Equity Research
Thematic Report
Brazilian Utilities
Utilities
April 9, 2024
Dry and high? Insights and sensitivities for reservoirs and prices after
disappointing hydrology in 2024
The (dry) summer is over. What were its impacts? In Brazil, the wet season starts in October and
ends in April, but rainfall is concentrated from January to March (55% of the total wet season).
As a result, after the wet season ends, it is unlikely that months in the rest of the year (water
inflows in the wet season represent 70% of the total for the year) will compensate for a drier
summer. During the dry season (from mid-fall to early spring in Brazil), reservoirs are expected
to deplete by close to 30pps. Consequently, based on the demand forecast of the National
Operator of the Electricity System (ONS) and assuming that the current hydrology (~70% of the
long-term average) will be maintained and that no additional thermal dispatch is required, we
expect reservoir levels to stand at ~35% at year-end 2024 and ~20% in 2025. These numbers are
tight, thus suggesting that additional thermal dispatch would be desirable, in our view.
How much more thermal generation would be needed? Reservoirs are at 71% of their maximum
capacity, leading to a comfortable supply-demand balance. Moreover, although the
ONS/EPE/CCEE estimate that demand will increase 3.9% YoY in 2024 (a strong figure), we see no
problems in meeting it, considering the ~33% excess supply (firm capacity) in the system. Yet,
we believe the operator should be conservative to reduce the risks related to poor hydrology in
the next wet season (2024/2025), especially because hydroelectric energy still represents 54%
of Brazil´s total firm capacity, while intermittent sources provide another 19% of firm capacity—
the latter cannot generate energy 24/7 and might be replaced during peak hours. As a result, in
our base-line scenario, we believe that, ideally, 9 GW of average thermal generation would be
required to guarantee a decent cushion for reservoirs in the 2024/2025 and 2025/2026 wet
seasons. In a bear case, we estimate that ~14 GW would be required to keep reservoirs at a
reasonable level until YE 2025.
How does this affect prices? Assuming our base case that an average of 9 GW of thermal
generation will be required to meet demand, we arrive at R$150–R$199 per MWh of marginal
cost (including Angra I and II). In our bear scenario, we estimate potential thermal generation of
12 to 14 GW (as seen in 2021, another dry year, when hydrology in the wet season was close to
60% of the long-term average) and marginal cost of R$280–R$330 per MWh. This thermal
dispatch and its larger impacts on prices might be more prominent in late winter (as a result of
higher depletion in reservoirs) and when demand picks up again (October and November) as a
result of higher temperatures, before the wet season’s full potential reaches the system (inflows
typically improve reservoir levels as of December).
Our take? Volatility is expected; prices for bilateral contracts could be sustained and thermal
dispatch should be higher than in 2023. After considering the possible scenarios for hydrology in
the 2024/2025 wet seasons, we expect more thermal dispatch starting in May (from 9 GW to 14
GW, depending on hydrology, vs. 7 GW in 2023) and a potential increase in spot prices (reflecting
the higher dispatch, especially when demand starts to peak again). As the spike in spot prices will
likely persist and the outlook for hydrology in 2025 is uncertain, we believe prices for energy
contracts could be sustained at higher levels in the mid-term. We see this scenario as likely
positive not only for Eletrobras (ELET3/ELET6; TP R$ 54.40/59.40; Outperform) but also for Eneva
(ENEV3; TP R$ 15.80; Outperform).
q
Carolina
Carneiro
u+55 11 3175 4266
ncarolina.carneiro@safra.com.br
Da
Daniel Travitzky
Ca
+55 11 3175 4352
daniel.travitzky@safra.com.br
+5
ca
Mario Wobeto
+55 11 3175 9327
mario.wobeto@safra.com.br
+5
da
Have you seen the hydrology?
How dry was last summer? After 2001 (when water rationing was in effect), the 2024 summer
was the fourth worse in terms of hydrology (from January to March, which corresponds to 55%
of the entire wet season), beaten only by 2014 and 2015, which were also excessively dry years
(with super-high thermal generation, totaling more than 15 GW in operation). Thankfully, in
2024, reservoirs are starting the dry season at comfortable levels (71% of maximum capacity)
and the system has more excess capacity (from renewables) to support a better supply-demand
balance in YE2024, but the scenario is clearly not ideal.
Figure 1: Summer hydrology (ENA, % of long-term average) – 2000-2024
88% 86%
104%
100%
95%
87% 89%
81% 77%
64%
2001
91%
86% 86%
81%
77%
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
75%
2016
2017
68%
65%
62%
59% 61%
81%
79%
2018
2019
2020
2021
62%
2022
2023
2024
Source: National Operator of the Electricity System (ONS) and Safra.
Why is this a big problem? Once the wet season ends (April), reservoir levels usually start to
decline sharply (as shown in Figure 2) by around 30% from April to November. This would not
be a problem if the system could count on significant dispatchable energy sources to replace
hydroelectric energy when reservoir levels are lower. Although hydroelectric energy has lost
share in terms of total capacity (from 68% in 2016 to 46% in 2024), it still accounts for 54% of
the system’s firm capacity, while thermal generation represents only 19% of firm capacity (with
a potential decline in its share from 2024–2028 because the operating authorization of several
thermal units will expire, and some will be considered fully depreciated). Consequently, in a
scenario of much lower reservoir levels and still-timid hydrology (depending on the next wet
season), the operator might be conservative and save water from reservoirs during the winter,
in our view.
Figure 2: Depletion of power reservoirs from April - November
42%
41%
34%
44%
32%
42%
42%
35%
33%
31%
27%
24%
26%
25%
22% 23%
20%
16%
15%
22% 23%
19%
18%
7%
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
Source: National Operator of the Electricity System (ONS) and Safra.
2
Figure 3: Share of different sources in the matrix (installed vs. firm)
Share (GW) - Installed Capacity
Share (GWm) - Firm Capacity
9%
16%
41%
16%
26%
22%
19%
14%
69%
68%
54%
46%
2016
Hydroelectric
2016
2024
Thermal
Intermittent power supplies
Hydroeletric
2024
Thermal
Intermittent power supplies
Source: National Operator of the Electricity System (ONS), companies and Safra.
How bad could it be for reservoirs?
Demand vs. supply in balance, but could risks be higher? As mentioned previously, reservoirs are
at 71% of their maximum capacity, leading to a comfortable supply-demand balance for the next
few months until we get to the next wet season and establish the scenario for 2025. On the
demand side, ONS/EPE/CCEE recently revised their demand estimates up to 3.9% YoY in 2024—
a strong figure—, basically because 1Q24 was hotter than usual, leading to much higher
electricity consumption (cumulative demand growth of 6.9% from Jan-Mar 2024). Yet, we see
no problems in meeting such demand, as there is ~33% excess supply (firm capacity) in the
system. In any event, we believe the operator should be conservative to reduce risks related to
poor hydrology in the next wet season (2024/2025), especially if hydrology remains weak. If
hydrology repeats the poor 61% of the long-term average seen from December to March,
reservoirs would be below 20% of their maximum capacity by December 2024. If ONS maintains
a mild 5 GW of thermal power in operation, the situation in 2025 would be very risky, in our
view, even if hydrology improved to 80% in the 2025 summer.
How much more thermal power are we talking about? As we believe the ONS should adopt a
conservative operation mode after such a dry summer, in our base-line scenario, where we
assume hydrology at 71% of the long term average (average hydrology from October to April),
we believe 9 GW of average thermal generation would be required to guarantee a decent
cushion for the reservoirs in the 2024/2025 and 2025/2026 wet season (reservoirs at 40% of
their full capacity by December 2024 and December 2025). In a bear-case scenario, we estimate
that at least ~12 GW in thermal generation would be required to sustain reservoirs at reasonable
levels until YE 2024 (close to 40%). However, close to 14 GW would be required if hydrology
remains weak in 2025 (in a scenario of poor hydrology, if the 12 GW thermal generation is
maintained, reservoirs would deplete to 20% by YE 2025). Alternatively, if hydrology returns to
80% of the long-term average, the level of thermals operating could be as low as 4–5 GW for the
entire year, thus not pressuring spot prices. For the last five years, the average hydrology of the
system has reached a mild 73% (or up to 75% if we use the last ten years as a proxy). Thus, our
base-line scenario is more aligned with the figures from the recent past.
3
Figure 4: Hydrology data base (ENA, % per year)
106%
95% 93%
78% 82% 77%
2001
2002
2003
2004
86% 85%
2005
2006
101%
93%
84%
2007
2008
2009
2010
97%
83%
81%
2011
2012
75%
2013
2014
78%
69%
2015
2016
2017
77%
2018
84%
78%
68% 69% 67%
2019
2020
2021
2022
2023
Source: National Operator of the Electricity System (ONS) and Safra.
Figure 5: Reservoir scenarios
100%
80%
60%
40%
20%
abr-23
jul-23
out-23
jan-24
61% inflow (bear)
abr-24
jul-24
out-24
jan-25
abr-25
80% inflow (bull)
jul-25
out-25
71% inflow
Source: Safra estimates.
What about costs? Assuming that an average of 9 GW of thermal generation will be required to
meet demand in our base case, we reach a marginal cost of R$150–R$199 per MWh (including
Angra I and II). If generation surpasses 15 GW, this cost will increase to R$350 per MWh. On
November 14, when the system was operating 17 GW in thermal generation to meet a peak in
demand, this cost surpassed R$400 per MWh. Thermal generation was commonly used to meet
demand in past hot spring/summer seasons. Still, the game-changer for the current price
dynamics, in our view, is the introduction of hourly spot prices, which now allow customers (and
the market) to see the practical impacts of the operation’s requirements and reflect the higher
costs of the operation timelier. As a result, although there is technically excess capacity supply,
sometimes it is necessary to use more expensive sources to meet demand.
Figure 6: Thermal concentration chart per CVU – MW and R$ / MWh
405
325
283
210
171
9 GW
10 GW
12 GW
14 GW
above 17 GW
Source: National Operator of the Electricity System (ONS), Safra estimates.
4
Figure 7: Spot price volatility
900
Spot energy prices (R$/MWh)
800
700
600
500
400
300
200
100
Average
Max
Oct-23
Mar-24
May-23
Jul-22
Dec-22
Feb-22
Apr-21
Sep-21
Nov-20
Jan-20
Jun-20
Aug-19
Oct-18
Mar-19
May-18
Jul-17
Dec-17
Feb-17
Apr-16
Sep-16
Nov-15
Jan-15
Jun-15
Aug-14
Oct-13
Mar-14
May-13
Jul-12
Dec-12
Feb-12
Apr-11
Sep-11
Nov-10
Jan-10
Jun-10
0
Min
Source: National Operator of the Electricity System (ONS), Safra estimates.
How can we play this scenario?
We prefer ELET and ENEVA. After considering the possible hydrology scenarios for the 2024/2025
wet seasons, we expect more thermal dispatch starting in May/June (from 9 GW to 14 GW,
depending on hydrology, vs. 7 GW in 2023) and a potential increase in spot prices (reflecting the
higher dispatch, especially when demand starts to peak again) by 3Q24. As the spike in spot prices
will likely persist into 4Q24 and the outlook for hydrology in 2025 is uncertain, we believe prices
for energy contracts could be sustained at higher levels in the mid-term. We cannot affirm that
the prices of large contracts in effect from 2025–2028 will be supported at levels as high as R$150
per MWh (as indicated by certain trading platforms); however, we could see upward pressure on
shorter (and smaller) contracts because of hydrology. We see this scenario as likely positive not
only for Eletrobras but also for Eneva. We present a sensitivity analysis of EBITDA in a scenario of
higher thermal dispatch for Eneva (+5pps vs. our base case of 45% dispatch for 2024) and for
Eletrobras (additional R$10 per MWh to 2024/2025 prices). Both companies will benefit from the
above-mentioned scenario if weaker hydrology persists.
Figure 8: Sensitivity
GenCos
Eletrobras
Eneva
EBITDA 2024
1.0%
1.2%
EBITDA 2025
1.4%
1.1%
NPV/sh
0.20
0.10
Var/sh
0.4%
0.6%
Source: Safra estimates.
5
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DISCLOSURE ITEMS
Analysts
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1.
The securities analyst(s) involved in preparing this report are associated with individuals who work
for the issuers addressed herein.
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The securities analyst’s(s’) spouse(s) or partner(s) hold, either directly or indirectly, on their own
behalf or on behalf of third parties, the stocks and/or other securities discussed in this report.
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Emissão, Alfa Holdings S.A., Aliança Agrícola do Cerrado S.A., Alianza Trust Renda Imobiliária FII - 6ª
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Ecoagro I FIAGRO - 6ª Emissão, Ecoagro I Fiagro Imobiliário - 4ª emissão, Ecovias do Cerrado, Eletrobras,
Energisa S.A.,Energisa Tocantins - Distribuidora de Energia S.A., Engie Brasil Energia S.A., EQI Recebíveis
Imobiliários FII - 2ª Emissão , Equatorial Goiás Distribuidora de Energia S.A., Exes Araguaia Fiagro - 3ª
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Suzano S.A., Tellus Rio Bravo Renda Logística FII - 6ª Emissão, TG Ativo Real FII - 12ª Emissão,
7
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8
contrary to the opinions expressed by other business areas of Banco Safra as a result of their
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indicative of future results, and this report does not ensure or guarantee, either expressly or
implicitly, any possible future performance or any other aspect thereof. Safra Corretora and its
affiliated companies may not be held liable for any losses, either direct or indirect, arising from
the use of this report or its content. Upon using the content herein, investors undertake to
irrevocably and irreparably hold Safra Corretora and/or any of its affiliated companies harmless
from and against any claims, complaints and/or losses.
9.
Any opinions, estimates and projections must not be construed as a representation that the
matters referred to therein will occur. The prices and availability of financial instruments are
indicative only and subject to change without notice. The Research department will initiate,
update and cease coverage solely at the discretion of Banco Safra.
10. This report may not be reproduced or redistributed to any other person, wholly or in part, for
any purpose, without the prior written consent of Safra Corretora. Additional information
relative to the financial instruments discussed in this report is available upon request.
Additional disclaimer for reports distributed to:
USA:
Safra Securities LLC (“SSL”), a FINRA/SIPC member firm, is distributing this report in the United States
and accepts responsibility for the content of this report. SSL assumes responsibility for this research
for purposes of U.S. law. Any U.S. investor who receives this report and intends to trade any of the
securities addressed herein must do so through Safra Securities LLC at 546 5th Ave, 2nd Floor, New
York, NY.
UK AND EUROPEAN ECONOMIC AREA (EEA):
The communication of this report is not being made and has not been approved by an authorized
person for the purposes of Section 21 of the United Kingdom Financial Services and Markets Act
2000 (“FSMA 2000”). Accordingly, the report is not being distributed to, and must not be passed on
to, the general public in the United Kingdom and is to be circulated only to persons outside the
United Kingdom or to persons within the United Kingdom falling within the definition of investment
professionals (as defined in Article 19(5) of the FSMA 2000 (Financial Promotion) Order 2005
(“Order”)) or to other persons to whom it may be lawfully communicated in accordance with the
Order.
While all reasonable efforts have been made to ensure that the information contained herein is not
untrue or misleading at the time of its publication, no representation is made as to its accuracy or
completeness, and it should not be relied upon as such. Past performances are not a guarantee of
future performances. All opinions expressed in the present document reflect the current context
and are subject to change without notice.
OTHER COUNTRIES:
This report and the securities discussed herein may not be eligible for distribution or sale in all
countries or to certain categories of investors. In general, this report may be distributed only to
professional and institutional investors. By accessing this report, you confirm that you are aware of
the laws in your jurisdiction relating to the provision and sale of financial service products and
acknowledge that this material contains proprietary information and that you are to keep this
information confidential. Additionally, you confirm that you understand the risks related to the
financial instruments discussed herein. Due to international regulations, not all financial
services/instruments may be available to all clients.
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RATINGS CRITERIA
Safra Corretora assigns specific ratings to the shares traded in the securities and exchange markets
based on the following criteria:
Safra Corretora sets a required rate of return for each share, calculated based on the cost of capital
in the local securities market. The target price of a particular share represents the fair value of the
respective company calculated by the analyst as of a specific date, which is currently set as the end
of 2023 or 2024. Such fair value is calculated based on various metrics, among which the discounted
cash flow is the most used one, followed by the models of residual profit, discounted dividends and
sum of the parts. Sector multiples are used to compare companies within the same sector. The
expected return is equivalent to the percentage difference between the current price and the target
price of the share added to the estimated dividend return.
The stock guide is an investment guide for the shares under Safra’s coverage universe. It covers the
most representative sectors of B3 and presents the main indicators followed by investors, such as
target price; expected return; rating; estimates for net income and cash generation; and market
multiples, including P/E, EV/EBITDA and dividend yield. The sectors analyzed currently comprise
financial services; capital goods; consumption and retail; education; health care; utilities and
sanitation; transportation; and natural resources.
Shares rated as OUTPERFORM are expected to report above-average performance in the stock
exchange within the coverage group defined under the stock guide. Shares rated as UNDERPERFORM
are expected to report below-average performance in the stock exchange within the coverage group
defined under the stock guide. Shares expected to report performances between the two
aforementioned ranges are rated as NEUTRAL.
Our ratings are continuously reviewed according to such ranges whenever a meaningful change
occurs (initiation of coverage, change in a volatility scenario or related to the target price).
Nevertheless—and although the ratings are subject to constant administrative revisions—, the
expected returns can fluctuate beyond the ranges as a result of normal fluctuations in share prices,
without a necessary change in their ratings.
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