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Changes in assumptions and market trends

Bringing assumptions closer to Minecon’s tariff guidance…

Renaissance Capital

9 January 2019

Utilities

We change some of our macro projections based on the recently released (November 2018) Ministry of Economic Development (Minecon) social economic development plan through to 2024. The plan assumes tariff growth for the population will be set at 5% till 2024 (we had previously assumed convergence with inflation as early as 2022), while gas tariffs are to be set at 3% till 2024 (we had again previously assumed convergence with inflation by 2022). The plan also sets a lower growth rate for 2019 tariffs (as it incorporates a VAT increase from 18% to 20% from January 2019).

As a result, we adjust our forecasts to bring them in line with Minecon’s tariff proposal, as we are now more inclined to believe that the government wants to address cross subsidies between the population and industry by raising electricity tariffs for the population. We leave our grid tariff growth assumption unchanged (and in line with current Minecon projections) despite indications in the press that tariffs could be raised to close to inflationary level (inflation – 0.1%) vs (inflation – 1%) as in our forecast. We also adjust our estimates for competitive capacity tariffs in the first price zone (PZ1) based on proposed government regulation on modernisation (we assume that the price parameters for KOM are adjusted by 15% in 2022 (relative to 2017 excluding adjustment for inflation), 0% in 2023 (relative to 2017 excluding adjustment for inflation), and 5% in 2024 (relative to 2017 excluding adjustment for inflation) as in the last version of the modernisation decree) (Figure 12).

Figure 12: Macro assumptions

	2017	2018E	2019E	2020E	2021E	2022E	2023E	2024E	2025E	2026E	2027E	2028E	2029E
Real GDP (% YoY)	1.5	1.9	1.4	2.4	2.2	2.4	2.4	2.3	2.3	2.3	2.3	2.3	2.3
Electricity demand (% YoY)	1.6	0.4	0.2	0.6	0.5	0.6	0.6	0.6	0.6	0.6	0.6	0.6	0.6
Gas price (% YoY)	2.0	3.7	2.4	2.2	3.0	3.0	3.0	3.0	3.5	4.0	4.0	4.0	4.0
Electricity price (% YoY)	0.1	3.8	2.5	2.4	3.2	3.0	3.0	3.0	3.5	4.0	4.0	4.0	4.0
Regulated electricity tariff, % (YoY)	6.3	5.0	3.3	5.0	5.0	5.0	5.0	5.0	4.0	4.0	4.0	4.0	4.0
CPI, annual average (% YoY)	3.7	3.0	5.2	3.7	4.0	4.0	4.0	4.0	4.0	4.0	4.0	4.0	4.0
Price KOM 1PZ, RUB '000/month/MW	118.2	119.7	123.7	128.2	151.5	181.0	188.0	205.1	213.3	221.9	230.7	232.0	233.3
Price KOM 2PZ, RUB '000/Month/MW	189.8	200.3	213.2	212.0	254.0	264.1	274.7	285.7	297.1	309.0	321.3	323.1	324.9

Source: Company data, Renaissance Capital estimates

We note that in the latest version of the modernisation decree (which is likely to be approved in January 2019 we believe) the government is set to increase the KOM capacity price via additional indexation (apart from the inflationary one) of the price parameters of the KOM capacity auctions, which should increase growth in competitive capacity tariffs (Figures 13 and 14).

Figure 13: KOM parameters indexations

Figure 14: KOM parameters indexation, 2017 base w/o inflation adjustments

Price			25%
					20%
			20%
			15%	15%
			15%
Price 1
			10%
	Price 2		5%
		Capacity	0%
			2022E	2023E	2024E
Demand 1	Demand 2

Source: Company data, Renaissance Capital estimates	Source: InterRAO

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…as the spread between electricity prices and tariff growth diminishes…

We also leave our forecast for electricity price growth unchanged as we see evidence of the negative spread between electricity price growth and gas tariff growth disappearing, which supports our assumption that electricity prices will depend on consumption growth starting from 2019. We also note that InterRAO in its updated (December) long-term forecasts also expects the negative spread between growth in electricity prices and gas tariffs to disappear in 2018-2022, while in its previous forecasts the company expected the negative spread to remain in the medium term.

Figure 15: Electricity price dynamics, 2018

	PZ1		PZ2		Gas tariff increase YoY					Consumption (rhs)
20.0%												7.00%
15.0%												6.00%
10.0%												5.00%
												4.00%
5.0%												3.00%
0.0%												2.00%
-5.0%												1.00%
												0.00%
-10.0%												-1.00%
-15.0%	Feb-18	Mar-18	Apr-18			Jul-18			Oct-18			-2.00%
Jan-18				May-18	Jun-18		Aug-18	Sep-18		Nov-18	Dec-18	Jan-19

Source: Company data, Renaissance Capital estimates

Despite a 3.9% YoY increase in gas tariffs in 1H18, electricity prices in PZ1 rose by only 2.1% YoY in 1H18, while prices in the second zone (PZ2) advanced by 2.1%. However, in 2H18 the gas tariff was raised by 3.4% YoY, effective 21 August (instead of 1 July), so average gas tariff growth in 2H18 has been 2.45%, vs electricity price growth at almost 5.05% YoY in PZ1 and 4.4% in PZ2. Thus, electricity prices have increased by 3.4% and 3.4% in 2018 in PZ1 and PZ2, respectively. The average growth in gas tariffs in FY18 is 3.17%. Thus, the spread between gas tariff and electricity price growth in PZ1 has almost disappeared. We also note that electricity consumption rose 1.3% in January-November 2018. Moreover, electricity price growth in 1H18 was heavily affected by a significant rise in hydro production (which translates into a decrease in demand for thermal plants that set the price). Price dynamics in 2H18 so far indicate that electricity prices are rising faster than gas prices, reflecting growth in electricity demand, we believe (Figure 15). Moreover, since the start of 2019 the spread is almost zero for the PZ1, while the growth in electricity prices in PZ2 is likely related to lower water flow.

Thus, we stand by our previous assumption that after the DPM programme is completed, the spread between growth in electricity market prices and growth in gas tariffs should be more or less defined by growth in electricity consumption. Moreover, as modernisation is unlikely to result in significant improvements in efficiency in the system, it should not significantly affect the spread either.

We note that the latest version of modernisation legislation allows the following modernisation projects to be implemented:

▪Boiler equipment: Replacement of steam boiler or a replacement at least four elements of the boiler: boiler barrel, boiler superheater, furnace waterwall, and crossover pipes.

Renaissance Capital

9 January 2019

Utilities

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Renaissance Capital 9 January 2019

Utilities

▪Turbines: Replacement of high-pressure cylinder (HPC), replacement of HPC and medium pressure cylinder (MPC), transformation of combustion turbine units into combine-cycle unit.

▪Associate events: Modernisation of electrical power generator, construction of coolers and pump stations, replacement of the heater of regeneration system, replacement of steam pipes, dust-collecting equipment, and stack, reconstruction of main building, etc.

Additional capacity as a result of the modernisation project should not exceed 20%, while the maximum improvement in specific reference fuel consumption is estimated not to exceed 3% in case of assembly replacement and 6% in case of integrated modernisation, according to InterRAO. This corroborates our assumption that we are unlikely to see a significant improvement in the system’s efficiency due to modernisation, which will likely be generally neutral in terms of its influence on growth in electricity market prices.

…and adjusting our forecast for DPM returns based on a zerocoupon rate

We have also witnessed a gradual rise in the zero-coupon rate in 2H18 (Figure 16) on the Russian debt market, which could be a proxy for the OFZ rate used to calculate DPM tariffs (Figure 17).

Figure 16: Zero-coupon rate, 2018, %

Figure 17: Zero-coupon rate vs OFZ rate in DPM, %

10												12.00
9
8												10.00
7
6												8.00
5												6.00
4
3												4.00
2
1												2.00
0	Feb-18	Mar-18	Apr-18	May-18		Jul-18			Oct-18
Jan-18					Jun-18		Aug-18	Sep-18		Nov-18	Dec-18	0.00

Average zero-coupon rate, %		OFZ rate in DPM, %

2014

2015

2016

2017

2018

Source: MICEX

Source: Bloomberg, Company data, Renaissance Capital estimates

Given that the average zero coupon rate is above its 2017 level, we expect that DPM will use an OFZ rate close to (8.3% on our estimates) what was used last year (8.34%). Moreover, as we believe we are likely to see inflation rise in 2019, we expect the OFZ rate to reach 8.5% next year. Thereafter we could see a gradual decline in the rate, which we set at 7.8% for the long term (Figure 18). To address the possible decline in the rate of return for the modernisation projects mentioned above, we examined the sensitivity of typical modernisation tariffs to the spread between the rate of return (we note that the government considers 14% for the first modernisation cycle, but a possible lowering to 12% for the balance of the programme) and the DPM OFZ rate (8.5% for a 14% modernisation return and 7.5% for a 12% return). We estimate that a change of 1% in the spread results in a change in the tariff of close to 5-6%, which we view as insufficiently dramatic to significantly affect the financials of the modernisation projects.

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														Renaissance Capital
														9 January 2019
														Utilities
Figure 18: Modernisation tariff, DPM tariff, OFZ rate forecast			Figure 19: Modernisation tariff as a function of base rate of return and DPM OFZ
			rate
		DPM tariff, RUB '000/MW/month				7.5%		8.0%		8.5%		9.0%		9.5%
		Modernisation tariff, RUB '000/MW/month	600

	700														12.00%
	600														10.00%	500
	500														8.00%	400
	400															300
															6.00%
	300
	200														4.00%	200
	100														2.00%	100
	0														0.00%	0
	2013	2014	2015	2016	2017	2018	2019	2020	2021	2022	2023	2024	2025	2026	2027
																12.0%	13.0%	14.0%	15.0%	16.0%
													Source: Renaissance Capital estimates						Source: Renaissance Capital estimates

We believe that if the government were to lower the spread between the modernisation rate of return and the OFZ rate, competition at the modernisation auction would decline, making it possible for the Gencos to bid for higher (relative to the case with strong competitions) capex (though still limited by the capex cap set by the government) or smaller profit margins in the electricity market, which could potentially leave the financials of the modernisation projects unchanged on a net basis, despite the lower rate of return.

Modernisation saga likely to end in 1H19…

We believe the main reason for utility stocks’ underperformance this year is the unclear situation regarding modernisation and capacity auctions, as well as doubts over the government’s desire to approve an attractive rate of return for modernisation projects to attract investment in the utility sector. Despite constant delays, we now believe that the final modernisation regulation will be signed in January 2019, which should then set the deadline for modernisation and capacity auctions to be carried out no later than 90 and 155 days (Figure 20), respectively, after the regulation is signed. As attractive modernisation parameters are likely to be approved only for the first three-year period of modernisation (2022-2024), the government will have to set the parameters for 2025 modernisation based on the results of the first auctions. The next round of modernisation auctions (for 2025) is likely to be held not before 1 September 2019, and subsequent KOM auction not before 15 November. Thus in 2H19 we should get a better idea of the government’s stance on further modernisation, which should make long-term forecasting easier.

Figure 20: Modernisation stages

X	-	X+30	X+60 The end of	X+125 The final
Regulation		GTP	modernisation	resultd	of
signed in		registrations	auctions	modernisation

X+155 KOM auctions

Source: InterRAO

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Renaissance Capital 9 January 2019

Utilities

We show the stages of modernisation in Figure 20. X is the date when the government decree on modernisation is signed, and the numbers are the maximum amount of days that the next stage must be completed by. Thus, the modernisation auctions must be held no later than two months after the decree is signed, while the KOM auctions should come one month after the modernisation results are approved by the government.

Projects with the lower levelised cost of electricity (LCOE)-type price will be chosen during the modernisation auctions.

= + + (1 − )

Where:

Pcapex – capex in the price bid of the generator (limited by capex caps, calculated for different types of projects)

Opex – opex in the price bid of the generator (limited by price at the KOM auctions)

CUF – capacity utilisation factor of the generator for the past three years before the auction (likely to be limited at 60% or above)

Pdam – electricity price at the day ahead market for the last year before the auction

Kdam – coefficient related to the margins the generator earns at the day-ahead electricity market, which is the higher the lower the specific reference fuel consumption (heat rate) is.

We believe that larger, more efficient generating units will have a competitive advantage in the modernisation auctions. This makes InterRAO (followed by Enel Russia and Unipro, although it will exercise a cautious approach to modernisation, in our view) stand out from other companies and likely to benefit most from the modernisation auctions, we believe. Moreover, the government has set strict localisation criteria for modernisation projects. If the company is not able to adhere to a localisation level the project will be unsuccessful and will not get the modernisation tariff. The government also set strict fees for late commissioning or lower capacity roughly at the level of 25% of modernisation tariff.

While improved market fundamentals could result in lower impairments

In our view, there are several reasons for the property, plant, and equipment (PPE) impairment charges we have seen in the sector over the past several years. They have differed from one company to the next, but basically reflected the adverse electricity and capacity market environments (suppressed electricity and capacity prices due to the previous capex cycle in the sector and lower indexation of gas tariffs vs those initially planned by the government) vs companies’ more optimistic business plans, management expectations, etc. Capex for new build also often exceeded initial estimates, which have also been reflected in the impairments. In Figure 21, we can see that on average PPE impairment charges were quite significant relative to companies’ EBIT over 2013-2017, apart from TGK1, which mostly reversed the impairments.

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Renaissance Capital 9 January 2019

Utilities

Figure 21: PPE impairment charges, RUBmn (unless otherwise stated)

		2013	2014	2015	2016	2017
	EBIT	15,739	19,021	16,715	6,718	41,187
Unipro	PPE impairments	3,440	159	703	4,307	325
	Impairments/EBIT, %	22%	1%	4%	64%	1%
	EBIT	9,852	9,778	(54,682)	10,334	13,970
Enel	PPE impairments	0	1,961	58,175	0	61
	Impairments/EBIT, %	0%	20%	-106%	0%	0%
	EBIT	(18,473)	19,946	25,743	77,260	56,120
Inter Rao	PPE impairments	19,554	4,850	14,766	4,082	10,995
	Impairments/EBIT, %	-106%	24%	57%	5%	20%
	EBIT	(5,302)	22,844	33,882	34,681	47,539
Hydro	PPE impairments	18,995	8,884	12,593	26,525	24,000
	Impairments/EBIT, %	-358%	39%	37%	76%	50%
	EBIT	6,874	(722)	3,918	9,389	15,551
OGK2	PPE impairments	0	8,647	420	(336)	(852)
	Impairments/EBIT, %	0%	-1198%	11%	-4%	-5%
	EBIT	9,837	1,571	(1,915)	15,636	27,356
Mosenergo	PPE impairments	902	7,019	10,283	0	0
	Impairments/EBIT, %	9%	447%	-537%	0%	0%
	EBIT	9,891	6,496	10,017	8,601	11,986
TGK-1	PPE impairments	(740)	(2,953)	221	(1,313)	0
	Impairments/EBIT, %	-7%	-45%	2%	-15%	0%
	EBIT	(262,546)	(15,326)	57,229	79,847	83,021
FGC	PPE impairments	292,860	70,775	2,850	38,155	13,862
	Impairments/EBIT, %	-112%	-462%	5%	48%	17%
	EBIT	(148,821)	14,112	136,343	143,457	191,317
Rosseti	PPE impairments	239,446	81,690	(5,090)	38,503	1,912
	Impairments/EBIT, %	-161%	579%	-4%	27%	1%

Source: Company data

Now the situation has changed, in our view. First, most DPM projects have been completed. The market regulator has also adopted a more reasonable approach to calculating DPM tariffs (higher government bond yield, higher share of capacity contribution in the return on investments component in the DPM tariff (krsv coefficient)). We are also unlikely to see further profit margins squeezed due to the negative spread between gas and electricity prices, as the effect of DMP projects are fully realised on the market, while modernisation will not result in significant pressure on electricity market prices. Moreover, we are likely to see a significant rise in KOM capacity prices to an economically justified level due to modernisation, which should improve the fair value for the old units.

We believe that, given these developments in market fundamentals, we may see a decrease in impairment charges in the Genco space (apart from RusHydro whose impairments are related to the commissioning of power plants in the Far East, where no economically justified tariffs exist and likely exceed of the total capex above what has been initially planned). Higher KOM prices (which could rise to economically justified levels in the medium term) will likely prevent impairments in PPE for old units, while PPE impairments related to new construction will likely disappear as almost all DPM projects are not completed.

The grid segment has been characterised by inefficient capex and ad hoc tariff regulation, so the grid companies had to incur significant impairment charges as well. The PPE impairment charges were subject to impairment due to a worsening tariff regulation regime and lack of loads on newly built capacities, we believe. Both Rosseti and FGC incurred significant PPE impairments in 2013 and 2014, which in our view was a result of the imposed tariff freeze in 2014 and significantly lower growth in grid tariffs beyond 2014 compared with the subsequent growth in tariffs implied in Rosseti’s and FGC’s business plans, which were based on non-modified RAB regulation. We now believe that the proposed friendlier grid tariff regulation, at least in terms of setting long-term tariffs with almost inflationary growth and the proposed payments by consumers for non-used grid

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reserve capacity, could result in lower impairment charges going forward, which could boost dividend yield, especially in FGC’s case.

MRSK performance in 2019 will mostly be defined in 4Q18 results, we believe

We believe that one of the main factors that will define the performance of MRSK shares will be impairment charges which companies will book in 4Q18 and thus for FY18. Impairments have significantly supressed the sector’s bottom line in the past. As the segment has been characterised by inefficient capex and ad hoc tariff regulation, the companies had to incur significant impairment charges. Moreover, not only was PPE subject to impairment due to a worsening tariff regulation regime and lack of loads on newly built capacities, but MRSKs also suffered significant impairments in account receivable (AR), which though have significant regional specifics.

Most companies incurred significant PPE impairments in 2014, which in our view was a result of the imposed tariff freeze in 2014 and significantly lower growth in grid tariffs beyond 2014 compared with the subsequent growth in tariffs implied in the MRSKs’ business plans, which were based on RAB regulation. Before 2014, significant PPE impairment charges were incurred only by Lenenergo (in 2011 and 2012), Kubanenergo (in 2012), and MRSK Ural (in 2012 and 2013). After 2014 and before 2017, Lenenergo reversed almost all impairments it incurred in 2011 and 2012 in 2015, while MRSK Center & Volga also reversed most of its 2014 PPE charges over the next three years. MRSK Ural and MRSK Caucasus continued to suffer from PPE impairment charges regularly.

In 2017 both Lenenergo and Moscow United Distribution Company suffered significant impairments, the nature of which is not disclosed in financial reports and is obscure to us. Among other companies only MRSK Center and MRSK Caucasus saw material impairment charges in 2017. Thus, we could expect that in the next two years we will see significantly lower PPE impairment charges, which could boost the bottom lines of the MRSKs. However, to value the companies we applied an average impairment charge over the 2011-2017 period. Impairment of AR showed a different dynamic over 20112017. The highest level of impairments was seen in the North Caucasus where the nonpayments epidemic is well known and where the average impairment charge stood at 42% of net AR during 2011-2017. This is the main reason for such a dismal performance of MRSK Caucasus in terms of profitability and debt burden.

Other MRSKs showed no pattern in their AR charges over the period, except maybe Moscow United Distribution Company and Lenenergo. Moscow United Distribution Company incurred impairments of AR almost every year with the average charge being close to 10% of net AR. Lenenergo incurred significant charges in 2011, 2012 and in 2015 and 2016, the average charge over the period stood at 18%. We have also seen significant charges for Tomsk Distribution Company in 2011 and in 2012, which significantly decreased after that. MRSK Volga and MRSK Ural showed the lowest average charge over 2011-2017 vs other MRSKs. Moreover, the impairment charges for these two companies had almost homogeneous distribution over the years, with no spikes.

MRSK South saw significant spikes in impairments in 2011 and 2014 with almost no impairments in other years. MRSK Center saw a spike in impairments in 2013 and at a lesser level in 2016, with minor impairment charges in other years. MRSK North-West on the contrary incurred only minor charges during 2011-2017 but suffered a significant charge (almost 60% of net AR) in 2017. We believe that significant spikes in AR impairments were

Renaissance Capital

9 January 2019

Utilities

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partly connected with the liquidation/bankruptcies of several Guaranteed Electricity Supply companies (suppliers of last resort) and the probability of that happening again has diminished significantly now. Nevertheless, we see no pattern in distribution of impairment charges over the years and have used an average percentage of net AR in our models for future periods. Moreover, we see the average level of impairments are quite high and could see it decrease in future years, especially for MRSK Caucasus, MRSK South, Lenenergo, MRSK North-West, and even Moscow United Distribution Company.

We have already witnessed significant impairment charges booked by MRSK Ural already in 1H18. The company incurred a RUB1.2bn loss in 1H18 owing to an impairment charge for AR of RUB6.4bn. The charge was incurred after two regional supply companies lost their guaranteed supply status. We note that this is a record impairment charge for AR in the past seven years; impairment charges over 2011-2017 totalled just RUB2.2bn, with a maximum annual charge of RUB0.93bn incurred in 2015. Thus, such a significant rise in AR impairment charges in 1H18 was a surprise to us and the market, in our view.

Though we don’t expect additional surprises from other MRSKs in 4Q18, we believe that the moves in MRSK share prices could be significant based on 4Q18 results and thus FY18 results, as low impairment charges for FY18 could significantly improve market sentiment and dividend yields, in our view, while the high charges will likely significantly decrease investor interest in the stocks.

Changes to forecasts based on 9M18 results…

All the utility companies under our coverage reported their 9M18 IFRS results in November and in the first half of December (RusHydro). Despite the numbers coming in relatively close to our estimates (Figure 22), we have adjusted our FY18 forecasts (and beyond) based on the results.

Figure 22: Actual 9M18 figures vs our estimates, %

	Revenue	EBITDA	Net income
Enel	-1%	-3%	-7%
Unipro	-1%	-1%	-3%
Mosenergo	0%	1%	0%
OGK2	0%	8%	5%
TGK1	1%	2%	3%
InterRAO	0%	12%	13%
RusHydro	2%	5.3%	-2.0%
FGC	-2%	2%	3%
Rosseti	0%	2%	1%

Source: Company data, Renaissance Capital estimates

9M18 results beat our forecasts (and consensus forecasts where available) for InterRAO and OGK-2, while coming in close to our estimates for the rest, though Enel and Unipro fell slightly short. RusHydro beat our forecast on EBITDA but came slightly below in the bottom line. We have incorporated the 9M18 figures into our models (we did so for Enel Russia on 1 November and for RusHydro on 11 December), thus adjusting our FY18 estimates (and the figures beyond where appropriate).

…and changes to our WACC assumptions

We also update our WACC estimates (Figure 23), slightly decreasing the risk-free rate from 8.94% to 8.76% but raising the risk premium from 6.93% to 9.3%. We also update our beta estimates for all companies. As a result, our new WACC estimates increase for

Renaissance Capital

9 January 2019

Utilities

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Renaissance Capital 9 January 2019

Utilities

most companies (Figure 23). We base our WACC calculation on companies’ current and forecast capital structure, which we believe are inefficient, as most companies have almost no leverage. Nevertheless, we are reluctant to incorporate more efficient capital structure assumptions (as for example InterRAO does for its purposes), as historically most of the companies have been meaningfully reducing their debt exposure in favour of distributing cash to shareholders. Moreover, most companies have lower leverage and as their FCF should remain strong even during the modernisation cycle, it is unclear as to whether additional debt will be accrued, in our view.

Figure 23: WACC estimates, %

	WACC, %	2018	2018	2019	2020	2022	2023	2024	2025	2026	2027	2028	2029
Enel	12.5-11.7	12.5	12.0	11.8	11.8	11.8	11.8	11.8	11.8	11.8	11.7	11.7	11.7
Unipro	14.1-13.7	14.1	14.1	14.0	14.0	13.8	13.8	13.8	13.8	13.7	13.7	13.7	13.7
Mosenergo	15.9-15.7	15.9	15.7	15.9	15.9	15.9	15.7	15.7	15.7	15.7	15.7	15.7	15.7
OGK2	13.2-12.3	12.3	12.4	12.5	12.7	13.0	13.0	13.0	13.0	13.0	13.0	13.1	13.2
TGK1	15.5-17.3	15.5	16.6	17.3	17.3	17.3	17.3	17.3	17.3	17.3	17.3	17.3	17.3
InterRAO	17.6-17.6	17.6	17.6	17.6	17.6	17.6	17.6	17.6	17.6	17.6	17.6	17.6	17.6
RusHydro	11.9-13.4	11.9	11.9	12.0	12.3	12.6	13.0	13.4	13.4	13.4	13.4	13.4	13.4
FGC	11.3-14.3	11.3	13.4	13.6	13.9	14.3	14.3	14.3	14.3	14.3	14.3	14.3	14.3
Rosseti	9.3-11.2	9.3	11.2	11.2	11.2	11.2	11.2	11.2	11.0	11.0	11.0	11.0	11.0

Source: Renaissance Capital estimates

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