBITDA and a factor of 5.0x (the capacity of 210 MW. In May it reached a settlement with implied EV/MWh of annual EUR-denominated sales is a 48 MW unit but at the same time it lost the case shown in the table). against a 16 MW in the court of first instance, indicating ▪ Net debt taken in its projected 2020 amount less the existence of material differences between the potential dividends. canceled contracts from a legal standpoint. ▪ The generation business valued as a difference If Energa should lose the rest of the pending cases between the enterprise value (current market cap and (482MW), with green certificates currently trading at adjusted 2020E debt) and the combined value of the PLN 80/MWh, it would face a present-value negative margin distribution and trading segments calculated as on the reinstated contractual purchases of roughly PLN described above. The SOTP valuation also allowed us to 1.4bn (the actual loss would over time be lower at calculate an implied EV/EBITDA ratio based on 2020 PLN 1bn, equivalent to 26% of market capitalization, which earnings forecasts. at the current level already prices most of the legal risks). This not including any other potential claims by the wind Simplified Sum-Of-The-Parts Utility Valuations farms. CEZ ENA ENG PGE TPE Share price (LCU) 568.5 9.66 8.88 9.24 2.0 Improving FCF MCap 305,847 4,264 3,677 17,276 3,505 2020E Net Debt 147,246 6,105 4,345 6,159 10,900 Utilities are never not expected to make large Minority Interest 4,304 921 56 1,165 30 investments by investors, who realize these companies 2020E EV 457,397 11,290 8,078 24,600 14,435 serve as "cash cows" furthering the agendas of each Dividends in 2020E 47,786 0 0 781 0 Investment in successive government. However, if we ignore the 6,252 0 0 0 0 unsubstantiated media buzz, hearsay, and proclamations noncom. units about major new state-led projects, what emerges is a RAB 119,652 7,984 12,231 16,260 16,900 picture of a slow increase in cash flows in the next five 2018-20E EBITDA 19,737 1,166 1,744 2,443 2,518 2017 transmission years. Investors should probably not get their hopes up as 52.0 19.3 22.1 32.5 51.4 regards dividends, but we think it is important to realize that volume (TWh) the Polish energy sector is ready to start reducing Implied EV/EBITDA 6.1 6.8 7.0 6.7 6.7 debt and generate much higher free cash flow going Trading Segment 24,000 929 1,261 3,445 2,608 forward. As a result, companies will be able to offer a better 2018-20E EBITDA 4,800 186 252 689 522 equity side of the enterprise value, and this should be EV/EBITDA 5.0 5.0 5.0 5.0 5.0 reflected in their market capitalizations even if the sector's Volume 37.0 17.9 20.4 40.4 34.9 EV/EBITDA were to hold at today's low level (see the Volume in EUR/MWh 25.5 12.3 14.7 20.2 17.7 following diagram). Implied value of 259,707 2,378 -5,414 4,114 -5,073 Generation Segment 2020E EBITDA 34,722 1,587 317 4,696 706 Implied 2020E 7.5 1.5 -17.1 0.9 -7.2 EV/EBITDA Source: Estimates by Dom Maklerski mBanku
21
▪ The conclusion that can be drawn from the simple SOTP Correlation between MSCI US Utilities with the analysis is that when it comes to the value attributed inverse of a 10Y T-yield and premium of sector to the generation business only CEZ enjoys a fair dividend yield over the risk-free rate assessment or is even possibly slightly overpriced given 170 90 the high share of nuclear in its energy mix. In case of 160 80 Enea and PGE, the valuation disproportionately low at less than 2.0x EBITDA despite the fact that their 150 70 generation assets are relatively young and vertically 140 60 integrated with coal mines, with high rankings in the 130 50 merit order (low variable costs of generation). Even more shockingly, the EV of the generation assets of 120 40 Energa and Tauron comes out negative at PLN -5bn, with 110 30 investors seemingly betting on high losses on these assets contrary to obvious indications of continuing high 100 20 earnings in the coming years. Note also that Energa
counts its attractive renewable assets toward the
Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18
Sep-13 Sep-14 Sep-15 Sep-16 Sep-17
May-14 May-15 May-16 May-17 generation business, and Tauron's generation segment May-13 MSCI US Utilities 1/10Y yield (rhs) includes the money-making heating assets. 3.0% Performance 2.5% Utility indices in various markets across the world are showing relatively strong correlation to each other despite 2.0% significant differences in regulatory environments and economic sensitivity. Obviously there is interim divergence 1.5% between the US and Europe due to continent-specific factors, but there are very clearly defined periods when cash 1.0% is seen to pour into and out of the sector (see diagram below). Such divergence is seen in recent months in 0.5% MSCI Utilities USA, down 4% ytd, versus Europe
which has gained 6% since the beginning of the year.
Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18
Sep-13 Sep-14 Sep-15 Sep-16 Sep-17
May-14 May-15 May-16 May-17 This is led by a strong rebound in European power prices, May-13 driven by rallying commodities and carbon allowances. DYield-RFR premium 3Y avg. Source: Bloomberg, Dom Maklerski mBanku Europe vs. US utility performance 150 The broad US stock market is showing relatively strong performance this year, and as a result the discount in 140 utilities at times reached 2015 highs (-10%) until the correction in February, with premiums/discounts now 130 matching the historical relationships with dividend yields. 120 Premium/discount of S&P Utilities P/E to the broad 110 market vs. relative attractiveness of dividend yields
100 3.0% 25%
90 20% 2.5%
15%
Jul-16 Jul-17
Jan-17 Jan-18
Jan-16 2.0%
Mar-16 Mar-17 Mar-18
Sep-16 Sep-17
Nov-16 Nov-17
May-17 May-18 May-16 10%
EU Utilities US Utilities 5% 1.5% Source: Bloomberg 0%
1.0% The weakness of US utilities is a consequence of the -5% momentum in market interest rates. This is not surprising looking at the high historical correlation between bond yields 0.5% -10%
and utility stocks, stemming from attractive dividend yields.
Jul-12 Jul-13 Jul-14 Jul-15 Jul-16 Jul-17
With the US Federal Reserve planning to raise interest rates, Jul-11
Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 the long rally in US utility stocks is now over. US 10Y bond P/E discount/premium (rhs) Dyield-RFR premium (lhs) yields have risen by 0.5pp to 3%, and this had to have an impact on utility stocks so that their dividend yields match Source: Bloomberg, Dom Maklerski mBanku market expectations. Nevertheless the current premium to risk-free rate is still lower than the 3-year average (1.2% vs The sell-off on MSCI Utilities US corresponds with a 1.5%). Theoretically, we should expect continued downward reversed earnings momentum in the sector, with the pressure on the sector, especially with analysts predicting trailing 12-month FWD EBITDA per share down nearly 3% further expansion in bond yields. over the last five months. The market is betting on an over- 10% rebound, but revisions are probably upcoming.
22
MSCI US Utilities vs. EBITDA forecasts (12M Fwd In Poland, utilities in the last few months have been Blended) hurt by the government's energy agenda, losing more 108 165 than 20% ytd and underperforming the broad WIG index by 107 160 14ppts. The underperformance versus European peers is 106 155 even worse, meanwhile in our view it is worth keeping in 105 150 mind the solid earnings prospects of Polish power 104 145 generators, owed to increasing electricity prices, new, 103 140 more efficient capacity, and higher returns on renewables. 102 135 Accordingly, we predict market expectations as to future 101 130 EBITDA will eventually start to be revised upward, though the EV/EBITDA expectations might now follow suit. The 100 125 revisions should be supported by improving FCF and lower- 99 120 than-assumed net debt and CAPEX.
WIG Energy vs. 12M Fwd EBITDA
Feb-15 Feb-16 Feb-17 Feb-18
Aug-15 Aug-16 Aug-17
Nov-15 Nov-16 Nov-17
May-15 May-16 May-17 May-18 US Utilities EBITDA MSCI Utilities US 110 5,500 Source: Bloomberg, Dom Maklerski mBanku
In Europe, the reverse correlation with bond yields is 105 4,500 less obvious due to a less stable regulatory environment, hindered by a malfunctioning emissions trading scheme, the 100 3,500 efforts for a clean energy push, and with less generous dividend policies across the board dividend yields and their premiums over the risk free rate have less of a bearing on 95 2,500 the equity valuations (premiums/discount to the broad market) of European power stocks. After years of falling profits and deteriorating balance sheets, sentiment going 90 1,500 forward will be shaped by future earnings expectations.
Recent performance indicates the market has discounted a
Feb-15 Feb-16 Feb-17 Feb-18
Aug-15 Aug-16 Aug-17
Nov-15 Nov-16 Nov-17
May-16 May-17 May-18 rebound in earnings in 2-3 years' time, reflecting the May-15 lagging impact of rising power prices due to hedging. EBITDA 12M Fwd WIG-ENE
Source: Bloomberg MSCI Utilities vs. 12M Fwd Blended DPS and EBITDA forecasts Though not imminent, we think the prospect of 29.0 120 WIG-Energy narrowing the discount to the broad 28.0 115 market on earnings multiples is real given the implementation of the capacity market and new 27.0 110 cogeneration payments. Political pressure could not be any 26.0 105 higher than it is today, and it is accompanied by messages 25.0 100 from the power industry signaling aversion to any involvement in the nuclear project. The fact that the market 24.0 95 seems to want to view the state's most controversial energy 23.0 90 plans as the base-case scenario leaves plenty of room for 22.0 85 positive surprises.
WIG Total Return vs. WIG-Energy
Feb-15 Feb-16 Feb-17 Feb-18
Aug-15 Aug-16 Aug-17
Nov-15 Nov-16 Nov-17
May-16 May-17 May-18 May-15 16 0% EBITDA 12 FWD EBITDA 2020 Utilities EU Source: Bloomberg, Dom Maklerski mBanku 14 -10% 12 -20% Almost all EU utilities are benefitting from the improvement 10 -30% in sentiment, although companies with positive 8 -40% exposures to clean power and low emissions have 6 -50% performed better. 4 -60% Total returns on utility stocks since the beginning of 2 -70% 2017 (incl. dividends)
50%
Jul-12 Jul-17
Jan-15
Oct-13
Jun-15
Apr-16
Feb-12 Feb-17
Mar-14
Dec-12 Dec-17
Sep-16
Aug-14
Nov-15 May-18 40% May-13 30% Discount WIG P/E WIG-ENERGY P/E 20% 10% Source: Bloomberg, Dom Maklerski mBanku 0% -10% The Warsaw Stock Exchange's WIG-Energy index, tracking -20% Poland's biggest power utilities, outperformed the broad- -30% market WIG benchmark only twice in the last seven years -40% (with negative cumulative returns of 45% since 2011 versus +30% WIG), and it was seen to beat the returns of MSCI Europe Utilities once in the period. After the sell-off of the last few months, we see good reason to overweight Polish utilities in medium-term portfolios.
Source: Bloomberg
23
Returns on utility stocks, Poland vs. EU and US Valuation premiums/discounts to peer EV/EBITDA 30% (12M Fwd) vs. 3-year averages 25% ENEA EV/EBITDA vs WIGENE 20% 15% 15% 10% 10% 5% 0% 5% -5% -10% 0% -15% -5% -20% -25%
-10%
2011 2012 2013 2014 2015 2016 2017 2018
Jan-14 Jan-15 Jan-16 Jan-17 Jan-18
Sep-14 Sep-15 Sep-16 Sep-17
May-15 May-16 May-17 May-18 US UTILITIES EU UTILITIES WIG-ENERGY WIG May-14
Source: Bloomberg, Dom Maklerski mBanku ENERGA EV/EBITDA vs. WIGENE 15% WIG-Energy is trading at a discount of 20% to its 10% average EV/EBITDA ratio for the last three years, but 5% going forward we believe the index can unlock much greater upside potential with the inevitable upward revisions to 0% the market's earnings expectations (our 2019 EBITDA -5% forecasts are currently 7% higher on average than the -10% average market forecasts), and the narrowing of the current 50+ percent discount to the European peers (compared to -15% an average of 30% over the last three years). -20%
Arithmetical mean of EV/EBITDA (12M fwd) for ENA,
Jan-14 Jan-15 Jan-16 Jan-17 Jan-18
Sep-14 Sep-15 Sep-16 Sep-17
May-15 May-16 May-17 May-18 ENG, PGE, and TPE vs. 3-year average May-14 6.25 PGE EV/EBITDA vs. WIGENE 6.00 15% 5.75 10% 5.50 5% 5.25 5.00 0% 4.75 -5% 4.50 -10% 4.25 4.00 -15%
3.75 -20%
Jan-14 Jan-15 Jan-16 Jan-17 Jan-18
Sep-14 Sep-15 Sep-16 Sep-17
May-14 May-15 May-16 May-17 May-18
Jan-14 Jan-15 Jan-16 Jan-17 Jan-18
Sep-14 Sep-15 Sep-16 Sep-17
May-15 May-16 May-17 May-18 May-14 Source: Bloomberg, estimates by Dom Maklerski mBanku 15% TAURON EV/EBITDA vs. WIGENE Forecast revisions and a subsequent value boost to the 10% whole sector can drive the valuations of individual utilities, which today are trading on a par with the sector 5% averages. It is worth noting that Energa has widened the 0% distance to its peers in the last six months, Tauron has turned its valuation discount to a sustained premium, and -5% Energa continues to trade at a discount, which is surprising -10% given its improving trading profits and a high share of the -15% regulated business in EBITDA, making it much more resistant to market shifts. -20%
Jan-14 Jan-15 Jan-16 Jan-17 Jan-18
Sep-14 Sep-15 Sep-16 Sep-17
May-15 May-16 May-17 May-18 May-14 Source: Bloomberg, estimates by Dom Maklerski mBanku
24
CEZ is a completely different case than Polish utilities, forward these companies' disregard for minority and it is currently trading at a 15% premium to the shareholders. A perfect example of this is Enea, which EV/EBITDA ratio of Stoxx Utilities after historically decided not to pay dividends this year even though it has incompatible gains which are all the more surprising that the just completed a major capital project and is about to start Czech generator's dividends are set to decrease in the generating a large cash surplus with net debt/EBITDA ratio coming years, with 12m fwd dividend yield seen to trail at 2.0x. sector averages versus 30% beats offered in the last three years, and the premium over the risk-free rate narrowed Regression analysis: EV/EBITDA vs. 2018-2020E from 5% to less than 2%. If we add to this the looming cumulative CAPEX/ EBITDA entanglement in the Czech nuclear project, the gains look 12 even more unjustified to us. National 11 SSE Red Grid CEZ vs. Stoxx Utilities (12m fwd EV/EBITDA) 10 Electrica CEZ EV/EBITDA vs STOXX UTILITIES 9 Iberdrola 30% 25% 8 EDP CEZ RWE 20% 7 Endesa EDF 15% EON 6 10% Enel 5% 5 0% 4 Enea Tauron -5% PGE 3 -10% Energa -15% 2 -20% 0.30 0.50 0.70 0.90 1.10
Source: Bloomberg, Dom Maklerski mBanku
Feb-12 Feb-13 Feb-14 Feb-15 Feb-16 Feb-17 Feb-18
Aug-13 Aug-14 Aug-15 Aug-16 Aug-17 Aug-12 CEZ DYield vs peers 70% Regression analysis: EV/EBITDA vs. 2018-2020E 60% dividend yields 50% 16 Fortum 40% 30% 14 20% 12 National 10% Grid Red SSE 0% 10 Electrica -10% CEZ Iberdrola 8 EDP -20% EDF Endesa EON 6 RWE
Enea Enel
Feb-12 Feb-13 Feb-14 Feb-15 Feb-16 Feb-17 Feb-18
Aug-13 Aug-14 Aug-15 Aug-16 Aug-17 Aug-12 4 CEZ Dyield vs 10Y bond yield Tauron PGE 9% 2 Energa 8%
7% 0 6% 0% 2% 4% 6% 8% 5% Source: Bloomberg, Dom Maklerski mBanku 4% 3% Regression analysis: EV/EBITDA vs. 2017-2020E EBITDA CAGR 2% 1% 18 Fortum 0%
16
Feb-… Feb-… Feb-… Feb-… Feb-… Feb-… Feb-…
Aug-… Aug-… Aug-… Aug-… Aug-… Aug-… 14
Source: Bloomberg, estimates by Dom Maklerski mBanku 12 Red SSE Electrica Iberdrola EV/EBITDA mapping for a large group of European 10 EDP CEZ EON utilities by FCF, dividends, and earnings growth, confirms 8 the intuitive correlations and in most cases explains the Enel discount attached to Polish companies. A graphic 6 Endesa EDF representation of this is provided below. While the discount 4 in the values of Polish utilities is absolutely deserved, Energa Enea Tauron its size is excessive, as evidenced by the fact that most 2 PGE Polish stocks are below the regression curve. For one, at the extremely low market capitalization of today, Polish utility 0 0% 2% 4% 6% 8% 10% 12% companies could offer dividend yields of 5% by distributing just 25% of their annual earnings, and increasing net debt Source: Bloomberg, Dom Maklerski mBanku by just 5% (0.1x EBITDA). The frozen distributions to shareholders are obviously a matter of politics, not financial standing. This reinforces the valuation discounts by bringing
25
Relative Valuation Charts for
Power Utilities
P/E, P/CE, EV/EBITDA, D&A as a pct. of EBITDA (the 2018-2022 CAPEX and OCF projection (top chart, higher the ratio the more meaningful the P/CE ratio PLN m), 2018-2023E CAPEX allocations by operating vs. the P/E ratio) segment (bottom chart) P/E 2018-2022P OCF vs. CAPEX 25 40,000 20 30,000 20,000 15 10,000
10 0 -10,000 5 -20,000
0 -30,000 2018P 2019P 2020P CEZ ENEA ENERGA PGE TAURON
CEZ ENEA ENERGA PGE TAURON capex ocf
P/CE 2018-2023P CAPEX allocations 8 100% 7 80% 6 40% 35% 55% 5 39% 67% 60% 4 3 40% 2 58% 56% 20% 47% 45% 1 31%
0 0% 2018P 2019P 2020P CEZ ENEA ENERGA PGE TAURON
CEZ ENEA ENERGA PGE TAURON Generation Distribution Other
EV/EBITDA 9 Source: Companies, estimates by Dom Maklerski mBanku
8
7 6 5 4 3 2 1 0 2018P 2019P 2020P CEZ ENEA ENERGA PGE TAURON
EBITDA Breakdown
45% 51% 55% 55% 50%
55% 49% 45% 45% 50%
CEZ ENEA ENERGA PGE TAURON D&A EBIT
Source: Companies, estimates by Dom Maklerski mBanku
26
2018-2020 Net Debt/EBITDA projection 2018E Regulated Asset Base (top, EUR m), RAB as a pct. of EV (middle), and Distribution EBITDA as a pct. of total (bottom) 3.5 2018 RAB (EUR m) 3.0 5,000 4,500 2.5 4,000 2.0 3,500 3,000 1.5 2,500 1.0 2,000 1,500 0.5 1,000 0.0 500 CEZ ENEA ENERGA PGE TAURON 0 CEZ ENEA ENERGA PGE TAURON 3.5 2019 RAB/EV 3.0 160%
2.5 140%
2.0 120% 100% 1.5 80% 1.0 60% 0.5 40%
0.0 20% CEZ ENEA ENERGA PGE TAURON 0% CEZ ENEA ENERGA PGE TAURON 3.5 2020 3.0 Distribution as % of EBITDA 100% 2.5
2.0 80%
1.5 60% 1.0 40% 0.5
0.0 20% CEZ ENEA ENERGA PGE TAURON
Source: Companies, estimates by Dom Maklerski mBanku 0% CEZ ENEA ENERGA PGE TAURON
Source: Companies, estimates by Dom Maklerski mBanku
27
2018-2020 Earnings Outlook For Power Utilities: mBank versus Consensus Forecasts EBITDA (LCU million) Net Profit (LCU million) DPS 2018P 2019P 2020P 2018P 2019P 2020P 2018P 2019P 2020P CEZ (CZK) mBank 52,619 55,633 59,098 14,308 15,724 17,848 33.00 26.60 29.23 Consensus 53,175 54,757 58,371 14,283 13,630 16,082 25.08 24.45 28.08 difference -1% 2% 1% 0% +15% +11% +32% 9% 4%
Enea (PLN) mBank 2,845 3,290 2,984 919 1,190 946 0.00 0.00 0.00 Consensus 2,796 2,992 2,963 919 1,053 1,012 0.27 0.29 0.31 difference 2% 10% 1% 0% +13% -7% -100% -100% -100%
Energa (PLN) mBank 2,268 2,360 2,362 800 828 805 0.00 0.00 0.00 Consensus 2,225 2,308 2,260 783 791 733 0.19 0.23 0.24 difference 2% 2% 5% 2% 5% 10% -100% -100% -100%
PGE (PLN) mBank 7,509 7,919 7,873 3,056 3,126 2,874 0.00 0.00 0.42 Consensus 7,225 7,402 7,413 2,863 2,730 2,542 0.00 0.22 0.39 difference 4% 7% 6% 7% +14% +13% 0% -100% 8%
Tauron (PLN) mBank 3,715 3,515 3,811 1,365 1,061 1,136 0.00 0.00 0.00 Consensus 3,347 3,395 3,600 1,035 1,036 1,063 0.00 0.04 0.09 difference +11% 4% 6% +32% 2% 7% 0% -100% -100% Source: Bloomberg, Dom Maklerski mBanku
28
podwyższona Tuesday, May 29, 2018 | update podtrzymana CEZ: sell (reiterated) obniżona CEZ CP; CEZ.WA | Power Utilities, Czech Republic Overvalued Given Risks Current Price CZK 551.00 Target Price CZK 458.38 CEZ has closely tracked rising electricity prices in the last few Market Cap CZK 296.43bn weeks, and at the current level, where the share price shows a record-high premium to the industry index, now is probably a good Free Float CZK 89.58bn time to take profits on the stock. CEZ generates over 40% of its ADTV (3M) CZK 367.21m power volumes via high-emissions lignite-fired installations, which means the increasing electricity prices, driven by an upshift in prices Ownership of carbon allowances, actually have a limited effect on its profits (as Czech Government 69.78% opposed to coal-led power price shifts). What is more, the Czech
utility is still facing having to lead its national nuclear project, which in the worst-case scenario has a negative net present value as well Others 30.22% as being potentially destructive to CEZ's current investment profile. We have raised our 9-month price target for CEZ slightly to Business Profile CZK 458.38 after factoring in the changed market conditions, but we CEZ is the leading producer of electric power in the Czech Republic (58.4 TWh, 67% market share), as still rate the stock as a sell. well as being the largest distributor (with a 65% market share) and seller (29%). The Company also Improved generation earnings now priced in operates power plants in Poland, and it distributes Electricity prices are expected to average EUR 32/MWh this year, and based electricity to end users in Bulgaria (where it has a on current hedging by 2020 they may rise to EUR 39/MWh. After taking into 28% market share) and in Romania (12%) where it account the rising prices of emission allowances, this would imply an also owns two large wind farms. An acquisition in Turkey gave CEZ a 3% share in the local market for increase of CZK 4bn in the EBITDA of CEZ’s Generation business, compared power distribution. Recently CEZ is also expanding to a CZK 5bn boost already priced into the current consensus forecasts. its presence in the Western European market for renewable energy through wind farms in Germany Overlooked nuclear risks and France. Investors seem to have forgotten the potentially destructive role of the Czech nuclear project from the standpoint of CEZ’s investment profile, at CEZ vs. WIG times even putting a premium on the proposed split of the Czech generator's 600 business. This is surprising considering the recent statements by the Czech CEZ CP CZK industry minister as regards future dividends and share value. Meanwhile WIG our calculations suggest that if CEZ had to finance the nuclear plant by itself 550 it stands to lose CZK 35bn of its value per each gigawatt of the 2 GW of
capacity currently planned, equivalent to 13% of the current market 500 capitalization.
Undeserved premium to Stoxx Utilities 450 CEZ is trading at an unprecedented 15% premium to the EV/EBITDA ratio of EURO Stoxx Utilities at the current level even though it is expected o pay 400 lower dividends in the years ahead, with its 12m fwd DYield slightly below the peer average compared to a 30% premium in the last three years, as well as showing a tighter premium of 2% vs. 5% to the yield on 10-year 350
treasuries.
Feb-18
Aug-17
Nov-17
May-17 May-18
Target Price* Rating Name new old new old CEZ 458.38 449.51 sell sell Current Target Upside/ Name Price* Price* Downside CEZ 551.00 458.38 -16.8% Forecast revision 2018E 2019E 2020E (CZK m) 2016 2017 2018E 2019E 2020E since last update Revenue 203,744 201,906 205,271 214,120 228,091 EBITDA -2.2% -0.1% +2.1% EBITDA 58,206 55,155 52,548 55,139 58,313 Net profit -1.2% +0.7% +11.0%
EBITDA margin 28.6% 27.3% 25.6% 25.8% 25.6% Power price (EUR/MWh) +14.8% +14.5% +7.9%
EBIT 26,114 25,620 23,859 25,601 29,030 EUR/CZK +0.0% +0.0% +0.0% Net profit 14,281 18,765 14,251 15,324 17,207 Carbon price (EUR/t) +40.0% +38.5% +36.9% P/E 20.8 15.8 20.8 19.3 17.2 *CZK prices P/CE 6.4 6.1 6.9 6.6 6.4 P/B 1.2 1.2 1.2 1.2 1.2 Analyst: EV/EBITDA 7.6 8.0 8.5 8.1 7.7 DPS 40.0 33.0 33.0 26.5 28.5 Kamil Kliszcz +48 22 438 24 02 DYield 7.2% 5.9% 6.0% 4.8% 5.2% [email protected]
Valuation
Using DCF analysis and relative valuation, we set our nine- weight price (CZK) price (PLN) month price target for CEZ at CZK 458.38 per share. Relative Valuation 50% 361.4 57.8
DCF analysis 50% 506.9 81.1 price 434.2 69.5
9M target price 458.4 73.3
DCF Valuation
Assumptions: . Macroeconomic and operational assumptions are as set . Cash flows are discounted to their present value as of out below. the end of May 2018. Equity value calculations factor in . We assume that FCF after FY2027 will grow at an minority interests, net debt as at year-end 2017, and annual rate of 2%. The risk-free rate is 2.5%, and beta is provisions for nuclear power plant closures. 1.0. . The model accounts for CEZ's equity in profits of associates accounted for using the equity method.
Additional Assumptions: 2017 2018P 2019P 2020P 2021P 2022P 2023P 2024P 2025P 2026P 2027P Power output (TWh) 62.9 67.0 67.6 67.7 67.7 67.7 67.7 67.7 67.7 67.7 67.7 nuclear power 28.3 30.4 30.4 30.4 30.4 30.4 30.4 30.4 30.4 30.4 30.4 lignite-fired 25.6 27.5 28.1 28.1 28.1 28.1 28.1 28.1 28.1 28.1 28.1 hard coal-fired power 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 gas-powered power 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 hydroelectric power 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 wind energy 1.6 1.8 1.8 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 other 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9
Sales volume (TWh) 37.0 37.3 37.6 37.9 38.2 38.5 38.8 39.1 39.4 39.7 40.0 Distribution volume 52.0 52.3 52.6 52.8 53.1 53.4 53.6 53.9 54.2 54.4 54.7 (TWh)
Price of 1Y electricity 32.4 41.2 42.3 38.6 39.2 39.6 40.1 40.6 41.1 41.6 42.2 contract (EUR/MWh) Price of a carbon 5.9 14.0 14.6 15.2 15.8 16.4 17.1 17.8 18.5 19.2 20.0 allowance (EUR/t)
EUR/CZK 26.5 25.5 25.5 25.5 25.5 25.5 25.5 25.5 25.5 25.5 25.5 USD/CZK 23.5 21.3 21.3 21.3 21.3 21.3 21.3 21.3 21.3 21.3 21.3
30
DCF Model (CZK m) 2018P 2019P 2020P 2021P 2022P 2023P 2024P 2025P 2026P 2027P 2027+ Revenue 205,271 214,120 228,091 226,124 230,509 232,873 235,268 237,730 240,262 242,867 242,867 change 1.7% 4.3% 6.5% -0.9% 1.9% 1.0% 1.0% 1.0% 1.1% 1.1% 0.0% EBITDA* 56,227 58,910 62,178 60,166 61,028 61,589 62,204 62,801 63,375 63,921 63,921 EBITDA margin 27.4% 27.5% 27.3% 26.6% 26.5% 26.4% 26.4% 26.4% 26.4% 26.3% 26.3% D&A* 32,368 33,309 33,148 33,961 33,545 34,132 34,265 34,588 35,076 35,694 32,659 EBIT 23,859 25,601 29,030 26,205 27,483 27,457 27,939 28,214 28,299 28,227 31,262 EBIT margin 11.6% 12.0% 12.7% 11.6% 11.9% 11.8% 11.9% 11.9% 11.8% 11.6% 12.9% Tax on EBIT 4,533 4,864 5,516 4,978 5,220 5,214 5,304 5,356 5,371 5,356 5,940 NOPLAT 19,325 20,737 23,514 21,227 22,264 22,243 22,635 22,858 22,928 22,871 25,323
CAPEX* -34,963 -34,663 -34,463 -33,300 -33,262 -33,215 -33,134 -33,016 -32,858 -32,659 -32,659 Working capital 68 -1,038 -1,638 231 -514 -277 -281 -289 -297 -305 -305 Equity investment 0 0 0 0 0 0 0 0 0 0 0
FCF 16,799 18,345 20,561 22,118 22,032 22,883 23,485 24,141 24,849 25,601 25,017 WACC 5.8% 5.8% 5.8% 5.7% 5.7% 5.7% 5.8% 5.8% 5.8% 5.8% 6.8% Discount factor 96.8% 91.5% 86.5% 81.8% 77.4% 73.2% 69.2% 65.4% 61.8% 58.5% 58.5% PV FCF 16,258 16,787 17,790 18,100 17,051 16,747 16,251 15,794 15,368 14,964
WACC 5.8% 5.8% 5.8% 5.7% 5.7% 5.7% 5.8% 5.8% 5.8% 5.8% 6.8% Cost of debt 3.5% 3.5% 3.5% 3.5% 3.5% 3.5% 3.5% 3.5% 3.5% 3.5% 3.5% Risk-free rate 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% Risk premium 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% Effective tax rate 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% Net debt / EV 37.1% 37.2% 37.2% 37.9% 37.7% 37.6% 37.4% 37.1% 36.8% 36.3% 15.0%
Cost of equity 7.5% 7.5% 7.5% 7.5% 7.5% 7.5% 7.5% 7.5% 7.5% 7.5% 7.5% Risk premium 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% Beta 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0
FCF growth after the forecast period 2.0% Sensitivity Analysis
Terminal value 521,161 FCF growth in perpetuity
Present value of terminal value 304,633 0.0% 1.0% 2.0% 3.0% 4.0%
Present value of FCF in the forecast period 165,110 WACC +1.0 p.p. 305.3 359.4 432.1 535.2 692.5
Enterprise value 469,744 WACC +0.5 p.p. 330.5 392.9 478.8 604.7 806.9
Net debt 139,546 WACC 359.4 432.1 535.2 692.5 962.2
Minority interests 4,304 WACC -0.5 p.p. 392.9 478.8 604.7 806.9 1,184.9
Equity Value 325,894 WACC -1.0 p.p. 432.1 535.2 692.5 962.2 1,531.4
Investment in associates accounted for under the equity 6,252 method Allowances for nuclear plant closures 59,419
Number of shares (millions) 537.99
Equity value per share (CZK) 506.9
9M cost of equity 5.6%
9M target price (CZK) 535.2
9M target price (PLN) 85.6
EV/EBITDA ('18) at target price 9.2
P/E ('18) at target price 20.2
TV / EV 65%
*incl. nuclear fuel expenses and amortization
31
Relative Valuation
We compared CEZ's forward P/E and EV/EBITDA multiples used (fuels, emissions, age of installed capacity), and the and projected dividend yields with the multiples and yields shares of different operating segments in total earnings. of the Company's peers as projected for fiscal 2018 We assigned equal weights to each multiple and forecast through 2020.The peer group comprises vertically- year. The calculations pertaining to PGE and Enea are integrated power producers as well as utilities focusing adjusted for compensation received under long-term power mainly on regulated distribution of electricity and on purchase agreements. renewable energy. It is diversified in terms of technology
Multiples Comparison P/E EV/EBITDA 2018- 20E Price 2017 2018E 2019E 2020E 2017 2018E 2019E 2020E DYield EDF 11.47 21.8 19.0 16.0 13.6 5.9 6.1 5.7 5.6 3.0% EDP 3.38 15.1 15.9 14.4 14.0 8.8 9.1 8.5 8.2 5.6% ENDESA 19.19 14.5 14.3 13.9 13.8 7.4 7.5 7.4 7.3 7.2% ENEL 4.71 13.2 11.6 10.4 9.8 6.6 6.5 6.3 6.1 6.6% EON 9.17 14.4 13.9 13.0 12.2 8.9 7.4 7.2 6.6 5.2% INNOGY 35.85 16.2 17.6 16.9 16.3 8.6 8.9 9.1 9.0 4.6% RWE 19.75 10.0 13.4 11.8 9.7 6.9 7.2 7.2 7.5 4.2% ENEA 9.57 3.9 4.6 3.5 4.5 4.0 4.0 3.5 3.9 0.0% ENERGA 9.00 4.8 4.7 4.5 4.6 3.6 3.4 3.3 3.4 0.0% PGE 9.28 10.4 5.7 5.6 6.0 4.0 3.5 3.3 3.1 1.5% TAURON 2.01 2.9 2.7 3.3 3.1 3.7 3.8 4.3 3.8 0.0%
Maximum 21.8 19.0 16.9 16.3 8.9 9.1 9.1 9.0 7.2% Minimum 2.9 2.7 3.3 3.1 3.6 3.4 3.3 3.1 0.0% Median 13.2 13.4 11.8 9.8 6.6 6.5 6.3 6.1 4.2%
CEZ 551.00 20.3 20.8 19.3 17.2 8.1 8.5 8.1 7.7 5.3% (premium / discount) to the median 53.8% 55.3% 63.4% 75.9% 22.3% 30.1% 29.7% 27.1% 27.9%
Implied Valuation Median 13.2 13.4 11.8 9.8 6.6 6.5 6.3 6.1 4.2% Multiple weight 33.3% 33.3% 33.3% Year weight 0.0% 33.3% 33.3% 33.3% 0.0% 33.3% 33.3% 33.3% Equity value per share (CZK) 361.4
32
Income Statement (CZK m) 2015 2016 2017 2018P 2019P 2020P 2021P Revenue 210,167 203,744 201,906 205,271 214,120 228,091 226,124 change 4.2% -3.1% -0.9% 1.7% 4.3% 6.5% -0.9%
EBITDA, of which 65,265 58,206 55,155 52,548 55,139 58,313 56,204 Generation 28,980 22,001 19,062 17,259 19,146 20,941 18,289 Mining 4,321 4,413 4,056 4,063 4,149 4,158 4,228 Renewables 2,374 3,402 4,988 4,359 4,802 5,033 5,133 Distribution 20,082 20,386 19,067 19,627 20,119 20,534 20,922 Sales 6,898 5,489 4,613 4,964 4,525 4,911 4,937 Others & intercompany eliminations 2,610 2,515 3,369 2,276 2,399 2,737 2,695
EBIT 28,961 26,114 25,620 23,859 25,601 29,030 26,205 change -21.6% -9.8% -1.9% -6.9% 7.3% 13.4% -9.7% EBIT margin 13.8% 12.8% 12.7% 11.6% 12.0% 12.7% 11.6%
Financing gains / losses -5,889 -6,786 -2,867 -6,083 -6,488 -7,567 -8,830 Tax on carbon allowances 3,823 0 0 0 0 0 0
Pre-tax income 26,895 19,328 22,753 17,776 19,114 21,463 17,376 Tax 6,348 4,753 3,794 3,377 3,632 4,078 3,302 Minority interests -192 294 194 147 158 178 144
Net income 20,739 14,281 18,765 14,251 15,324 17,207 13,930 change -7.4% -31.1% 31.4% -24.1% 7.5% 12.3% -19.0% margin 9.9% 7.0% 9.3% 6.9% 7.2% 7.5% 6.2%
D&A 36,304 32,092 29,535 28,690 29,538 29,283 29,999 EBITDA 65,265 58,206 55,155 52,548 55,139 58,313 56,204 change -10.2% -10.8% -5.2% -4.7% 4.9% 5.8% -3.6% EBITDA margin 31.1% 28.6% 27.3% 25.6% 25.8% 25.6% 24.9%
Shares at year-end (millions) 538.0 538.0 538.0 538.0 538.0 538.0 538.0 EPS 38.5 26.5 34.9 26.5 28.5 32.0 25.9 CEPS 106.0 86.2 89.8 79.8 83.4 86.4 81.7
ROAE 7.8% 5.4% 7.4% 5.7% 6.2% 6.9% 5.6% ROAA 3.4% 2.3% 3.0% 2.3% 2.4% 2.7% 2.2%
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Balance Sheet (CZK m) 2015 2016 2017 2018P 2019P 2020P 2021P ASSETS 602,686 630,841 626,207 630,398 637,166 647,029 645,166 Fixed assets 493,055 489,254 487,953 490,548 491,902 493,217 492,556 Property, plant and equipment 408,367 412,003 412,801 415,028 416,159 417,337 416,688 Intangible assets 20,164 21,983 26,804 26,318 25,781 25,250 24,668 Equity investment 9,239 5,309 3,520 3,520 3,520 3,520 3,520 Other fixed assets 55,285 49,959 44,828 45,681 46,443 47,110 47,680
Current assets 109,631 141,587 138,254 139,850 145,264 153,812 152,609 Inventory 10,131 8,516 10,558 10,264 10,706 11,405 11,306 Current receivables 46,003 56,331 57,766 58,729 61,260 65,258 64,695 Other current assets 40,015 65,410 57,307 58,025 59,911 62,890 62,471 Cash and cash equivalents 13,482 11,330 12,623 12,833 13,387 14,260 14,137
(CZK m) 2015 2016 2017 2018P 2019P 2020P 2021P EQUITY AND LIABILITIES 602,686 630,841 626,207 630,398 637,166 647,029 645,166 Equity 267,893 256,812 250,018 246,515 247,588 249,471 246,195 Share capital 53,799 53,799 53,799 53,799 53,799 53,799 53,799 Other equity 214,094 203,013 196,219 192,716 193,789 195,672 192,396
Minority interests 4,262 4,548 4,304 4,304 4,304 4,304 4,304
Long-term liabilities 236,832 240,041 241,603 243,005 244,588 246,230 248,142 Loans 145,575 142,265 132,475 133,877 135,460 137,102 139,014 Other 91,257 97,776 109,128 109,128 109,128 109,128 109,128
Current liabilities 93,699 129,440 130,282 136,573 140,686 147,024 146,524 Loans 11,919 25,551 19,694 24,531 24,821 25,122 25,473 Trade creditors 58,010 80,516 87,236 88,690 92,513 98,549 97,700 Other 23,770 23,373 23,352 23,352 23,352 23,352 23,352
Debt 157,494 167,816 152,169 158,409 160,281 162,225 164,486 Net debt 131,899 140,886 139,546 145,575 146,895 147,964 150,349 (Net debt / Equity) 49.2% 54.9% 55.8% 59.1% 59.3% 59.3% 61.1% (Net debt / EBITDA) 2.0 2.4 2.5 2.8 2.7 2.5 2.7
BVPS 498.0 477.4 464.7 458.2 460.2 463.7 457.6
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Cash Flow (CZK m) 2015 2016 2017 2018P 2019P 2020P 2021P Cash flow from operating activities 72,579 48,953 45,812 50,596 51,919 54,136 54,802 Net income 20,739 14,281 18,765 14,251 15,324 17,207 13,931 D&A 28,619 28,978 29,305 28,690 29,538 29,283 29,999 Working capital -579 -9,295 355 786 849 1,341 -189 Other 23,800 14,989 -2,613 6,870 6,208 6,305 11,061
Cash flow from investing activities -31,570 -34,571 -20,212 -34,963 -34,663 -34,463 -33,300 CAPEX -31,909 -35,553 -30,688 -34,963 -34,663 -34,463 -33,300 Other 339 982 10,476 0 0 0 0
Cash flow from financing activities -47,374 -16,540 -24,107 -15,423 -16,702 -18,800 -21,625 Share issue 0 0 0 0 0 0 0 Debt -26,062 5,480 -6,150 6,240 1,873 1,943 2,262 Dividend (buy-back) -21,309 -21,325 -17,618 -17,754 -14,251 -15,324 -17,207 Other -3 -695 -339 -3,909 -4,324 -5,419 -6,680
Change in cash -6,613 -2,152 1,293 210 553 873 -123 Cash at period-end 13,482 11,330 12,623 12,833 13,387 14,260 14,137
DPS (CZK) 40.0 40.0 33.0 33.0 26.5 28.5 32.0 FCF 26,429 8,605 21,028 14,994 17,694 21,113 19,414 (CAPEX/Sales) 15.2% 17.4% 15.2% 17.0% 16.2% 15.1% 14.7%
Trading Multiples 2015 2016 2017 2018P 2019P 2020P 2021P P/E 14.3 20.8 15.8 20.8 19.3 17.2 21.3 P/CE 5.2 6.4 6.1 6.9 6.6 6.4 6.7 P/BV 1.1 1.2 1.2 1.2 1.2 1.2 1.2 P/S 1.4 1.5 1.5 1.4 1.4 1.3 1.3
FCF/EV 6.1% 1.9% 4.8% 3.4% 4.0% 4.7% 4.3% EV/EBITDA 6.6 7.6 8.0 8.5 8.1 7.7 8.0 EV/EBIT 14.9 16.9 17.2 18.7 17.5 15.5 17.2 EV/S 2.1 2.2 2.2 2.2 2.1 2.0 2.0
DYield 7.2% 7.2% 5.9% 6.0% 4.8% 5.2% 5.8%
Price (CZK) 551.0 Shares at year-end (millions) 538.0 538.0 538.0 538.0 538.0 538.0 538.0 MC (CZK m) 296,432 296,432 296,432 296,432 296,432 296,432 296,432 Minority interests (CZK m) 4,262 4,548 4,304 4,304 4,304 4,304 4,304 EV (CZK m) 432,593 441,866 440,282 446,312 447,631 448,701 451,086
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podwyższona Tuesday, May 29, 2018 | update podtrzymana Enea: buy (reiterated) obniżona ENA PW; ENAE.WA | Power Utilities, Poland 2019 Outlook Boosted by Coal & Power Price Rally Current Price PLN 9.57 Target Price PLN 12.62 Enea is trading at a cheap 2018-2020E EV/EBITDA ratio of 3.8x, an Market Cap PLN 4.22bn aftermath of a destroyed investment profile reflecting the Company's looming state-led involvement in loss-making energy Free Float PLN 2.05bn projects, and, most recently, a freeze on dividends announced at a ADTV (3M) PLN 12.35m time when capital expenditures are about to drop and debt is relatively low. When it comes to core business, however, Enea has Ownership solid prospects ahead in our view in terms of earnings and cash State Treasury 51.50% flow, and we consider the 2019 earnings consensus for the Company TFI PZU 9.96% to be underestimated by 10%. Upward revisions by analysts could restore the market's confidence in Enea, with the upside potential in the coming months set to be reinforced further as the capacity Others 38.54% market takes shape, and if the planned 1000 MW coal-based “Ostrołęka C” project is shelved because of unsustainable costs. We Business Profile maintain a buy rating for ENA, with the price target raised to Enea is one of Poland's largest vertically-integrated PLN 12.62 per share to reflect a more optimistic outlook on power energy groups with a market share of 14% and a prices. customer base of 2.3 million. Its core production assets include a 3.88 GW power station in Kozienice, a 1.9 GW power station in Połaniec, acquired last Positive exposure to coal and power prices year, and a CHP in Białystok. Enea also controls the Thanks to its unique, vertically-integrated business model, Enea stands to listed coal miner LW Bogdanka, producing over benefit more from the improving market conditions than any of its local 9mmt of coal per year. competitors. Its subsidiary coal mine, with its incomparably low production costs, can arguably generate PLN 150-200m additional EBITDA per year ENA vs. WIG after any PLN 1 rise in the price of a gigajoule of coal energy. At the same time, Enea's new 1000 MW generator, with carbon emissions of less than 16 0.7 t/MWh, given the rising prices of emission allowances can add a further PLN PLN 50m per every 5 euros more paid for a tonne of emissions, on top of savings on internal coal supplies. 14
Positive FCF Enea has just finished a 1075 MW generator at its power station in 12 Kozienice, suggesting a substantial reduction in capital expenditure going forward. Even assuming it has to pay 50% of the costs of the “Ostrołęka C” plant, we predict Enea has the capacity to generate fee cash flow of PLN 0.5bn in 2018-2022, and report a net debt/EBITDA ratio of 2.2x at the 10 end of 2018. This assuming higher CAPEX than the Company is guiding for ENA itself (PLN 21bn vs. PLN 18bn, not counting Ostrołęka C). WIG
8 Toxic projects The two state-led projects that are weighing down Enea’s performance are
Ostrołęka C and a coal gasification plant for the Company’s coal mine. Our Feb-18
Aug-17
Nov-17
May-17 May-18 valuation model for Enea factors in the Ostrołęka C project at an assumed negative NPV of PLN 0.53bn (and an assumed PLN 0.3bn boost to value if the project, which has already generated costs at the planning stages, is Target Price Rating shelved). At the same time, we choose to leave out the IGCC project out of Name our forecasts because it shows zero viability even with major concessions new old new old made in the calculations (the profitability of an IGCC plant is shaped by the Enea 12.62 11.78 buy buy spread between the costs of power production from coal versus natural gas, Current Target Upside/ Name which has to be 30 euros minimum to break even compared to the current 7 Price Price Downside euros). Enea 9.57 12.62 +31.9% Forecast revision (PLN m) 2016 2017 2018E 2019E 2020E 2018E 2019E 2020E since last update Revenue 11,255.7 11,405.7 12,232.3 14,265.3 13,951.4 EBITDA -3.3% +11.1% +7.9% EBITDA 2,327.8 2,683.6 2,845.4 3,290.0 2,984.1 Net profit -6.0% +27.6% +24.9% EBITDA margin 20.7% 23.5% 23.3% 23.1% 21.4% EBIT 1,119.3 1,487.7 1,431.4 1,834.3 1,509.1 Power price (EUR/MWh) +1.5% +19.2% +17.4% Net profit 784.4 1,070.2 919.2 1,190.3 945.8 Coal price (PLN/t) +2.5% +5.9% +4.5%
P/E 5.4 3.9 4.6 3.5 4.5 Carbon price (EUR/t) +40.0% +38.5% +36.9% P/CE 2.1 1.9 1.8 1.6 1.7 P/BV 0.3 0.3 0.3 0.3 0.3 Analyst: EV/EBITDA 4.1 4.0 4.0 3.5 3.9 DPS 0.00 0.28 0.00 0.00 0.00 Kamil Kliszcz +48 22 438 24 02 DYield 0.0% 2.9% 0.0% 0.0% 0.0% [email protected]
Valuation We calculated our price target for Enea using only DCF (PLN) weight price valuation, as the relative valuation method (provided Relative Valuation 0% 18.20 below for reference only) cannot produce an accurate estimate of the Company's value in our view due to the DCF Analysis 100% 11.77 heightened political risks weighing on Polish utilities, not price 11.77 experienced by comparable foreign companies. The DCF 9M target price 12.62 model yielded a price target of PLN 12.62 per share.
DCF Valuation
Assumptions: . Macroeconomic assumptions and capital investment . Cash flows are discounted to their present value as of plans are as set out in the table below. the end of May 2018. Equity value calculations factor in . We assume that FCF after FY2027 will grow at an minority interests and net debt as of 31 December annual rate of 2%. The risk-free rate is 3.5%, and beta 2017. is 1.1. . The final valuation is adjusted for potential tax on a capital reserve conversion to equity that may be required by the government.
Additional Assumptions: 2017 2018P 2019P 2020P 2021P 2022P 2023P 2024P 2025P 2026P 2027P Price of electricity (EEX, EUR/MWh) 32.4 41.2 42.3 38.6 39.2 39.6 40.1 40.6 41.1 41.6 42.2 Price of electricity (POLPX, PLN/MWh) 159.7 168.5 203.8 194.1 179.0 180.1 181.2 182.4 183.7 185.1 186.5 Price of a carbon allowance (EUR/t) 5.9 14.0 14.6 15.2 15.8 16.4 17.1 17.8 18.5 19.2 20.0 Price of thermal coal (PLN/t) 205.1 230.0 233.9 214.4 214.4 214.4 214.4 214.4 214.4 214.4 214.4 PLN/USD (annual avg.) 3.77 3.54 3.60 3.70 3.70 3.70 3.70 3.70 3.70 3.70 3.70 EUR/PLN (annual avg.) 4.26 4.17 4.15 4.15 4.15 4.15 4.15 4.15 4.15 4.15 4.15 Electricity output (TWh), of which: 21.8 24.6 28.2 28.2 27.7 27.7 28.7 30.2 30.2 30.2 30.2 hard coal-fired power 19.6 22.7 26.2 26.2 25.7 25.7 26.7 28.2 28.2 28.2 28.2 cogeneration 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 hydroelectric power 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 wind energy 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 biomass-fired power 1.9 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 Distribution volume (TWh) 19.3 19.6 20.0 20.4 20.8 21.3 21.7 22.1 22.6 23.0 23.5
37
DCF Model (PLN m) 2018P 2019P 2020P 2021P 2022P 2023P 2024P 2025P 2026P 2027P 2027+ Revenue 12,232 14,265 13,951 13,373 13,538 13,812 14,142 14,345 14,560 14,787 14,787 change 7.2% 16.6% -2.2% -4.1% 1.2% 2.0% 2.4% 1.4% 1.5% 1.6% 0.0% EBITDA 2,845.4 3,290.0 2,984.1 3,225.8 3,217.3 3,308.8 3,420.1 3,423.0 3,431.2 3,443.1 3,443.1 EBITDA margin 23.3% 23.1% 21.4% 24.1% 23.8% 24.0% 24.2% 23.9% 23.6% 23.3% 23.3% D&A 1,414.1 1,455.8 1,475.0 1,507.9 1,513.0 1,578.0 1,646.7 1,681.3 1,720.6 1,764.3 2,166.5 EBIT 1,431.4 1,834.3 1,509.1 1,717.9 1,704.3 1,730.8 1,773.4 1,741.7 1,710.6 1,678.8 1,276.6 EBIT margin 11.7% 12.9% 10.8% 12.8% 12.6% 12.5% 12.5% 12.1% 11.7% 11.4% 8.6% Tax on EBIT 272.0 348.5 286.7 326.4 323.8 328.9 336.9 330.9 325.0 319.0 242.6 NOPLAT 1,159.4 1,485.8 1,222.4 1,391.5 1,380.5 1,402.0 1,436.4 1,410.8 1,385.6 1,359.8 1,034.0
CAPEX -2,430.4 -2,414.9 -2,851.6 -2,891.0 -2,695.7 -2,239.6 -2,061.7 -2,095.6 -2,130.6 -2,166.5 -2,166.5 Working capital -603.2 -216.3 272.3 51.7 -14.7 -24.5 -29.4 -18.2 -19.2 -20.2 -20.2 Equity investment 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
FCF -460.2 310.3 118.2 60.1 183.1 715.8 992.0 978.3 956.3 937.4 1,013.8 WACC 6.6% 6.9% 7.0% 6.8% 6.7% 6.8% 6.9% 7.0% 7.1% 7.2% 7.4% Discount factor 96.3% 90.1% 84.2% 78.8% 73.9% 69.2% 64.7% 60.5% 56.5% 52.7% 52.7% PV FCF -443.2 279.7 99.6 47.4 135.3 495.4 642.2 591.9 540.2 494.0
WACC 6.6% 6.9% 7.0% 6.8% 6.7% 6.8% 6.9% 7.0% 7.1% 7.2% 7.4% Cost of debt 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% Risk-free rate 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% Risk premium 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% Effective tax rate 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% Net debt / EV 43.9% 39.6% 37.9% 40.3% 42.6% 41.7% 39.3% 37.3% 35.4% 33.7% 30.0%
Cost of equity 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% Risk premium 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% Beta 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1
FCF growth after the forecast period 2.0% Sensitivity Analysis
Terminal value 18,797 FCF growth in perpetuity
Present value of terminal value 9,905 0.0% 1.0% 2.0% 3.0% 4.0%
Present value of FCF in the forecast period 2,882.4 WACC +1.0 p.p. 4.0 6.1 8.9 12.6 18.1
Enterprise value 12,788 WACC +0.5 p.p. 5.0 7.4 10.6 15.1 21.9
Net debt (eoy 2017) 5,523.1 WACC 6.1 8.9 12.6 18.1 26.8
Minority interests 921.5 WACC -0.5 p.p. 7.4 10.6 15.1 21.9 33.4
Potential capital conversion tax -1,147.1 WACC -1.0 p.p. 8.9 12.6 18.1 26.8 42.8
Equity value 5,196
Number of shares (millions) 441.4
Equity value per share (PLN) 11.8
9M cost of equity 6.7%
Target price (PLN) 12.6
EV/EBITDA ('18) at target price 4.2
P/E('18) at target price 6.1
TV / EV 77%
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Relative Valuation
We compared Enea's forward P/E and EV/EBITDA multiples used (fuels, emissions, age of installed capacity), and the and projected dividend yields with the multiples and yields shares of different operating segments in total earnings. of the Company's peers as projected for fiscal 2018 We assigned equal weights to each multiple and forecast through 2020. The peer group comprises vertically- year. The calculations pertaining to PGE and Enea are integrated power producers as well as utilities focusing adjusted for compensation received under long-term power mainly on regulated distribution of electricity and purchase agreements. renewable energy. It is diversified in terms of technology
Multiples Comparison P/E EV/EBITDA 2018- 2020E Price 2017 2018E 2019E 2020E 2017 2018E 2019E 2020E DYield EDF 11.47 21.8 19.0 16.0 13.6 5.9 6.1 5.7 5.6 3.0% EDP 3.38 15.1 15.9 14.4 14.0 8.8 9.1 8.5 8.2 5.6% ENDESA 19.19 14.5 14.3 13.9 13.8 7.4 7.5 7.4 7.3 7.2% ENEL 4.71 13.2 11.6 10.4 9.8 6.6 6.5 6.3 6.1 6.6% EON 9.17 14.4 13.9 13.0 12.2 8.9 7.4 7.2 6.6 5.2% INNOGY 35.85 16.2 17.6 16.9 16.3 8.6 8.9 9.1 9.0 4.6% RWE 19.75 10.0 13.4 11.8 9.7 6.9 7.2 7.2 7.5 4.2% CEZ 551.00 20.3 20.8 19.3 17.2 8.1 8.5 8.1 7.7 5.3% ENERGA 9.00 4.8 4.7 4.5 4.6 3.6 3.4 3.3 3.4 0.0% PGE 9.28 10.4 5.7 5.6 6.0 4.0 3.5 3.3 3.1 1.5% TAURON 2.01 2.9 2.7 3.3 3.1 3.7 3.8 4.3 3.8 0.0%
Maximum 21.8 20.8 19.3 17.2 8.9 9.1 9.1 9.0 7.2% Minimum 2.9 2.7 3.3 3.1 3.6 3.4 3.3 3.1 0.0% Median 14.4 13.9 13.0 12.2 6.9 7.2 7.2 6.6 4.6%
ENEA 9.57 3.9 4.6 3.5 4.5 4.0 4.0 3.5 3.9 0.0% (premium / discount) to the median -72.7% -67.0% -72.7% -63.4% -42.2% -44.0% -51.3% -40.7% -100.0%
Implied valuation Median 14.4 13.9 13.0 12.2 6.9 7.2 7.2 6.6 4.6% Multiple weight 33.3% 33.3% 33.3% Year weight 0.0% 33.3% 33.3% 33.3% 0.0% 33.3% 33.3% 33.3%
Implied valuation (PLN) 20.8 Potential capital conversion tax -2.6 Equity value per share (PLN) 18.2
39
Income Statement (PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P Revenue 9,848.4 11,255.7 11,405.7 12,232.3 14,265.3 13,951.4 13,372.8 change -0.1% 14.3% 1.3% 7.2% 16.6% -2.2% -4.1% of which PPA compensation 293.0 0.0 0.0 0.0 0.0 0.0 0.0
EBITDA, of which 2,129.9 2,327.8 2,683.6 2,845.4 3,290.0 2,984.1 3,225.8 Generation 895.4 517.5 735.3 901.7 1,247.2 1,020.4 1,191.0 Mining 114.4 608.6 709.0 652.5 754.8 605.9 605.9 Trade 126.1 154.0 177.8 200.6 167.3 189.4 225.8 Distribution 1,138.9 1,111.3 1,073.4 1,129.3 1,159.5 1,208.2 1,247.2 Other & intercompany eliminations -44.9 -13.6 39.5 15.5 16.9 17.2 14.3 Unattributed costs -141.7 -53.2 -52.8 -54.2 -55.5 -56.9 -58.3
EBIT -162.1 1,119.3 1,487.7 1,431.4 1,834.3 1,509.1 1,717.9 change -113.7% -790.4% 32.9% -3.8% 28.1% -17.7% 13.8% EBIT margin -1.6% 9.9% 13.0% 11.7% 12.9% 10.8% 12.8%
Financing gains / losses 2.7 -50.7 -31.0 -194.1 -220.6 -257.9 -270.5 Extraordinary gains/losses 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Other -249.6 0.1 9.8 9.8 9.8 9.8 9.8
Pre-tax income -409.0 1,068.8 1,466.6 1,247.1 1,623.5 1,261.0 1,457.2 Tax -10.1 219.9 301.7 236.9 308.5 239.6 276.9 Minority interests 36.0 64.5 94.7 91.0 124.7 75.6 75.6
Net income -434.9 784.4 1,070.2 919.2 1,190.3 945.8 1,104.8 change -147.9% -280.4% 36.4% -14.1% 29.5% -20.5% 16.8% margin -4.4% 7.0% 9.4% 7.5% 8.3% 6.8% 8.3%
D&A 2,292.0 1,208.5 1,195.8 1,414.1 1,455.8 1,475.0 1,507.9 EBITDA 2,129.9 2,327.8 2,683.6 2,845.4 3,290.0 2,984.1 3,225.8 change 9.5% 9.3% 15.3% 6.0% 15.6% -9.3% 8.1% EBITDA margin 21.6% 20.7% 23.5% 23.3% 23.1% 21.4% 24.1%
Shares at year-end (millions) 441.4 441.4 441.4 441.4 441.4 441.4 441.4 EPS -1.0 1.8 2.4 2.1 2.7 2.1 2.5 CEPS 4.2 4.5 5.1 5.3 6.0 5.5 5.9
ROAE -3.7% 6.7% 8.5% 6.8% 8.2% 6.0% 6.7% ROAA -2.1% 3.3% 4.0% 3.2% 4.1% 3.1% 3.5%
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Balance Sheet (PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P ASSETS 22,989.0 24,536.5 28,313.0 28,594.3 29,621.6 30,654.2 31,853.7 Fixed assets 18,203.4 19,486.6 22,080.9 23,097.2 24,056.3 25,432.9 26,815.9 Property, plant and equipment 17,075.0 18,382.5 20,416.9 21,418.7 22,392.7 23,769.2 25,151.0 Intangible assets 272.1 370.6 418.2 432.7 417.8 417.9 419.1 Equity investment 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Other fixed assets 856.3 733.5 1,245.8 1,245.8 1,245.8 1,245.8 1,245.8
Current assets 4,785.6 5,049.9 6,232.1 5,497.1 5,565.3 5,221.3 5,037.8 Inventory 649.5 448.9 846.2 882.3 1,028.9 767.3 735.5 Current receivables 1,732.7 1,824.5 1,903.6 1,984.8 2,314.6 2,263.7 2,169.8 Other current assets 581.2 436.3 795.2 795.2 795.2 795.2 795.2 Cash and cash equivalents 1,822.1 2,340.2 2,687.1 1,834.9 1,426.5 1,395.1 1,337.3
(PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P EQUITY AND LIABILITIES 22,989.0 24,536.5 28,313.0 28,594.3 29,621.6 30,654.2 31,853.7 Equity 11,337.7 12,176.0 13,078.2 13,987.6 15,168.0 16,104.0 16,726.1 Share capital 588.0 588.0 588.0 588.0 588.0 588.0 588.0 Other equity 10,749.7 11,588.0 12,490.2 13,399.6 14,580.0 15,516.0 16,138.1
Minority interests 784.9 835.7 921.5 1,012.4 1,137.2 1,212.8 1,288.4
Long-term liabilities 8,457.8 8,606.8 10,063.0 9,845.2 9,342.2 9,399.4 9,937.7 Loans 5,933.4 6,275.6 7,720.1 7,502.3 6,999.3 7,056.5 7,594.8 Other 2,524.5 2,331.1 2,342.9 2,342.9 2,342.9 2,342.9 2,342.9
Current liabilities 2,408.6 2,918.0 4,250.3 3,749.1 3,974.1 3,938.0 3,901.5 Loans 43.4 448.9 539.4 524.2 489.1 493.1 530.7 Trade creditors 1,223.3 1,141.6 2,051.4 1,565.4 1,825.6 1,785.4 1,711.4 Other 1,141.8 1,327.5 1,659.5 1,659.5 1,659.5 1,659.5 1,659.5
Debt 5,976.8 6,724.5 8,259.5 8,026.5 7,488.4 7,549.6 8,125.4 Net debt 3,932.2 4,379.0 5,522.6 6,141.8 6,012.0 6,104.6 6,738.3 (Net debt / Equity) 34.7% 36.0% 42.2% 43.9% 39.6% 37.9% 40.3% (Net debt / EBITDA) 1.8 1.9 2.1 2.2 1.8 2.0 2.1
BVPS 25.7 27.6 29.6 31.7 34.4 36.5 37.9
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Cash Flow (PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P Cash flow from operating activities 2,206.4 2,424.4 2,579.6 2,005.3 2,765.2 3,016.9 3,000.6 Net income -434.9 784.4 1,070.2 919.2 1,190.3 945.8 1,104.8 D&A 790.4 1,110.4 1,194.5 1,414.1 1,455.8 1,475.0 1,507.9 Working capital 116.8 206.2 291.6 -603.2 -216.3 272.3 51.7 Other 1734.1 323.5 23.4 275.3 335.5 323.7 336.3
Cash flow from investing activities -3,724.7 -2,490.6 -3,482.9 -2,389.4 -2,379.1 -2,811.8 -2,852.4 CAPEX -2,847.4 -2,688.4 -2,058.0 -2,430.4 -2,414.9 -2,851.6 -2,891.0 Other -877.3 197.8 -1424.9 41.0 35.8 39.8 38.5
Cash flow from financing activities 2,653.0 584.3 1,250.2 -468.2 -794.5 -236.5 -206.1 Share issue 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Debt 2,979.9 761.6 1,560.4 -233.1 -538.1 61.2 575.9 Dividend (buy-back) -208.3 -1.1 -122.4 0.0 0.0 0.0 -472.9 Other -118.5 -176.2 -187.8 -235.1 -256.4 -297.7 -309.0
Change in cash 1,134.8 518.1 346.9 -852.3 -408.3 -31.4 -57.9 Cash at period-end 1,822.1 2,340.2 2,687.1 1,834.9 1,426.5 1,395.1 1,337.3
DPS (PLN) 0.47 0.00 0.28 0.00 0.00 0.00 1.07 FCF -590.6 -374.3 615.5 -425.1 350.4 165.3 109.7 (CAPEX/Sales) 28.9% 23.9% 18.0% 19.9% 16.9% 20.4% 21.6%
Trading Multiples 2015 2016 2017 2018P 2019P 2020P 2021P P/E -9.7 5.4 3.9 4.6 3.5 4.5 3.8 P/CE 2.3 2.1 1.9 1.8 1.6 1.7 1.6 P/BV 0.4 0.3 0.3 0.3 0.3 0.3 0.3 P/S 0.4 0.4 0.4 0.3 0.3 0.3 0.3
FCF/EV -6.6% -4.0% 5.8% -3.7% 3.1% 1.4% 0.9% EV/EBITDA 4.2 4.1 4.0 4.0 3.5 3.9 3.8 EV/EBIT -55.2 8.4 7.2 7.9 6.2 7.6 7.1 EV/S 0.9 0.8 0.9 0.9 0.8 0.8 0.9
DYield 4.9% 0.0% 2.9% 0.0% 0.0% 0.0% 11.2%
Price (PLN) 9.57 Shares at year-end (millions) 441.4 441.4 441.4 441.4 441.4 441.4 441.4 MC (PLN m) 4,224.6 4,224.6 4,224.6 4,224.6 4,224.6 4,224.6 4,224.6 Minority interests (PLN m) 784.9 835.7 921.5 1012.4 1137.2 1212.8 1288.4 EV (PLN m) 8,941.6 9,439.3 10,668.6 11,378.8 11,373.8 11,542.0 12,251.3
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podwyższona Tuesday, May 29, 2018 | update podtrzymana Energa: buy (reiterated) obniżona ENG PW; ENGP.WA | Power Utilities, Poland Baffling Discount To Benchmark Current Price PLN 9.00 Target Price PLN 15.58 Energa generates 90% of annual EBITDA from distribution and Market Cap PLN 3.73bn renewable energy, and the investment it plans to 2018-2025 allocates only 20-25% of the total budget to coal-based capacity. In Free Float PLN 1.81bn theory, this should earn the Utility a premium as the world moves ADTV (3M) PLN 16.26m away from coal, and as prices of emissions are about to take off, but in reality, at 3.4x EV/EBITDA ENG stock is trading at a discount even Ownership to its much more coal-dependent local rivals. Meanwhile, Energa’s State Treasury 51.52% earnings prospects continue to improve as prices of electricity and
green certificates increase, and its future returns on distribution assets show growth potential resulting from rising interest rates. Others 48.48% With the net debt/EBITDA ratio not likely to exceed 1.7x at the end of 2018, Energa will be able to offer generous distributions to Business Profile shareholders in the future assuming it goes back to its usual Energa is a top-4 vertically integrated power dividend policy (a 10% dividend yield would have little noticeable producer in Poland. At the same time, it is the third- impact on the leverage ratio). We maintain a buy rating for ENG, largest distribution system operator (22.1 TWh in with the price target raised to PLN 15.58 per share. 2017) and power seller (with a 16% market share). In 2017 Energa power plants generated a total of 4.3 TWh of power, of which 36% produced by Grossly undervalued generation business renewable power plants. A sum-of-the-parts analysis of Energa’s business reveals that the market currently assigns negative value of a staggering PLN 5 billion to the ENG vs. WIG generation business even though these assets generate annual EBITDA over PLN 0.3 billion. Not even Energa’s 50% involvement (jointly with Enea) in 16 the planned 1000 MW coal-based “Ostrołęka C” project, with an estimated negative NPV of PLN 0.5bn, or the potential costs of pending cases against PLN wind farms, can account for this negative valuation. Note that Energa's 14 participation any other potential major loss-making projects is limited by its borrowing capacity.
Rising profits from renewables 12 As the owner of 0.4 GW of renewable generation capacity and a large hydroelectric power plant, Energa is poised to benefit from the recent upward shift in the prices of electric power and green certificates. We 10 estimate the boost to the annual revenues at PLN 80+ million, equivalent to ENG nearly 4% of consolidated EBITDA. WIG Energa v. wind farms 8 In 2017 Energa terminated long-term fixed-price power purchase contracts
with 22 wind farms, saying it expected the resulting savings to reach
Feb-18
Aug-17
Nov-17 May-18 PLN 2.1bn. The operators sued, and in May 2018 one 48 MW installation May-17 agreed to settle out of court. Even assuming Energa loses the other cases after failed settlement talks, at the current price level, it would face a loss of about PLN 1.4bn by buying back the green certificates from the wind farms at the contractual prices (the NPV of the potential outlay is PLN 1bn, Target Price Rating equivalent to 26% of the current market cap). Name new old new old Energa 15.58 14.91 buy buy Current Target Upside/ Name Price Price Downside Energa 9.00 15.58 +73.1%
(PLN m) 2016 2017 2018E 209E 2020E Forecast revision 2018E 2019E 2020E Revenue 10,181.0 10,534.0 11,286.9 12,428.2 12,370.4 EBITDA -1.6% +0.5% +3.7% EBITDA 2,027.0 2,160.0 2,268.0 2,360.4 2,362.2 Net profit -3.3% +1.5% +10.2% EBITDA margin 19.9% 20.5% 20.1% 19.0% 19.1% EBIT 487.0 1,210.0 1,248.9 1,288.4 1,295.8 Power price (EUR/MWh) +1.5% +19.2% +17.4% Net profit 151.0 773.0 799.9 828.2 805.5 Coal price (PLN/t) +2.5% +5.9% +4.5% P/E 24.4 4.8 4.6 4.4 4.6 Carbon price (EUR/t) +40.0% +38.5% +36.9% P/CE 2.2 2.1 2.0 1.9 2.0 P/BV 0.4 0.4 0.4 0.3 0.3 Analyst: EV/EBITDA 4.1 3.6 3.4 3.3 3.4 Kamil Kliszcz DPS 0.49 0.19 0.00 0.00 0.00 +48 22 438 24 02 DYield 5.5% 2.1% 0.0% 0.0% 0.0% [email protected]
Valuation
We calculated our price target for Energa using only DCF (PLN) weight price valuation, as the relative valuation method (provided Relative Valuation 0% 17.80 below for reference only) cannot produce an accurate estimate of the Company's value in our view due to the DCF Analysis 100% 14.60 heightened political risks weighing on Polish utilities, not price 14.60 experienced by comparable foreign companies. The DCF 9M target price 15.58 model yielded a price target of PLN 15.58 per share.
DCF Valuation
Assumptions: . Macroeconomic assumptions and capital investment . Cash flows are discounted to their present value as of plans are as set out in the table below. the end of May 2018. Equity value calculations factor in . We assume that FCF after FY2027 will grow at an minority interests and net debt as of 31 December annual rate of 2%. The risk-free rate is 3.5%, and beta 2017. is 1.1. . The final valuation is adjusted for potential tax on a capital reserve conversion to equity that may be required by the government.
Additional Assumptions: 2017 2018P 2019P 2020P 2021P 2022P 2023P 2024P 2025P 2026P 2027P Price of electricity (EEX, EUR/MWh) 32.4 41.2 42.3 38.6 39.2 39.6 40.1 40.6 41.1 41.6 42.2 Price of electricity (POLPX, PLN/MWh) 159.7 168.5 203.8 194.1 179.0 180.1 181.2 182.4 183.7 185.1 186.5 Price of a carbon allowance (EUR/t) 5.9 14.0 14.6 15.2 15.8 16.4 17.1 17.8 18.5 19.2 20.0 Price of a green certificate (PLN/MWh) 36.5 75.0 89.2 106.1 126.1 150.0 150.0 150.0 150.0 150.0 150.0 Price of coal in Poland (PLN/t) 205.1 230.0 233.9 214.4 214.4 214.4 214.4 214.4 214.4 214.4 214.4 EUR/PLN (annual avg.) 4.26 4.17 4.15 4.15 4.15 4.15 4.15 4.15 4.15 4.15 4.15 Net electricity output (TWh), of which: 4.3 4.0 4.0 4.0 4.0 4.0 5.4 6.9 6.9 6.9 6.9 hard coal-fired power 2.7 2.4 2.4 2.4 2.4 2.4 3.9 5.4 5.4 5.4 5.4 cogeneration 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 wind energy 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 hydroelectric power 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 Power distribution (TWh) 22.1 22.5 23.0 23.4 23.9 24.4 24.9 25.3 25.9 26.4 26.9
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DCF Model (PLN m) 2018P 2019P 2020P 2021P 2022P 2023P 2024P 2025P 2026P 2027P 2027+ Revenue 11,287 12,428 12,370 12,149 12,324 12,554 12,689 12,827 12,969 13,113 13,113 change 7.1% 10.1% -0.5% -1.8% 1.4% 1.9% 1.1% 1.1% 1.1% 1.1% 0.0% EBITDA 2,268.0 2,360.4 2,362.2 2,248.5 2,240.9 2,397.1 2,573.4 2,625.2 2,676.7 2,727.0 2,707.0 EBITDA margin 20.1% 19.0% 19.1% 18.5% 18.2% 19.1% 20.3% 20.5% 20.6% 20.8% 20.6% D&A 1,019.1 1,071.9 1,066.4 1,107.9 1,067.5 1,134.1 1,204.4 1,239.5 1,276.8 1,271.9 1,501.5 EBIT 1,248.9 1,288.4 1,295.8 1,140.6 1,173.4 1,263.0 1,369.0 1,385.8 1,399.8 1,455.1 1,205.4 EBIT margin 11.1% 10.4% 10.5% 9.4% 9.5% 10.1% 10.8% 10.8% 10.8% 11.1% 9.2% Tax on EBIT 237.3 244.8 246.2 216.7 223.0 240.0 260.1 263.3 266.0 276.5 229.0 NOPLAT 1,011.6 1,043.6 1,049.6 923.9 950.5 1,023.0 1,108.9 1,122.5 1,133.9 1,178.6 976.4
CAPEX -1,573 -1,849 -2,202 -2,261 -2,087 -1,654 -1,485 -1,494 -1,499 -1,502 -1,502 Working capital -100.3 -152.0 7.7 29.6 -23.4 -30.6 -17.9 -18.5 -18.9 -19.2 -19.2
FCF 357.3 114.9 -77.8 -199.4 -92.5 472.6 810.0 850.0 892.6 929.8 957.3 WACC 7.5% 7.6% 7.6% 7.5% 7.5% 7.5% 7.7% 7.8% 8.0% 8.2% 7.9% Discount factor 95.9% 89.1% 82.9% 77.1% 71.7% 66.7% 61.9% 57.4% 53.2% 49.2% 49.2% PV FCF 342.6 102.4 -64.5 -153.7 -66.3 315.2 501.6 488.2 474.8 457.2
WACC 7.5% 7.6% 7.6% 7.5% 7.5% 7.5% 7.7% 7.8% 8.0% 8.2% 7.9% Cost of debt 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% Risk-free rate 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% Risk premium 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% Effective tax rate 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% Net debt / EV 27.8% 26.7% 26.8% 27.7% 28.7% 27.4% 24.8% 22.0% 19.1% 15.0% 20.0%
Cost of equity 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% Risk premium 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% Beta 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1
FCF growth after the forecast period 2.0% Sensitivity Analysis
Terminal value 16,145 FCF growth in perpetuity
Present value of terminal value 7,938 0.0% 1.0% 2.0% 3.0% 4.0%
Present value of FCF in the forecast period 2,398 WACC +1.0 p.p. 8.7 10.4 12.6 15.6 19.7
Enterprise value 10,336 WACC +0.5 p.p. 9.5 11.4 14.0 17.5 22.5
Net debt (eoy 2017) 4,064 WACC 10.4 12.6 15.6 19.7 26.0
Minority interests 56 WACC -0.5 p.p. 11.4 14.0 17.5 22.5 30.5
Potential capital conversion tax -170 WACC -1.0 p.p. 12.6 15.6 19.7 26.0 36.5
Equity value 6,046
Number of shares (millions) 414.1
Equity value per share (PLN) 14.6
9M cost of equity 6.7%
Target price (PLN) 15.6
EV/EBITDA('18) at DCF valuation 4.7
P/E('18) at DCF valuation 8.3
TV/EV 77%
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Relative Valuation
We compared Energa's forward P/E and EV/EBITDA used (fuels, emissions, age of installed capacity), and the multiples and projected dividend yields with the multiples shares of different operating segments in total earnings. and yields of the Company's peers as projected for fiscal We assigned equal weights to each multiple and forecast 2018 through 2020. The peer group comprises vertically- year. The calculations pertaining to PGE and Enea are integrated power producers as well as utilities focusing adjusted for compensation received under long-term power mainly on regulated distribution of electricity and purchase agreements. renewable energy. It is diversified in terms of technology
Multiples Comparison P/E EV/EBITDA 2018- 2020E Price 2017 2018E 2019E 2020E 2017 2018E 2019E 2020E DYield EDF 11.47 21.8 19.0 16.0 13.6 5.9 6.1 5.7 5.6 3.0% EDP 3.38 15.1 15.9 14.4 14.0 8.8 9.1 8.5 8.2 5.6% ENDESA 19.19 14.5 14.3 13.9 13.8 7.4 7.5 7.4 7.3 7.2% ENEL 4.71 13.2 11.6 10.4 9.8 6.6 6.5 6.3 6.1 6.6% EON 9.17 14.4 13.9 13.0 12.2 8.9 7.4 7.2 6.6 5.2% INNOGY 35.85 16.2 17.6 16.9 16.3 8.6 8.9 9.1 9.0 4.6% RWE 19.75 10.0 13.4 11.8 9.7 6.9 7.2 7.2 7.5 4.2% CEZ 551.00 20.3 20.8 19.3 17.2 8.1 8.5 8.1 7.7 5.3% ENEA 9.57 3.9 4.6 3.5 4.5 4.0 4.0 3.5 3.9 0.0% PGE 9.28 10.4 5.7 5.6 6.0 4.0 3.5 3.3 3.1 1.5% TAURON 2.01 2.9 2.7 3.3 3.1 3.7 3.8 4.3 3.8 0.0%
Maximum 21.8 20.8 19.3 17.2 8.9 9.1 9.1 9.0 7.2% Minimum 2.9 2.7 3.3 3.1 3.7 3.5 3.3 3.1 0.0% Median 14.4 13.9 13.0 12.2 6.9 7.2 7.2 6.6 4.6%
ENERGA 9.00 4.8 4.7 4.5 4.6 3.6 3.4 3.3 3.4 0.0% (premium / discount) to the median -66.6% -66.6% -65.4% -62.1% -47.6% -52.9% -53.7% -47.6% -100.0%
Implied valuation Median 14.4 13.9 13.0 12.2 6.9 7.2 7.2 6.6 4.6% Multiple weight 33.3% 33.3% 33.3% Year weight 0.0% 33.3% 33.3% 33.3% 0.0% 33.3% 33.3% 33.3% Valuation (PLN/share) 18.3 Potential capital conversion tax -0.4 Equity value per share (PLN) 17.8
46
Income Statement (PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P Revenue 10,804.0 10,181.0 10,534.0 11,286.9 12,428.2 12,370.4 12,148.5 change 2.0% -5.8% 3.5% 7.1% 10.1% -0.5% -1.8%
EBITDA, of which 2,213.0 2,027.0 2,160.0 2,268.0 2,360.4 2,362.2 2,248.5 Baseload Power Plants 149.0 152.0 189.0 170.4 170.1 119.2 -3.8 Renewables 228.0 119.0 169.0 165.5 228.3 224.5 214.6 Distribution 1,688.0 1,720.0 1,723.0 1,686.7 1,755.7 1,788.6 1,815.2 Trade 172.0 40.0 85.0 269.4 231.3 256.1 260.0 Heat 15.0 43.0 40.0 40.0 40.0 40.0 40.0 Other & intercompany eliminations -39.0 -48.0 -46.0 -63.8 -65.0 -66.2 -77.4
EBIT 1,280.0 487.0 1,210.0 1,248.9 1,288.4 1,295.8 1,140.6 change -11.5% -62.0% 148.5% 3.2% 3.2% 0.6% -12.0% EBIT margin 11.8% 4.8% 11.5% 11.1% 10.4% 10.5% 9.4%
Financing gains / losses -228.0 -230.0 -232.0 -225.5 -229.1 -265.2 -284.6 Extraordinary gains/losses 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Other 0.0 -52.0 24.0 0.0 0.0 0.0 0.0
Pre-tax income 1,052.0 205.0 1,002.0 1,023.5 1,059.3 1,030.5 856.0 Tax 212.0 58.0 213.0 217.6 225.2 219.1 182.0 Minority interests 8.0 -4.0 16.0 6.0 6.0 6.0 6.0 Net profit from discontinued operations 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Net income 832.0 151.0 773.0 799.9 828.2 805.5 668.0 change -15.3% -81.9% 411.9% 3.5% 3.5% -2.7% -17.1% margin 7.7% 1.5% 7.3% 7.1% 6.7% 6.5% 5.5%
D&A 933.0 1,540.0 950.0 1,019.1 1,071.9 1,066.4 1,107.9 EBITDA 2,213.0 2,027.0 2,160.0 2,268.0 2,360.4 2,362.2 2,248.5 -5.5% -8.4% 6.6% 5.0% 4.1% 0.1% -4.8% EBITDA margin 20.5% 19.9% 20.5% 20.1% 19.0% 19.1% 18.5%
Shares at year-end (millions) 414.1 414.1 414.1 414.1 414.1 414.1 414.1 EPS 2.0 0.4 1.9 1.9 2.0 1.9 1.6 CEPS 4.3 4.1 4.2 4.4 4.6 4.5 4.3
ROAE 9.6% 1.7% 8.5% 8.2% 7.8% 7.0% 5.5% ROAA 4.5% 0.8% 3.9% 3.7% 3.7% 3.5% 2.7%
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Balance Sheet (PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P ASSETS 18,456.0 18,731.0 21,056.0 21,766.9 22,781.4 23,904.5 25,011.1 Fixed assets 13,873.0 14,515.0 14,930.0 15,484.0 16,260.7 17,395.8 18,548.7 Property, plant and equipment 12,912.0 13,053.0 13,371.0 13,863.3 14,557.5 15,577.4 16,613.0 Intangible assets 395.0 383.0 338.0 399.7 482.3 597.5 714.7 Other financial assets 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Other non-financial assets 306.0 683.0 896.0 896.0 896.0 896.0 896.0 Deferred tax asset 260.0 396.0 325.0 325.0 325.0 325.0 325.0
Current assets 4,583.0 4,216.0 6,126.0 6,282.9 6,520.7 6,508.7 6,462.4 Inventory 513.0 472.0 352.0 377.2 415.3 413.4 406.0 Trade debtors 1,762.0 1,947.0 1,843.0 1,974.7 2,174.4 2,164.3 2,125.5 Other current assets 317.0 324.0 290.0 290.0 290.0 290.0 290.0 Fixed assets held for sale 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Cash and cash equivalents* 1,991.0 1,473.0 3,641.0 3,641.0 3,641.0 3,641.0 3,641.0
(PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P EQUITY AND LIABILITIES 18,456.0 18,731.0 21,056.0 21,766.9 22,781.4 23,904.5 25,011.1 Equity 8,770.0 8,777.0 9,409.0 10,208.9 11,037.1 11,842.5 12,510.6 Share capital 4,522.0 4,522.0 4,522.0 4,522.0 4,522.0 4,522.0 4,522.0 Other equity 4,248.0 4,255.0 4,887.0 5,686.9 6,515.1 7,320.5 7,988.6
Minority interests 44.0 40.0 56.0 49.2 50.4 51.6 52.8
Long-term liabilities 7,402.0 7,417.0 8,968.0 8,934.6 9,029.2 9,334.7 9,767.2 Loans 5,591.0 5,725.0 7,240.0 7,206.6 7,301.2 7,606.7 8,039.2 Other 1,811.0 1,692.0 1,728.0 1,728.0 1,728.0 1,728.0 1,728.0
Current liabilities 2,240.0 2,497.0 2,623.0 2,574.2 2,664.8 2,675.7 2,680.6 Loans 279.0 412.0 465.0 359.6 364.3 379.6 401.2 Trade creditors 877.0 811.0 792.0 848.6 934.4 930.1 913.4 Other 1,084.0 1,274.0 1,366.0 1,366.0 1,366.0 1,366.0 1,366.0
Debt 5,870.0 6,137.0 7,705.0 7,566.2 7,665.5 7,986.3 8,440.4 Net debt 3,879.0 4,664.0 4,064.0 3,925.2 4,024.5 4,345.3 4,799.4 (Net debt / Equity) 44.2% 53.1% 43.2% 38.4% 36.5% 36.7% 38.4% (Net debt / EBITDA) 1.8 2.3 1.9 1.7 1.7 1.8 2.1
BVPS 21.2 21.2 22.7 24.7 26.7 28.6 30.2 *the difference between cash as shown on the balance sheet and the cash flow statement is a result of an overdraft facility
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Cash Flow (PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P Cash flow from operating activities 1,604.0 1,782.0 2,182.0 1,950.2 1,983.2 2,150.8 2,096.1 Net income 832.0 151.0 773.0 799.9 828.2 805.5 668.0 D&A 916.0 1,540.0 950.0 1,019.1 1,071.9 1,066.4 1,107.9 Working capital -549.0 -190.0 266.0 -100.3 -152.0 7.7 29.6 Other 405.0 281.0 193.0 231.5 235.1 271.2 290.6
Cash flow from investing activities -1,139.0 -1,689.0 -1,455.0 -1,496.9 -1,761.0 -2,113.9 -2,173.1 CAPEX -1,602.0 -1,580.0 -1,280.0 -1,573.1 -1,848.6 -2,201.5 -2,260.8 Other 463.0 -109.0 -175.0 76.2 87.7 87.7 87.7
Cash flow from financing activities -718.0 -287.0 1,452.0 -453.3 -222.2 -37.0 77.0 Share issue 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Debt 100.0 133.0 1,695.0 -138.8 99.3 320.7 454.1 Dividend (buy-back) -596.0 -203.0 -79.0 0.0 0.0 0.0 0.0 Other -222.0 -217.0 -164.0 -314.5 -321.6 -357.7 -377.1
Change in cash -253.0 -194.0 2,179.0 0.0 0.0 0.0 0.0 Cash at period-end 1,658.0 1,464.0 3,641.0 3,641.0 3,641.0 3,641.0 3,641.0
DPS (PLN) 1.44 0.49 0.19 0.00 0.00 0.00 0.00 FCF -150.0 199.0 933.0 377.1 134.5 -50.7 -164.7 (CAPEX/Sales) 14.8% 15.5% 12.2% 13.9% 14.9% 17.8% 18.6%
Trading Multiples 2015 2016 2017 2018P 2019P 2020P 2021P P/E 4.5 24.7 4.8 4.7 4.5 4.6 5.6 P/CE 2.1 2.2 2.2 2.0 2.0 2.0 2.1 P/BV 0.4 0.4 0.4 0.4 0.3 0.3 0.3 P/S 0.3 0.4 0.4 0.3 0.3 0.3 0.3
FCF/EV -2.0% 2.4% 11.9% 4.9% 1.7% -0.6% -1.9% EV/EBITDA 3.5 4.2 3.6 3.4 3.3 3.4 3.8 EV/EBIT 6.0 17.3 6.5 6.2 6.1 6.3 7.5 EV/S 0.7 0.8 0.7 0.7 0.6 0.7 0.7
DYield 16.0% 5.4% 2.1% 0.0% 0.0% 0.0% 0.0%
Price per share (PLN) 9.0 Shares at year-end (millions) 414.1 414.1 414.1 414.1 414.1 414.1 414.1 MC (PLN m) 3,726.6 3,726.6 3,726.6 3,726.6 3,726.6 3,726.6 3,726.6 Minority interests (PLN m) 44.0 40.0 56.0 49.2 50.4 51.6 52.8 EV (PLN m) 7,649.6 8,430.6 7,846.6 7,701.0 7,801.5 8,123.5 8,578.8
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podwyższona Tuesday, May 29, 2018 | update podtrzymana PGE: buy (reiterated) obniżona PGE PW; PGE.WA | Power Utilities, Poland Free Cash Flow Will Turn Positive From FY2019 Current Price PLN 9.28 Target Price PLN 13.60 Despite a string of positive developments over the last few months Market Cap PLN 17.35bn (including hopes of reduced ownership of the nuclear project, plans for offshore wind farms, a takeover bid on a listed power generator, Free Float PLN 7.39bn a new mechanism for cogeneration capacity payments, and a ADTV (3M) PLN 44.17m rebound in POLPX power prices), PGE stock is close to touching all- time lows even as the Company finalizes a years-long investment Ownership cycle and gives analysts reasons to hike their future EBITDA State Treasury 57.39% expectations. If we add to this the low expectations as to the
benefits of the capacity market, this makes PGE look like an incredible bargain considering its growth potential. Accordingly, we Others 42.61% maintain a buy rating for PGE, with the price target raised to PLN 13.60 per share. Business Profile PGE is Poland's largest energy holding comprising power plants and combined heat and power plants Generation thrives amid improving market fundamentals with combined capacity of 16 GW and annual One of the drivers behind PGE’s recent underperformance is the rapid shift in production of 69 TWh, representing a market share prices of carbon allowances, which would indeed have put a major strain on of ca. 41%. About 60% of the electricity output the profitability of the Company's mostly coal-based generation assets were comes from burning lignite mined at captive mines. it not for the simultaneous rebound in the prices of electricity. The clean- PGE also operates a distribution network (ca. 27% dark spread for lignite-powered installations is holding at the average for the market share) and owns the largest retail sales network in Poland (40.4 TWh). last two years, and the spread for vertically-integrated hard coal installations
has actually widened. New efficient generators coming on line do not have to PGE vs. WIG worry about emission costs. All this, plus the upcoming allocation of 10mmt of free EUAs, and the increasing profitability of renewable energy, makes for 16 a pretty solid 2019 earnings outlook. PLN Diversifying out of coal PGE has announced a number of strategic initiatives in the course of the last 14 few months which suggest a shift in its medium-term business and investment strategy. Among those initiatives are expansion into district heating (represented by last year’s acquisition of EDF heating plants and 12 planned investment in new capacity to capitalize on new support mechanisms), the revival of plans for offshore wind farms, coupled with an acquisition bid on the listed wind farm operator Polenergia, and three gas- 10 fired plants put up for capacity auctions. All these efforts are aimed at PGE increasing the share of earnings from regulated business, as well as reducing PGE’s dependence on coal and sensitivity to shifts in EUA prices. If WIG we add to this the potential benefits of the capacity market mechanism, 8 these changes lay the groundwork for a very interesting investment profile.
Feb-18
Aug-17
Nov-17 May-18 Unparalleled FCF May-17 PGE is nearing the end of a huge investment push (new conventional capacity and upgrades to existing installations), with over PLN 25 billion set to be spent from 2014 to 2019. In the next five years, capital expenditures Target Price Rating are expected to drop to PLN 4 billion on average per year from the Name PLN 7 billion spent in the last four years, with obvious positive effects on new old new old free cash flow. According to our forecasts, PGE’s FCF/EV ratio in 2019-2022 PGE 13.60 12.89 buy buy will average 11%, enough for the Company to resume dividend payments Current Target Upside/ Name given a low current net debt/EBITDA ratio of 1.0x. Price Price Downside PGE 9.28 13.60 +46.6% (PLN m) 2016 2017 2018E 2019E 2020E Forecast revision 2018E 2019E 2020E since last update Revenue 28,092.0 23,100.0 26,025.1 31,767.3 32,647.9 EBITDA +1.3% +9.2% +10.3% EBITDA 7,376.0 7,650.0 7,509.4 7,919.0 7,872.9 EBITDA margin 26.3% 33.1% 28.9% 24.9% 24.1% Net profit +2.6% +21.1% +26.6% EBIT 3,512.0 3,620.0 4,132.1 4,321.9 3,996.0 Power price (EUR/MWh) +1.5% +19.2% +17.4%
Net profit 2,568.0 2,660.0 3,056.2 3,125.7 2,873.8 Coal price (PLN/t) +2.5% +5.9% +4.5%
P/E 6.8 6.5 5.7 5.6 6.0 Carbon price (EUR/t) +40.0% +38.5% +36.9% P/CE 2.7 2.6 2.7 2.6 2.6 P/BV 0.4 0.4 0.4 0.3 0.3 Analyst: EV/EBITDA 3.0 3.4 3.5 3.3 3.2 DPS 0.25 0.00 0.00 0.00 0.42 Kamil Kliszcz +48 22 438 24 02 DYield 2.7% 0.0% 0.0% 0.0% 4.5% [email protected]
Valuation
We calculated our price target for PGE using only DCF (PLN) weight price valuation, as the relative valuation method (provided Relative Valuation 0% 15.40 below for reference only) cannot produce an accurate estimate of the Company's value in our view due to the DCF Analysis 100% 12.74 heightened political risks weighing on Polish utilities, not price 12.74 experienced by comparable foreign companies. The DCF 9M target price 13.60 model yielded a price target of PLN 13.60 per share.
DCF Valuation
Assumptions: . Macroeconomic assumptions and capital investment . Cash flows are discounted to their present value as of plans are as set out in the table below. the end of May 2018. Equity value calculations factor in . We assume that FCF after FY2027 will grow at an minority interests and net debt as of 31 December annual rate of 2%. The risk-free rate is 3.5%, and beta 2017. is 1.1. . The final valuation is adjusted for potential tax on a capital reserve conversion to equity that may be required by the government.
Additional Assumptions: 2017 2018P 2019P 2020P 2021P 2022P 2023P 2024P 2025P 2026P 2027P Price of electricity (EEX, EUR/MWh) 32.4 41.2 42.3 38.6 39.2 39.6 40.1 40.6 41.1 41.6 42.2 Price of electricity (POLPX, PLN/MWh) 159.7 168.5 203.8 194.1 179.0 180.1 181.2 182.4 183.7 185.1 186.5 Price of a carbon allowance (EUR/t) 5.9 14.0 14.6 15.2 15.8 16.4 17.1 17.8 18.5 19.2 20.0 Price of thermal coal (PLN/t) 205.1 230.0 233.9 214.4 214.4 214.4 214.4 214.4 214.4 214.4 214.4 PLN/USD (annual avg.) 3.8 3.5 3.6 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 EUR/PLN (annual avg.) 4.26 4.17 4.15 4.15 4.15 4.15 4.15 4.15 4.15 4.15 4.15 Electricity output (TWh), of which: 56.8 67.0 72.9 82.6 81.7 81.7 81.7 81.7 81.7 81.7 81.7 lignite-fired 39.0 38.0 38.8 42.3 42.3 42.3 42.3 42.3 42.3 42.3 42.3 hard coal-fired power 12.8 23.7 28.8 35.0 34.1 34.1 34.1 34.1 34.1 34.1 34.1 natural gas-fired 2.6 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 hydroelectric power 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 biomass-fired power 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 wind energy 1.3 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2
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DCF Model (PLN m) 2018P 2019P 2020P 2021P 2022P 2023P 2024P 2025P 2026P 2027P 2027+ Revenue 26,025 31,767 32,648 30,596 30,974 31,348 31,744 32,162 32,598 33,056 33,056 change 12.7% 22.1% 2.8% -6.3% 1.2% 1.2% 1.3% 1.3% 1.4% 1.4% 0.0% EBITDA 7,509.4 7,919.0 7,872.9 7,980.4 7,882.1 7,737.1 7,588.0 7,443.6 7,371.9 7,304.6 7,304.6 EBITDA margin 28.9% 24.9% 24.1% 26.1% 25.4% 24.7% 23.9% 23.1% 22.6% 22.1% 22.1% D&A 3,377.3 3,597.1 3,876.9 3,909.1 3,948.8 4,035.3 4,148.8 4,285.7 4,444.1 4,420.2 4,180.2 EBIT 4,132.1 4,321.9 3,996.0 4,071.3 3,933.3 3,701.8 3,439.2 3,157.9 2,927.8 2,884.4 3,124.4 EBIT margin 15.9% 13.6% 12.2% 13.3% 12.7% 11.8% 10.8% 9.8% 9.0% 8.7% 9.5% Tax on EBIT 785.1 821.2 759.2 773.6 747.3 703.3 653.4 600.0 556.3 548.0 593.6 NOPLAT 3,347.0 3,500.7 3,236.7 3,297.8 3,186.0 2,998.4 2,785.7 2,557.9 2,371.5 2,336.4 2,530.8
CAPEX -7,446 -5,844 -4,251 -4,091 -4,038 -3,941 -3,997 -4,056 -4,117 -4,180 -4,180 Working capital 363.8 -667.3 -102.3 238.4 -43.9 -43.5 -46.0 -48.6 -50.6 -53.2 -53.2 Equity investment 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
FCF -358.2 587.0 2,760.7 3,354.3 3,052.9 3,049.3 2,891.0 2,738.9 2,647.8 2,523.2 2,477.6 WACC 8.1% 8.2% 8.4% 8.6% 8.5% 8.5% 8.5% 8.5% 8.5% 8.5% 7.9% Discount factor 95.6% 88.3% 81.5% 75.0% 69.2% 63.8% 58.8% 54.2% 50.0% 46.1% 46.1% PV FCF -342.3 518.5 2,249.8 2,516.3 2,111.5 1,944.4 1,699.6 1,484.5 1,323.1 1,162.5
WACC 8.1% 8.2% 8.4% 8.6% 8.5% 8.5% 8.5% 8.5% 8.5% 8.5% 7.9% Cost of debt 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% Risk-free rate 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% Risk premium 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% Effective tax rate 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% Net debt / EV 16.8% 15.2% 11.5% 6.8% 10.0% 10.0% 10.0% 10.0% 10.0% 10.0% 20.0%
Cost of equity 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% Risk premium 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% Beta 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1
FCF growth after the forecast period 2.0% Sensitivity Analysis
Terminal value 41,787 FCF growth in perpetuity
Present value of terminal value 19,252 0.0% 1.0% 2.0% 3.0% 4.0%
Present value of FCF in the forecast period 14,668 WACC +1.0 p.p. 9.9 10.8 12.0 13.6 15.8
Enterprise value 33,920 WACC +0.5 p.p. 10.3 11.4 12.7 14.6 17.3
Net debt (eoy 2017) 7,487 WACC 10.8 12.0 13.6 15.8 19.2
Minority interests 1,165 WACC -0.5 p.p. 11.4 12.7 14.6 17.3 21.6
Potential capital conversion tax -1,439 WACC -1.0 p.p. 12.0 13.6 15.8 19.2 24.8
PPA compensation refund 0
Equity value 23,829
Number of shares (millions) 1,870
Equity value per share (PLN) 12.7
9M cost of equity 6.7%
Target price (PLN) 13.6
EV/EBITDA ('18) at target price 8.3
P/E ('18) at target price 57%
TV / EV 2.0%
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Relative Valuation
We compared PGE's forward P/E and EV/EBITDA multiples used (fuels, emissions, age of installed capacity), and the and projected dividend yields with the multiples and yields shares of different operating segments in total earnings. of the Company's peers as projected for fiscal 2018 We assigned equal weights to each multiple and forecast through 2020. The peer group comprises vertically- year. The calculations pertaining to PGE and Enea are integrated power producers as well as utilities focusing adjusted for compensation received under long-term power mainly on regulated distribution of electricity and purchase agreements. renewable energy. It is diversified in terms of technology
Multiples Comparison P/E EV/EBITDA 2018- 2020e Price 2017 2018E 2019E 2020E 2017 2018E 2019E 2020E DYield EDF 11.47 21.8 19.0 16.0 13.6 5.9 6.1 5.7 5.6 3.0% EDP 3.38 15.1 15.9 14.4 14.0 8.8 9.1 8.5 8.2 5.6% ENDESA 19.19 14.5 14.3 13.9 13.8 7.4 7.5 7.4 7.3 7.2% ENEL 4.71 13.2 11.6 10.4 9.8 6.6 6.5 6.3 6.1 6.6% EON 9.17 14.4 13.9 13.0 12.2 8.9 7.4 7.2 6.6 5.2% INNOGY 35.85 16.2 17.6 16.9 16.3 8.6 8.9 9.1 9.0 4.6% RWE 19.75 10.0 13.4 11.8 9.7 6.9 7.2 7.2 7.5 4.2% CEZ 551.00 20.3 20.8 19.3 17.2 8.1 8.5 8.1 7.7 5.3% ENEA 9.57 3.9 4.6 3.5 4.5 4.0 4.0 3.5 3.9 0.0% ENERGA 9.00 4.8 4.7 4.5 4.6 3.6 3.4 3.3 3.4 0.0% TAURON 2.01 2.9 2.7 3.3 3.1 3.7 3.8 4.3 3.8 0.0%
Maximum 21.8 20.8 19.3 17.2 8.9 9.1 9.1 9.0 7.2% Minimum 2.9 2.7 3.3 3.1 3.6 3.4 3.3 3.4 0.0% Median 14.4 13.9 13.0 12.2 6.9 7.2 7.2 6.6 4.6%
PGE 9.28 10.4 5.7 5.6 6.0 4.0 3.5 3.3 3.1 1.5% (premium / discount) to the median -28.3% -59.3% -57.3% -50.5% -41.7% -50.9% -53.5% -52.2% -67.2%
Implied valuation Median 14.4 13.9 13.0 12.2 6.9 7.2 7.2 6.6 4.6% Multiple weight 33.3% 33.3% 33.3% Year weight 0.0% 33.3% 33.3% 33.3% 0.0% 33.3% 33.3% 33.3% Implied value per share (PLN) 16.2 Potential capital conversion tax -0.8
Equity value per share (PLN) 15.4
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Income Statement (PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P Revenue 28,542.0 28,092.0 23,100.0 26,025.1 31,767.3 32,647.9 30,596.3 change 1.4% -1.6% -17.8% 12.7% 22.1% 2.8% -6.3% of which PPA compensation 546.0 520.0 1,215.0 0.0 0.0 0.0 0.0
EBITDA, of which 8,228.0 7,376.0 7,650.0 7,509.4 7,919.0 7,872.9 7,980.4 Mining and Generation 4,698.0 4,182.0 4,099.0 3,909.0 4,311.5 4,158.4 4,182.4 Renewables 391.0 365.0 364.0 406.6 496.6 495.0 486.2 Power Distribution 2,461.0 2,230.0 2,333.0 2,423.6 2,420.2 2,484.0 2,530.4 Sales 610.0 500.0 811.0 727.2 647.6 692.4 738.5 Other, intercompany eliminations 68.0 99.0 43.0 43.0 43.0 43.0 43.0
EBIT -3,589.0 3,512.0 3,620.0 4,132.1 4,321.9 3,996.0 4,071.3 change - - 3.1% 14.1% 4.6% -7.5% 1.9% EBIT margin -12.6% 12.5% 15.7% 15.9% 13.6% 12.2% 13.3%
Financing gains / losses -167.0 -193.0 -370.0 -297.5 -401.1 -387.6 -327.0 Extraordinary gains/losses 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Other 0.0 -45.0 40.0 0.0 0.0 0.0 0.0
Pre-tax income -3,756.0 3,274.0 3,290.0 3,834.6 3,920.8 3,608.4 3,744.4 Tax -719.0 708.0 623.0 728.6 744.9 685.6 711.4 Minority interests -5.0 -2.0 7.0 49.8 50.2 49.0 49.0 Net profit from discontinued operations 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Net income -3,032.0 2,568.0 2,660.0 3,056.2 3,125.7 2,873.8 2,983.9 change - - 3.6% 14.9% 2.3% -8.1% 3.8% margin -10.6% 9.1% 11.5% 11.7% 9.8% 8.8% 9.8%
D&A 11,817.0 3,864.0 4,030.0 3,377.3 3,597.1 3,876.9 3,909.1 EBITDA 8,228.0 7,376.0 7,650.0 7,509.4 7,919.0 7,872.9 7,980.4 change -0.8% -10.4% 3.7% -1.8% 5.5% -0.6% 1.4% EBITDA margin 28.8% 26.3% 33.1% 28.9% 24.9% 24.1% 26.1%
Shares at year-end (millions) 1,869.8 1,869.8 1,869.8 1,869.8 1,869.8 1,869.8 1,869.8 EPS -1.6 1.4 1.4 1.6 1.7 1.5 1.6 CEPS 4.7 3.4 3.6 3.4 3.6 3.6 3.7
ROAE -7.1% 6.2% 6.1% 6.5% 6.3% 5.5% 5.5% ROAA -4.8% 4.0% 3.8% 4.1% 4.0% 3.6% 3.8%
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Balance Sheet (PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P ASSETS 61,296.0 67,474.0 72,106.0 75,634.1 78,872.8 79,398.7 79,226.1 Fixed assets 49,586.0 55,232.0 62,586.0 66,655.1 68,901.6 69,275.3 69,457.2 Property, plant and equipment 47,068.0 51,365.0 58,620.0 62,691.3 64,956.1 65,331.4 65,515.3 Intangible assets 904.0 653.0 1,281.0 1,278.7 1,260.4 1,258.9 1,256.9 Equity investment 8.0 402.0 634.0 634.0 634.0 634.0 634.0 Other fixed assets 1,606.0 2,812.0 2,051.0 2,051.0 2,051.0 2,051.0 2,051.0
Current assets 11,710.0 12,242.0 9,520.0 8,979.0 9,971.2 10,123.4 9,768.9 Inventory 1,959.0 1,596.0 1,879.0 1,677.2 2,047.3 2,104.0 1,971.8 Current receivables 2,548.0 2,705.0 3,159.0 2,819.8 3,441.9 3,537.3 3,315.1 Other current assets 4,099.0 5,272.0 1,930.0 1,930.0 1,930.0 1,930.0 1,930.0 Cash and cash equivalents 3,104.0 2,669.0 2,552.0 2,552.0 2,552.0 2,552.0 2,552.0
(PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P EQUITY AND LIABILITIES 61,296.0 67,474.0 72,106.0 75,634.1 78,872.8 79,398.7 79,226.1 Equity 40,321.0 42,679.0 45,188.0 48,244.2 51,369.9 53,462.3 55,727.7 Share capital 18,698.0 19,165.0 19,165.0 19,165.0 19,165.0 19,165.0 19,165.0 Other equity 21,623.0 23,514.0 26,023.0 29,079.2 32,204.9 34,297.3 36,562.7
Minority interests 96.0 96.0 1,165.0 1,214.8 1,265.0 1,314.0 1,363.0
Long-term liabilities 13,295.0 17,002.0 16,773.0 17,275.4 17,055.7 15,659.4 13,671.5 Loans 5,118.0 9,603.0 8,422.0 8,924.4 8,704.7 7,308.4 5,320.5 Other 8,177.0 7,399.0 8,351.0 8,351.0 8,351.0 8,351.0 8,351.0
Current liabilities 7,584.0 7,697.0 8,980.0 8,899.6 9,182.3 8,963.0 8,463.8 Loans 291.0 411.0 1,623.0 1,719.8 1,677.5 1,408.4 1,025.3 Trade creditors 1,119.0 976.0 1,650.0 1,472.8 1,797.8 1,847.6 1,731.5 Other 6,174.0 6,310.0 5,707.0 5,707.0 5,707.0 5,707.0 5,707.0
Debt 5,409.0 10,014.0 10,045.0 10,644.2 10,382.1 8,716.8 6,345.8 Net debt 2,304.0 5,045.0 7,487.0 8,086.2 7,824.1 6,158.8 3,787.8 (Net debt / Equity) 5.7% 11.8% 16.6% 16.8% 15.2% 11.5% 6.8% (Net debt / EBITDA) 0.3 0.7 1.0 1.1 1.0 0.8 0.5
BVPS 21.6 22.8 24.2 25.8 27.5 28.6 29.8
55
Cash Flow (PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P Cash flow from operating activities 6,777.0 6,391.0 7,934.0 7,144.6 6,506.8 7,084.9 7,507.4 Net income -3,032.0 2,568.0 2,660.0 3,056.2 3,125.7 2,873.8 2,983.9 D&A 11,817.0 3,864.0 4,030.0 3,377.3 3,597.1 3,876.9 3,909.1 Working capital 306.0 -102.0 24.0 363.8 -667.3 -102.3 238.4 Other -2,314.0 61.0 1,220.0 347.3 451.3 436.6 376.0
Cash flow from investing activities -8,594.0 -10,656.0 -7,775.0 -7,371.9 -5,769.2 -4,176.2 -4,016.6 CAPEX -8,606.0 -7,935.0 -6,071.0 -7,446.3 -5,843.6 -4,250.6 -4,091.0 Other 12.0 -2,721.0 -1,704.0 74.4 74.4 74.4 74.4
Cash flow from financing activities -1,265.0 3,830.0 -274.0 227.3 -737.6 -2,908.7 -3,490.8 Share issue 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Debt 337.0 4,449.0 -1.0 599.2 -262.1 -1,665.3 -2,371.0 Dividend (buy-back) -1,462.0 -471.0 -1.0 0.0 0.0 -781.4 -718.4 Other -140.0 -148.0 -272.0 -371.9 -475.5 -462.0 -401.4
Change in cash -3,082.0 -435.0 -115.0 0.0 0.0 0.0 0.0 Cash at period-end 3,101.0 2,666.0 2,551.0 2,551.0 2,551.0 2,551.0 2,551.0
DPS (PLN) 0.78 0.25 0.00 0.00 0.00 0.42 0.38 FCF 647.0 -1,369.0 980.0 -301.7 663.2 2,834.3 3,416.4 (CAPEX/Sales) 30.2% 28.2% 26.3% 28.6% 18.4% 13.0% 13.4%
Trading Multiples 2015 2016 2017 2018P 2019P 2020P 2021P P/E -5.7 6.8 6.5 5.7 5.6 6.0 5.8 P/CE 2.0 2.7 2.6 2.7 2.6 2.6 2.5 P/BV 0.4 0.4 0.4 0.4 0.3 0.3 0.3 P/S 0.6 0.6 0.8 0.7 0.5 0.5 0.6
FCF/EV 3.3% -6.1% 3.8% -1.1% 2.5% 11.4% 15.2% EV/EBITDA 2.4 3.0 3.4 3.5 3.3 3.2 2.8 EV/EBIT -5.5 6.4 7.2 6.5 6.1 6.2 5.5 EV/S 0.7 0.8 1.1 1.0 0.8 0.8 0.7
DYield 8.4% 2.7% 0.0% 0.0% 0.0% 4.5% 4.1%
Price (PLN) 9.28 Shares at year-end (millions) 1869.8 1869.8 1869.8 1869.8 1869.8 1869.8 1869.8 MC (PLN m) 17,351.6 17,351.6 17,351.6 17,351.6 17,351.6 17,351.6 17,351.6 Minority interests (PLN m) 96.0 96.0 1165.0 1214.8 1265.0 1314.0 1363.0 EV (PLN m) 19,751.6 22,492.6 26,003.6 26,652.6 26,440.7 24,824.4 22,502.4
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podwyższona Tuesday, May 29, 2018 | update podtrzymana Tauron: buy (upgraded) obniżona TPE PW; TPE.WA | Power Utilities, Poland New Capacity Mechanisms Boost Investment Profile Current Price PLN 2.01 Target Price PLN 2.76 Tauron stock has not been able to shake off the downward trend Market Cap PLN 3.52bn started a few months ago despite delivering better-than-expected 2018 first-quarter earnings, and even after the Energy Minister Free Float PLN 2.10bn announced the Company would probably not have to participate in ADTV (3M) PLN 26.27m the nuclear project. The underperformance is consistent with the pullback on the whole Polish energy sector, and when it comes to Ownership factors specific to Tauron, it is ironic that, just as its value reaches State Treasury 30.06% all-time lows, the risk of covenant breach has decreased (in line with KGHM 10.39% an upcoming reduction in capital expenditures and as cash flow is poised to turn positive), and the prospect of the Company regaining NN OFE 5.60% the capacity to make regular dividend payments becomes more and more real. Tauron, which generates 90% of annual EBITDA from Others 53.95% distribution, heat, renewables, and trade, can restore its attractive investment profile provided it can leverage this year’s capacity Business Profile auctions to overhaul generation assets. We upgrade TPE to buy, Tauron is the second-largest vertically-integrated with the price target raised slightly to PLN 2.76 per share. power producer in Poland with annual power- generation capacity of 5.0 GW and coal production Solid FCF from 2020 capacity of 6-7mmt. Moreover, the Company is the largest local retailer, delivering close to 35 TWh of Tauron has steadily built up debt for the last eight years, and after more electrical power to end users each year. Finally, borrowing expected in 2019 its net debt/EBITDA ratio at the end of next Tauron's distribution network transmitted nearly 51 year is set to reach 3.3x. After the launch of the new 910 MW generator in TWh of power in 2017. Q4 2019, however, we believe the Company will be able to reduce leverage and start generating positive net ash flow to the tune of PLN 1 billion a year. TPE vs. WIG These prospects should turn sentiment for Tauron around in our view given that with the new capacity the Generator will derive over 90% of annual 4.50 earnings from regulated activities (distribution, heat) and the low-risk PLN trading business. 4.00
Capacity market an opportunity to overhaul energy mix Tauron owns relatively large generation capacity (5 GW), but its energy mix 3.50 returns very low profits, with the compound margin at PLN 21/MWh compared to a sector average of PLN 60/MWh. To date, any plans to revamp 3.00 the inefficient capacity have been hindered by the expectations of the TSO, and by political interests. However, with the introduction of the capacity market, we believe Tauron will be able to push through the decommissioning 2.50 TPE of some of its worst-performing installations which cannot be upgraded to WIG meet today’s emission norms at a reasonable cost. The elimination of loss- 2.00 making plants would boost profits as well as helping to avoid costly
upgrades.
Feb-18
Aug-17
Nov-17 May-18 May-17 Trading profits under pressure in a changing market Electricity trading accounts for about 17% of Tauron’s EBITDA. In the last Target Price Rating few years, the Company enjoyed strong trading profits thanks to lower Name prices of electricity and green certificates. With both trends reversed this new old new old year, the trading segment faces a squeeze in 2019, especially if the Tauron 2.76 2.73 buy hold regulator implements measures to mitigate the impact of the higher power Current Target Upside/ Name prices on household energy bills. For any PLN 10/MWh hike in price not Price Price Downside passed through the household tariff, Tauron may be facing a drop in EBITDA Tauron 2.01 2.76 +37.5% as high as PLN 100m. Forecast revision 2018E 2019E 2020E (PLN m) 2016 2017 2018E 2019E 2020E since last update Revenue 17,646.5 17,416.0 18,028.9 19,771.1 19,861.9 EBITDA +8.3% +2.7% +6.7% EBITDA 3,336.8 3,545.3 3,665.4 3,514.6 3,811.2 Net profit +14.6% +2.7% +14.9%
EBITDA margin 18.9% 20.4% 20.3% 17.8% 19.2% Power price (EUR/MWh) +1.5% +19.2% +17.4% EBIT 801.5 1,806.3 1,938.0 1,681.3 1,811.8 Coal price (PLN/t) +2.5% +5.9% +4.5% Net profit 367.5 1,380.7 1,325.2 1,059.7 1,135.0 Carbon price (EUR/t) +40.0% +38.5% +36.9% P/E 9.6 2.6 2.7 3.3 3.1 P/CE 1.2 1.1 1.2 1.2 1.1 P/BV 0.2 0.2 0.2 0.2 0.2 Analyst: EV/EBITDA 3.6 3.5 3.8 4.3 3.8 DPS 0.00 0.00 0.00 0.00 0.00 Kamil Kliszcz +48 22 438 24 02 DYield 0.0% 0.0% 0.0% 0.0% 0.0% [email protected]
Valuation
We calculated our price target for Tauron using only DCF (PLN) weight price valuation, as the relative valuation method (provided Relative Valuation 0% 5.32 below for reference only) cannot produce an accurate estimate of the Company's value in our view due to the DCF Analysis 100% 2.59 heightened political risks weighing on Polish utilities, not price 2.59 experienced by comparable foreign companies. The DCF 9M target price 2.76 model yielded a price target of PLN 2.76 per share.
DCF Valuation
Assumptions: . Macroeconomic assumptions and capital investment . Cash flows are discounted to their present value as of plans are as set out in the table below. the end of May 2018. Equity value calculations factor in . We assume that FCF after FY2027 will grow at an minority interests and net debt as of 31 December annual rate of 2%. The risk-free rate is 3.5%, and beta 2017. is 1.1. . The final valuation is adjusted for potential tax on a capital reserve conversion to equity that may be required by the government.
Additional Assumptions: 2017 2018P 2019P 2020P 2021P 2022P 2023P 2024P 2025P 2026P 2026P Price of electricity (EEX, EUR/MWh) 32.4 41.2 42.3 38.6 39.2 39.6 40.1 40.6 41.1 41.6 42.2 Price of electricity (POLPX, PLN/MWh) 159.7 168.5 203.8 194.1 179.0 180.1 181.2 182.4 183.7 185.1 186.5 Price of a carbon allowance (EUR/t) 5.9 14.0 14.6 15.2 15.8 16.4 17.1 17.8 18.5 19.2 20.0 Price of a green certificate (PLN/MWh) 36.5 75.0 89.2 106.1 126.1 150.0 150.0 150.0 150.0 150.0 150.0 Price of coal in Poland (PLN/t) 227.7 256.2 254.0 225.8 225.8 225.8 225.8 225.8 225.8 225.8 225.8 PLN/USD (annual avg.) 3.77 3.54 3.60 3.70 3.70 3.70 3.70 3.70 3.70 3.70 3.70 EUR/PLN (annual avg.) 4.26 4.17 4.15 4.15 4.15 4.15 4.15 4.15 4.15 4.15 4.15 Net electricity output (TWh), of which: 18.4 16.0 16.2 19.2 19.2 19.2 19.2 19.2 19.2 19.2 19.2 hard coal-fired power 17.1 14.7 13.2 16.2 16.7 16.7 16.7 16.7 16.7 16.7 16.7 biomass-fired power 0.4 0.4 0.4 0.4 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2 natural gas-fired 0.0 0.0 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 wind energy 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 hydroelectric power 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 Sales volume (TWh) 34.9 35.5 36.0 36.5 37.1 37.6 38.2 38.8 39.4 40.0 40.5 Value of Distribution Assets (PLN bn) 16.3 17.2 17.5 17.8 18.1 18.4 18.7 18.9 19.2 19.4 19.5
58
DCF Model (PLN m) 2018P 2019P 2020P 2021P 2022P 2023P 2024P 2025P 2026P 2027P 2027+ Revenue 18,029 19,771 19,862 19,477 19,755 20,061 20,378 20,715 21,031 21,360 21,360 change 3.5% 9.7% 0.5% -1.9% 1.4% 1.6% 1.6% 1.7% 1.5% 1.6% 0.0% EBITDA 3,435.4 3,514.6 3,811.2 3,991.2 3,982.1 4,017.3 4,054.9 4,116.3 4,178.4 4,236.3 4,236.3 EBITDA margin 19.1% 17.8% 19.2% 20.5% 20.2% 20.0% 19.9% 19.9% 19.9% 19.8% 19.8% D&A 1,727.4 1,833.3 1,999.4 2,067.8 2,061.4 2,107.7 2,158.2 2,216.2 2,279.2 2,350.8 2,767.8 EBIT 1,708.0 1,681.3 1,811.8 1,923.4 1,920.7 1,909.6 1,896.7 1,900.0 1,899.2 1,885.5 1,468.5 EBIT margin 9.5% 8.5% 9.1% 9.9% 9.7% 9.5% 9.3% 9.2% 9.0% 8.8% 6.9% Tax on EBIT 324.5 319.5 344.2 365.4 364.9 362.8 360.4 361.0 360.8 358.2 279.0 NOPLAT 1,383.5 1,361.9 1,467.6 1,558.0 1,555.8 1,546.8 1,536.4 1,539.0 1,538.3 1,527.3 1,189.4
CAPEX -4,377.3 -3,988.0 -2,643.6 -2,701.1 -2,670.3 -2,692.9 -2,702.0 -2,727.6 -2,728.3 -2,767.8 -2,767.8 Working capital -17.1 -48.5 -2.5 10.7 -7.7 -8.5 -8.8 -9.4 -8.8 -9.1 -9.1 Equity investment 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.0 2.0
FCF -1,283.5 -841.3 820.8 935.4 939.1 953.1 983.8 1,018.3 1,080.4 1,101.1 1,180.3 WACC 6.2% 6.0% 6.3% 6.6% 6.8% 7.1% 7.3% 7.5% 7.4% 7.4% 7.4% Discount factor 96.6% 91.1% 85.7% 80.4% 75.3% 70.3% 65.5% 60.9% 56.8% 52.8% 52.8% PV FCF -1,239.6 -766.5 703.6 752.4 707.1 670.2 644.7 620.6 613.1 581.8
WACC 6.2% 6.0% 6.3% 6.6% 6.8% 7.1% 7.3% 7.5% 7.4% 7.4% 7.4% Cost of debt 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% 4.5% Risk-free rate 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% 3.50% Risk premium 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% Effective tax rate 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% 19.0% Net debt / EV 53.1% 56.0% 50.8% 45.4% 40.5% 36.0% 31.6% 27.5% 30.0% 30.0% 30.0%
Cost of equity 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% 9.0% Risk premium 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% 5.0% Beta 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1
FCF growth after the forecast period 2.0% Sensitivity Analysis
Terminal value 21,884 FCF growth in perpetuity
Present value of terminal value 11,564 0.0% 1.0% 2.0% 3.0% 4.0%
Present value of FCF in the forecast period 3,288 WACC +1.0 p.p. 0.25 0.86 1.66 2.76 4.37
Enterprise value 14,852 WACC +0.5 p.p. 0.53 1.23 2.17 3.48 5.48
Net debt (eoy 2017) 8,944 WACC 0.86 1.66 2.76 4.37 6.91
Minority interests 31 WACC -0.5 p.p. 1.23 2.17 3.48 5.48 8.85
Present value of potential capital conversion tax -777 WACC -1.0 p.p. 1.66 2.76 4.37 6.91 11.59
Equity value 4,540
Number of shares (millions) 1,752.5
Equity value per share (PLN) 2.59
9M cost of equity 6.7%
Target price (PLN) 2.76
EV/EBITDA('18) at DCF valuation 4.0
P/E('18) at DCF valuation 3.7
TV / EV 78%
59
Relative Valuation
We compared Tauron's forward P/E and EV/EBITDA used (fuels, emissions, age of installed capacity), and the multiples and projected dividend yields with the multiples shares of different operating segments in total earnings. and yields of the Company's peers as projected for fiscal We assigned equal weights to each multiple and forecast 2018 through 2020. The peer group comprises vertically- year. The calculations pertaining to PGE and Enea are integrated power producers as well as utilities focusing adjusted for compensation received under long-term power mainly on regulated distribution of electricity and purchase agreements. renewable energy. It is diversified in terms of technology
Multiples Comparison P/E EV/EBITDA 2018- 2020E Price 2017 2018E 2019E 2020E 2017 2018E 2019E 2020E DYield EDF 12.34 23.4 20.5 17.3 14.6 6.1 6.2 5.9 5.7 2.8% EDP 3.45 15.4 16.3 14.7 14.2 8.9 9.1 8.6 8.3 5.5% ENDESA 20.00 15.1 14.9 14.5 14.4 7.7 7.7 7.6 7.6 6.9% ENEL 4.87 13.6 12.0 10.7 10.1 6.7 6.6 6.4 6.1 6.4% EON 9.29 14.6 14.1 13.2 12.4 9.0 7.4 7.2 6.6 5.2% INNOGY 36.01 16.3 17.6 16.9 16.4 8.7 8.9 9.1 9.1 4.6% RWE 19.82 10.1 13.5 11.9 9.7 6.9 7.2 7.2 7.5 4.1% CEZ 568.50 20.9 21.5 20.0 17.8 8.3 8.7 8.3 7.9 4.6% ENEA 9.66 4.0 4.6 3.6 4.5 4.0 4.1 3.5 3.9 0.0% ENERGA 8.88 4.8 4.6 4.4 4.6 3.6 3.4 3.3 3.4 2.5% PGE 9.24 10.3 5.7 5.5 6.0 4.0 3.5 3.3 3.1 2.2%
Maximum 23.4 21.5 20.0 17.8 9.0 9.1 9.1 9.1 6.9% Minimum 4.0 4.6 3.6 4.5 3.6 3.4 3.3 3.1 0.0% Median 14.6 14.1 13.2 12.4 6.9 7.2 7.2 6.6 4.6%
TAURON 2.00 2.9 2.6 3.3 3.1 3.7 3.8 4.3 3.8 0.0% (premium / discount) to the median -80.5% -81.3% -74.9% -75.0% -46.4% -47.8% -40.9% -42.5% -
Implied valuation Median 14.6 14.1 13.2 12.4 6.9 7.2 7.2 6.6 4.6% Multiple weight 33.3% 33.3% 33.3% Year weight 0.0% 33.3% 33.3% 33.3% 0.0% 33.3% 33.3% 33.3% Implied value per share (PLN) 5.76 Potential capital conversion tax -0.44 Equity value per share (PLN) 5.32
60
Income Statement (PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P Revenue 18,264.4 17,646.5 17,416.0 18,028.9 19,771.1 19,861.9 19,477.0 change -1.7% -3.4% -1.3% 3.5% 9.7% 0.5% -1.9% of which PPA compensation 0.0 0.0 0.0 0.0 0.0 0.0 0.0
EBITDA, of which 3,523.2 3,336.8 3,545.3 3,665.4 3,514.6 3,811.2 3,991.2 Mining 9.1 -82.1 -83.0 27.6 43.9 47.4 47.4 Generation 754.8 545.3 464.0 598.1 443.1 633.3 743.4 Power Distribution 2,372.1 2,394.8 2,282.7 2,442.5 2,518.6 2,594.0 2,651.7 Trade 380.4 490.0 841.2 567.4 485.9 511.5 519.2 Other 100.2 114.6 118.0 120.4 122.8 125.3 127.8 Unattributed -93.5 -123.8 -78.3 -90.7 -99.8 -100.3 -98.3
EBIT -1,901.2 801.5 1,806.3 1,938.0 1,681.3 1,811.8 1,923.4 change -203.9% -142.2% 125.4% 7.3% -13.2% 7.8% 6.2% EBIT margin -10.4% 4.5% 10.4% 10.7% 8.5% 9.1% 9.9%
Financing gains / losses -294.6 -352.7 -121.7 -253.8 -334.5 -369.3 -375.2 Extraordinary gains/losses 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Other 7.9 60.0 73.1 0.0 0.0 0.0 0.0
Pre-tax income -2,187.8 508.9 1,757.7 1,684.2 1,346.8 1,442.5 1,548.2 Tax -383.6 138.7 374.7 359.1 287.1 307.5 330.1 Minority interests 3.1 2.7 2.3 0.0 0.0 0.0 0.0 Net profit from discontinued operations 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Net income -1,807.4 367.5 1,380.7 1,325.2 1,059.7 1,135.0 1,218.2 change -253.1% -120.3% 275.7% -4.0% -20.0% 7.1% 7.3% margin -9.9% 2.1% 7.9% 7.4% 5.4% 5.7% 6.3%
D&A 5,424.4 2,535.3 1,739.1 1,727.4 1,833.3 1,999.4 2,067.8 EBITDA 3,523.2 3,336.8 3,545.3 3,665.4 3,514.6 3,811.2 3,991.2 change -4.6% -5.3% 6.2% 3.4% -4.1% 8.4% 4.7% EBITDA margin 19.3% 18.9% 20.4% 20.3% 17.8% 19.2% 20.5%
Shares at year-end (millions) 1,752.5 1,752.5 1,752.5 1,752.5 1,752.5 1,753.5 1,754.5 EPS -1.0 0.2 0.8 0.8 0.6 0.6 0.7 CEPS 2.1 1.7 1.8 1.7 1.7 1.8 1.9
ROAE -10.6% 2.2% 8.0% 7.1% 5.3% 5.4% 5.5% ROAA -5.4% 1.1% 4.0% 3.6% 2.7% 2.8% 2.9%
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Balance Sheet (PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P ASSETS 32,071.4 33,456.9 35,792.0 38,523.8 40,911.0 41,567.4 42,149.3 Fixed assets 28,124.2 29,148.3 31,049.1 33,699.1 35,853.8 36,498.1 37,131.3 Property, plant and equipment 24,882.8 26,355.2 28,079.9 30,800.7 33,068.7 33,797.4 34,518.4 Intangible assets 1,785.7 1,390.8 1,597.4 1,526.5 1,413.3 1,328.8 1,241.0 Other financial assets 433.0 468.1 478.9 478.9 478.9 478.9 478.9 Other non-financial assets 550.4 422.4 346.8 346.8 346.8 346.8 346.8 Deferred tax asset 54.2 50.4 47.0 47.0 47.0 47.0 47.0
Current assets 3,947.2 4,308.6 4,742.9 4,824.7 5,057.2 5,069.3 5,017.9 Inventory 433.3 486.1 295.5 305.9 335.4 337.0 330.4 Trade debtors 1,830.0 1,894.1 2,032.8 2,104.2 2,307.2 2,317.7 2,272.9 Other current assets 1,301.1 1,524.0 1,489.5 1,489.5 1,489.5 1,489.5 1,489.5 Fixed assets held for sale 17.9 19.6 15.9 15.9 15.9 15.9 15.9 Cash and cash equivalents* 364.9 384.9 909.2 909.2 909.2 909.2 909.2
(PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P EQUITY AND LIABILITIES 32,071.4 33,456.9 35,792.0 38,523.8 40,911.0 41,567.4 42,149.3 Equity 16,018.3 16,649.3 18,036.4 19,361.6 20,421.3 21,556.3 22,774.5 Share capital 8,762.7 8,762.7 8,762.7 8,762.7 8,762.7 8,762.7 8,762.7 Other equity 7,255.6 7,886.5 9,273.7 10,598.9 11,658.6 12,793.5 14,011.7
Minority interests 29.8 30.1 31.4 29.5 29.5 29.5 29.5
Long-term liabilities 8,584.0 11,968.7 12,738.0 14,033.8 15,136.5 14,665.7 14,091.3 Loans 4,924.1 8,759.8 9,501.4 10,797.2 11,899.9 11,429.1 10,854.7 Other 3,659.8 3,208.9 3,236.6 3,236.6 3,236.6 3,236.6 3,236.6
Current liabilities 7,439.3 4,808.9 4,986.2 5,098.9 5,323.7 5,315.9 5,254.0 Loans 3,214.5 219.7 351.4 399.3 440.1 422.7 401.4 Trade creditors 1,557.5 1,863.5 1,839.7 1,904.5 2,088.5 2,098.1 2,057.4 Other 2,667.3 2,725.6 2,795.1 2,795.1 2,795.1 2,795.1 2,795.1
Debt 8,138.6 8,979.5 9,852.8 11,196.5 12,340.0 11,851.8 11,256.1 Net debt 7,773.7 8,594.6 8,943.5 10,287.2 11,430.8 10,942.5 10,346.9 (Net debt / Equity) 48.5% 51.6% 49.6% 53.1% 56.0% 50.8% 45.4% (Net debt / EBITDA) 2.21 2.58 2.52 2.81 3.25 2.87 2.59
BVPS 9.1 9.5 10.3 11.0 11.7 12.3 13.0 *the difference between cash as shown on the balance sheet and the cash flow statement is a result of an overdraft facility
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Cash Flow (PLN m) 2015 2016 2017 2018P 2019P 2020P 2021P Cash flow from operating activities 3,387.5 3,064.2 3,558.7 3,289.3 3,179.0 3,501.1 3,671.9 Net income -1,807.4 367.5 1,380.7 1,325.2 1,059.7 1,135.0 1,218.2 D&A 5,428.7 2,535.8 1,739.1 1,727.4 1,833.3 1,999.4 2,067.8 Working capital 28.7 54.2 249.5 -17.1 -48.5 -2.5 10.7 Other -262.5 106.7 189.5 253.8 334.5 369.3 375.2
Cash flow from investing activities -3,942.1 -3,627.5 -3,871.7 -4,312.4 -3,899.1 -2,554.7 -2,612.1 CAPEX -3,973.5 -3,647.4 -3,561.8 -4,377.3 -3,988.0 -2,643.6 -2,701.1 Other 31.4 19.9 -309.9 65.0 88.9 88.9 88.9
Cash flow from financing activities -525.7 590.3 759.6 1,023.1 720.1 -946.5 -1,059.7 Share issue 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Debt 14.4 845.2 902.5 1,343.7 1,143.5 -488.2 -595.6 Dividend (buy-back) -262.9 0.0 0.0 0.0 0.0 0.0 0.0 Other -277.2 -254.9 -142.9 -320.6 -423.5 -458.2 -464.1
Change in cash -1,080.4 27.0 446.6 0.0 0.0 0.0 0.0 Cash at period-end 327.7 354.7 801.4 801.4 801.4 801.4 801.4
DPS (PLN) 0.15 0.00 0.00 0.00 0.00 0.00 0.00 FCF -38.1 -395.0 -141.6 -1,088.0 -809.0 857.5 970.8 (CAPEX/Sales) 21.8% 20.7% 20.5% 24.3% 20.2% 13.3% 13.9%
Trading Multiples 2015 2016 2017 2018P 2019P 2020P 2021P P/E -1.9 9.6 2.6 2.7 3.3 3.1 2.9 P/CE 1.0 1.2 1.1 1.2 1.2 1.1 1.1 P/BV 0.2 0.2 0.2 0.2 0.2 0.2 0.2 P/S 0.2 0.2 0.2 0.2 0.2 0.2 0.2
FCF/EV -0.3% -3.3% -1.1% -7.9% -5.4% 5.9% 7.0% EV/EBITDA 3.2 3.6 3.5 3.8 4.3 3.8 3.5 EV/EBIT -6.0 15.2 6.9 7.1 8.9 8.0 7.2 EV/S 0.6 0.7 0.7 0.8 0.8 0.7 0.7
DYield 7.5% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Price per share (PLN) 2.0 Shares at year-end (millions) 1752.5 1752.5 1752.5 1752.5 1752.5 1753.5 1754.5 MC (PLN m) 3505.1 3505.1 3505.1 3505.1 3505.1 3507.1 3509.1 Minority interests (PLN m) 29.8 30.1 31.4 29.5 29.5 29.5 29.5 EV (PLN m) 11,308.7 12,129.8 12,480.0 13,821.9 14,965.4 14,479.2 13,885.5
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List of abbreviations and ratios contained in the report: EV – net debt + market value EBIT – Earnings Before Interest and Taxes EBITDA – EBIT + Depreciation and Amortisation P/CE – price to earnings with amortisation MC/S – market capitalisation to sales EBIT/EV – operating profit to economic value P/E – (Price/Earnings) – price divided by annual net profit per share ROE – (Return on Equity) – annual net profit divided by average equity P/BV – (Price/Book Value) – price divided by book value per share Net debt – credits + debt papers + interest bearing loans – cash and cash equivalents EBITDA margin – EBITDA/Sales
OVERWEIGHT (OW) – a rating which indicates that we expect a stock to outperform the broad market NEUTRAL (N) – a rating which indicates that we expect the stock to perform in line with the broad market UNDERWEIGHT (UW) – a rating which indicates that we expect the stock to underperform the broad market
Recommendations of Dom Maklerski mBanku: A recommendation is valid for a period of 6-9 months, unless a subsequent recommendation is issued within this period. Expected returns from individual recommendations are as follows: BUY – we expect that the rate of return from an investment will be at least 15% ACCUMULATE – we expect that the rate of return from an investment will range from 5% to 15% HOLD – we expect that the rate of return from an investment will range from -5% to +5% REDUCE – we expect that the rate of return from an investment will range from -5% to -15% SELL – we expect that an investment will bear a loss greater than 15% Recommendations are updated at least once every nine months. mBank S.A. with its registered office in Warsaw at Senatorska 18 renders brokerage services in the form of derived organisational unit – Brokerage Office which uses name Dom Maklerski mBanku.
This document has been created and published by Dom Maklerski mBanku. The present report expresses the knowledge as well as opinions of the authors on day the report was prepared. The opinions and estimates contained herein constitute our best judgment at this date and time, and are subject to change without notice. The present report was prepared with due care and attention, observing principles of methodological correctness and objectivity, on the basis of sources available to the public, which Dom Maklerski mBanku S.A. considers reliable, including information published by issuers, shares of which are subject to recommendations. However, Dom Maklerski mBanku S.A., in no case, guarantees the accuracy and completeness of the report, in particular should sources on the basis of which the report was prepared prove to be inaccurate, incomplete or not fully consistent with the facts. mBank S.A. bears no responsibility for investment decisions taken on the basis of the present report or for any damages incurred as a result of investment decisions taken on the basis of the present report.
This document does not constitute an offer or invitation to subscribe for or purchase any financial instruments and neither this document nor anything contained herein shall form the basis of any contract or commitment whatsoever. It is being furnished to you solely for your information and may not be reproduced or redistributed to any other person. This document nor any copy hereof is not to be distributed directly or indirectly in the United States, Australia, Canada or Japan.
Recommendations are based on essential data from the entire history of a company being the subject of a recommendation, with particular emphasis on the period since the previous recommendation. Investing in shares is connected with a number of risks including, but not limited to, the macroeconomic situation of the country, changes in legal regulations as well as changes on commodity markets. Full elimination of these risks is virtually impossible.
It is possible that mBank S.A. in its brokerage activity renders, will render or in the past has rendered services for companies and other entities mentioned in the present report. mBank S.A. does not rule out offering brokerage services to an issuer of securities being the subject of a recommendation. Information concerning a conflict of interest arising in connection with issuing a recommendation (should such a conflict exist) is located below. mBank S.A. acts as market animator for the Issuer. mBank S.A. acts as market maker for the Issuer.
In the last 12 months mBank S.A. had a brokerage agreement in place with Enea. In the last 12 month mBank might have received coompensation for services rendered Enea, Energa, PGE, and Tauron.
The production of this recommendation was completed on May 29, 2018, 8:34 AM. This recommendation was first disseminated on May 29, 2018, 8:34 AM. mBank S.A., its shareholders and employees may hold long or short positions in the issuer's shares or other financial instruments related to the issuer's shares.
Copying or publishing the present report, in full or in part, or disseminating in any way information contained in the present report requires the prior written consent of mBank S.A.
Recommendations are addressed to all Clients of Dom Maklerski mBanku.
The activity of mBank S.A. is subject to the supervision of the Polish Financial Supervision Commission.
Individuals who did not participate in the preparation of recommendations, but had or could have had access to recommendations prior to their publication, are employees of Dom Maklerski mBanku authorised to access the premises in which recommendations are prepared and/or individuals having to access to recommendations based on their corporate roles, other than the analysts mentioned as the authors of the present recommendations.
This publication constitutes investment research within the meaning of Art. 36.1 of Commission Delegated Regulation (EU) 2017/565.
The compensation of the research analysts responsible for preparing investment research is determined independently of and without regard to the compensation of or revenue generated by any other employee of the Bank, including but not limited to any employee whose business interests may reasonably be considered to conflict with the interests of the persons to whom the investment research prepared by the Research Department of Dom Maklerski mBanku is disseminated. With that being said, since one of the factors taken into consideration when determining the compensation of research analysts is the degree of fulfillment of annual financial targets by customer service functions, there is a risk that the adequacy of compensation offered to persons preparing investment research will be questioned by a competent oversight body.
For U.S. persons only: This research report is a product of mBank SA which is the employer of the research analyst(s) who has prepared the research report. The research analyst(s) preparing the research report is/are resident outside the United States (U.S.) and are not associated persons of any U.S. regulated broker-dealer and therefore the analyst(s) is/are not subject to supervision by a U.S. broker-dealer, and is/are not required to satisfy the regulatory licensing requirements of FINRA or required to otherwise comply with U.S. rules or regulations regarding, among other things, communications with a subject company, public appearances and trading securities held by a research analyst account.
This report is intended for distribution by mBank SA only to "Major Institutional Investors" as defined by Rule 15a-6(b)(4) of the U.S. Securities and Exchange Act, 1934 (the Exchange Act) and interpretations thereof by U.S. Securities and Exchange Commission (SEC) in reliance on Rule 15a 6(a)(2). If the recipient of this report is not a Major Institutional Investor as specified above, then it should not act upon this report and return the same to the sender. Further, this report may not be copied, duplicated and/or transmitted onward to any U.S. person, which is not the Major Institutional Investor.
In reliance on the exemption from registration provided by Rule 15a-6 of the Exchange Act and interpretations thereof by the SEC in order to conduct certain business with Major Institutional Investors, mBank SA has entered into an agreement with a U.S. registered broker-dealer, Cabrera Capital Markets. ("Cabrera"). Transactions in securities discussed in this research report should be effected through Cabrera or another U.S. registered broker dealer.
Strong and weak points of valuation methods used in recommendations: DCF – acknowledged as the most methodologically correct method of valuation; it consists in discounting financial flows generated by a company; its weak point is the significant susceptibility to a change of forecast assumptions in the model. Relative – based on a comparison of valuation multipliers of companies from a given sector; simple in construction, reflects the current state of the market better than DCF; weak points include substantial variability (fluctuations together with market indices) as well as difficulty in the selection of the group of comparable companies. Economic profits – discounting of future economic profits; the weak point is high sensitivity to changes in the assumptions made in the valuation model. Discounted Dividends (DDM) – discounting of future dividends; the weak point is high sensitivity to changes in the assumptions as to future dividends made in the valuation model. NAV - valuation based on equity value, one of the most frequently used method in case of developing companies; the weak point of the method is that it does not factor in future changes in revenue/profits of a company.
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mBank issued the following recommendations for CEZ in the last 12 months: recommendation sell reduce hold hold accumulate accumulate buy accumulate accumulate date issued 2018-05-09 2018-04-06 2018-03-05 2018-02-02 2017-12-01 2017-11-03 2017-10-02 2017-09-01 2017-06-27 target price (PLN) 449.51 449.51 506.40 532.50 548.60 512.33 512.33 468.78 453.01 price at rating day 567.00 519.50 495.00 530.00 490.70 481.30 441.30 416.00 399.00 mBank issued the following recommendations for Enea in the last 12 months: recommendation buy buy accumulate accumulate hold hold hold hold date issued 2018-04-06 2018-03-05 2018-02-02 2018-01-05 2017-12-01 2017-10-02 2017-09-01 2017-06-27 target price (PLN) 11.78 12.11 12.98 12.82 12.82 14.59 15.23 12.60 price at rating day 9.10 10.36 11.07 12.19 11.89 14.80 15.25 13.14 mBank issued the following recommendations for Energa in the last 12 months: recommendation buy buy buy buy buy accumulate hold accumulate hold date issued 2018-04-06 2018-03-05 2018-02-02 2018-01-05 2017-12-01 2017-10-02 2017-09-01 2017-07-21 2017-06-27 target price (PLN) 14.91 14.71 15.20 14.97 14.81 14.49 13.50 13.20 10.71 price at rating day 9.96 10.11 12.21 12.60 12.09 13.40 13.64 11.65 10.87 mBank issued the following recommendations for PGE in the last 12 months: recommendation buy buy accumulate accumulate hold hold accumulate buy date issued 2018-04-06 2018-03-05 2018-02-02 2017-12-01 2017-10-02 2017-09-01 2017-08-02 2017-06-27 target price (PLN) 12.89 12.61 13.30 13.20 13.61 14.98 14.46 14.46 price at rating day 9.81 10.28 11.87 11.93 13.30 14.27 13.29 12.29 mBank issued the following recommendations for Tauron in the last 12 months: recommendation hold hold hold hold hold hold hold date issued 2018-04-06 2018-03-05 2018-02-02 2017-12-01 2017-10-02 2017-09-01 2017-06-27 target price (PLN) 2.73 2.98 3.38 3.23 3.64 3.89 3.67 price at rating day 2.38 2.69 3.08 3.10 3.75 3.92 3.65
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Dom Maklerski mBanku Senatorska 18 00-082 Warszawa http://www.mbank.pl/
Research Department
Kamil Kliszcz Michał Marczak Michał Konarski director +48 22 438 24 01 +48 22 438 24 05 +48 22 438 24 02 [email protected] [email protected] [email protected] strategy banks, financials energy, power generation
Jakub Szkopek Paweł Szpigiel Piotr Zybała +48 22 438 24 03 +48 22 438 24 06 +48 22 438 24 04 [email protected] [email protected] [email protected] industrials, chemicals, metals media, IT, telco construction, real-estate development
Piotr Bogusz +48 22 438 24 08 [email protected] retail
Sales and Trading
Traders
Piotr Gawron Krzysztof Bodek Tomasz Jakubiec director +48 22 697 48 89 +48 22 697 47 31 +48 22 697 48 95 [email protected] [email protected] [email protected]
Jędrzej Łukomski Adam Prokop Szymon Kubka, CFA, PRM +48 22 697 49 85 +48 22 697 47 90 +48 22 697 48 54 [email protected] [email protected] [email protected]
Andrzej Sychowski Tomasz Galanciak Magdalena Bernacik +48 22 697 48 46 +48 22 697 49 68 +48 22 697 47 35 [email protected] [email protected] [email protected]
Sales, Foreign Markets
Marzena Łempicka-Wilim Bartosz Orzechowski deputy director +48 22 697 48 47 +48 22 697 48 82 [email protected] [email protected]
Private Broker
Kamil Szymański Jarosław Banasiak director, active sales deputy director, active sales +48 22 697 47 06 +48 22 697 48 70 [email protected] [email protected]
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