Brazilian Electrics - abraconee 2014/3 - JPMorgan... · Brazilian Electrics ... no longer perceived as a defensive sector ... The GSF factor may cause a R$21bn loss to hydro GenCos

Brazilian Electrics

Presentation to Abraconee

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investment decision.

Latin America Equity Research

November 2014

Latin American Utilities

Marcos Severine AC

(55-11) 4950-4297

[email protected]

Banco J.P. Morgan S.A.

Henrique Peretti

(55-11) 4950-4229

[email protected]

Banco J.P. Morgan S.A.

2

Team Members

Marcos Severine (Sector Head)

Marcos Severine has over 20 years of experience in financial markets, having dedicated

most of his career to the equity research as a Utilities analyst. He has been ranked several

times by Institutional Investor magazine (both Brazil and Latam). He joined J.P. Morgan in

October 2013. Prior to J.P. Morgan, Mr. Severine held senior positions in the investment

banking, project finance and equity research areas in important institutions in Brazil,

including Itaú BBA, Unibanco, Société Générale, BBA Creditanstalt and Sudameris (Head

of Equity Research). He has a BSc. In Business Administration and holds an MBA from

São Paulo Business School.

Henrique Peretti (Associate)

Henrique Peretti has 6 years’ experience in Equity Research in the Utilities sector. He re-

joined J.P. Morgan in October 2013 after spending the previous four years at UBS

covering the Utilities sector. Henrique was an intern at J.P. Morgan in 2008-2009 and part

of the team that top ranked Institutional Investor that year. Henrique holds a CNPI

certification, a BSc. In Economics from University of Campinas (July 2011) and a

Technical Degree in Computing from University of Campinas (July 2006).

3

OPPORTUNITIES IN THE ELECTRIC SECTOR 23

CHALLENGES 31

Page

INVESTMENT RETURNS 14

Agenda

DIAGNOSIS OF THE SECTOR 4

4

Diagnosis of the Sector

5

Regulatory Uncertainties Negatively Impact the Sector

Sep 11, 2012: The

Government unleashes

the Provisory Measure

MP579 to allow the

renewal of expiring

generation and

transmission concessions

and promote a ~20%

tariff cut. Negative

surprise for Cemig (São

Simão, Jaguara and

Miranda HPPs) and Cesp

(Três Irmãos HPP).

1 Oct 15, 2012:

Deadline for

companies exposed to

MP579 to file non-

binding intentions of

renewing

concessions. Cemig

was the only

abstention because

co. did not accept the

inclusion of the São

Simão, Jaguara and

Miranda in the

renewal package.

2 Nov 01, 2012: The

Government discloses

detailed concession-

renewal conditions

(R$30/MWh regulated

tariff for genCos, 70%

revenue cut for

transCos,

indemnifications for

non-depreciated

investments), again

disappointing market

expectations by a great

margin.

3 Nov 30, 2012:

Positive adjustments

in MP579 to

incentivize

companies to accept

the deal: (i) pre-2000

transCo assets

(RBSE) would also

be indemnified; (ii)

upward revision in

the indemnification

values for genCos,

mainly Cesp (Três

Irmãos).

4 Dec 4, 2012:

Deadline to file

binding-offer for

MP579 and

accept the deal.

All transCos

accept the deal.

All genCos

except

Eletrobras and

CEEE reject

the deal.

5

Jan 2013: An electricity supply crisis

unfolds due to poor hydrology, with

record-high thermoelectric generation.

Spot prices surpass R$400/MWh.

6

Mar 07, 2013: Decree #579 determines

that resources from the CDE regulatory

fund will be transferred to disCos to cover

high thermo dispatch costs.

7

May 2013 and onwards: Economic

growth disappoints, the tightening cycle is

resumed, and the Brazilian Real

deteriorates against the US dollar.

8

June: The City Hall raises bus fares in

São Paulo city by R$0.20/sh. Protests

emerge and spread throughout the

country. The population goes to the

streets claiming for lower corruption,

improvement in public services (health,

education, transportation). Popularity of

President Dilma Rousseff tumbles.

9

The past 2 years were marked by a sharp deterioration in investors’ confidence

Deterioration of Brazil macro conditions,

decelerating GDP growth, investors

withdraw money from EM

January-February 2014: Another energy

crisis emerges. Spot prices reach record

high of R$823/MWh in Feb. Rationing

risks become material

11

10

Source: Bloomberg and J.P. Morgan.

March to present: Vote intentions for

Dilma Rousseff decline, Government bail

out plan

12

BRAZIL

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September to present: Disappointment

with election outcome, FX devaluation,

Petrobras investigations.

13

6

How the market perceives the electric sector today

+ Subject to Government intervention, sensitive to political changes and the electoral process

+ Squeezed returns and profitability

+ Elevated execution and capex risks for new Greenfield projects

+ Rising sector and regulatory complexity

= Regulatory and legal instability, low earnings visibility, no longer perceived as a defensive sector

Investors are “Underweight” Brazilian Utilities

+ New entrants are of poorer quality and have low required rates of return (i.e. Chinese players, smaller local players)

+ “Impunity” for contract breaches / project delays (i.e. Bertin, Chesf’s transmission lines, Grupo Rede disCos)

+ Increasing delinquency in the commercialization chamber, rising sistemic risk

+ Power shortage risks / rationing risks / spot price volatility

+ Tariff reset risk

7 Source: J.P. Morgan.

#1 Risk Factor: Hydrology & Shortage Risk

Despite poor economic growth expected for 2014-15, we believe hydrology risks will remain

high in 2015 because: (i) reservoir levels are likely to start 2015 in a worst situation compared

to Dec-2014 (20%-25%); (ii) start-up delays in G & T will continue pressuring the electricity

supply; and (iii) weather institutes continue to point to a below avg. hydrology.

We foresee a thermal dispatch between 11.5-to-15.5 Avg. GW in 2015 in the best case

scenario, which is only ~10% below the average thermal dispatch registered in 2014 (14.5 Avg.

GW).

Full thermoelectric dispatch in 2014 and 2015 would trigger the need for strong tariff increases

at DisCos or a new round of heavy capitalizations from the Federal Government.

Spot Price is Likely to Remain at High Levels

The higher estimated spot price is a result of thermal generation output (mostly fuel oil and

diesel), in order to storage water in the reservoirs.

The new spot price calculation will likely culminate in a lower price volatility and in a higher

price, because would require a frequent thermal dispatch.

In the mid-to-long term, we foresee the spot price in a range between R$150-to-250/MWh.

We assume avg. spot price of R$450/MWh for 2015.

A fierce recovery of industrial electricity consumption or a poor hydrology could

trigger energy shortage or the need of full thermal dispatch in 2015. In this scenario

spot price could easily reach as high as R$600/MWh.

Shortage Risk in 2015 = HIGH

North (5% of National Capacity) South (7% of National Capacity)

Southeast/Center-West (70% of National Capacity) Northeast (18% of National Capacity)

BRAZIL

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Source for all four charts: ONS and J.P. Morgan

Rainfall is the new key catalyst for Brazilian utilities

0

20

40

60

80

100

J F M A M J J A S O N D

Range 2001 2013 Average Risk Aversion 2014

0

20

40

60

80

100

120


Range 2001 2013 Average Risk Aversion 2014

0

20

40

60

80

100

120


Range 2001 2013 Average 2014

0

20

40

60

80

100

120

J F M A M J J A S O N D Range 2001 2013 Average Risk Aversion 2014

8

Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14e Oct-14e Nov-14e Dec-14e 2014YE

Spot Price, R$/MWh (SE/CW) 490.00

GSF: Surplus / deficit (MW av g) (71)

Negativ e Ex posure, R$m (970) (23,581)

(3,618)

800

(2,113)

728.95 776.88

(6,564)

(3,493) (3,230)

(5,696)

709.53

(8,648)

(4,479)

592.54

(6,514)

(2,818)(1,522)

(1,981) (880) (3,097) (576) (2,842) (5,054)

(547) (529) (1,860) (346) (1,674)

378.22 412.65806.97822.83822.83822.83

#2 Risk Factor: Negative GSF

Generation Scaling Factor (GSF): Historical vs. JPMorgan Estimates

Source: ONS and J.P. Morgan estimates.

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Estimated Cost for GSF in 2014

Source: CCEE and J.P. Morgan estimates.

Source: CCEE and J.P. Morgan estimates.

The GSF factor may cause a R$21bn loss to hydro GenCos in 2014 alone

Generation Scaling Factor (GSF): Historical vs. JPMorgan Estimates

Hydro Generation vs. Contracted Output = GSF

35,000

40,000

45,000

50,000

55,000

60,000

65,000

Apr-0

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Jul-0

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Sep-

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n-10

Feb-

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ar-1

0Ap

r-10

May

-10

Jun-

10Ju

l-10

Aug-

10Se

p-10

Oct

-10

Nov

-10

Dec

-10

Jan-

11Fe

b-11

Mar

-11

Apr-1

1M

ay-1

1Ju

n-11

Jul-1

1Au

g-11

Sep-

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1N

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1D

ec-1

1Ja

n-12

Feb-

12M

ar-1

2Ap

r-12

May

-12

Jun-

12Ju

l-12

Aug-

12Se

p-12

Oct

-12

Nov

-12

Dec

-12

Jan-

13Fe

b-13

Mar

-13

Apr-1

3M

ay-1

3Ju

n-13

Jul-1

3Au

g-13

Sep-

13O

ct-1

3N

ov-1

3D

ec-1

3Ja

n-14

Feb-

14M

ar-1

4Ap

r-14

May

-14

Jun-

14Ju

l-14

Aug-

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p-14

eO

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Delivered Output (MW avg) Contracted Output (MW avg) Surplus Deficit

JPM

Estimates

Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14e Oct-14e Nov-14e Dec-14e

Deliv ered Output (MW av g) 51,821 50,727 46,744 45,182 41,609 40,317 40,397 39,241 41,860 42,341 43,840 44,279

Contracted Output (MW av g) 53,802 51,607 49,841 45,758 44,451 45,371 46,911 47,889 48,424 48,036 47,458 46,493

GSF: Surplus / deficit (MW av g) (1,981) (880) (3,097) (576) (2,842) (5,054) (6,514) (8,648) (6,564) (5,696) (3,618) (2,214)

GSF 96.3% 98.3% 93.8% 98.7% 93.6% 88.9% 86.1% 81.9% 86.4% 88.1% 92.4% 95.2%

9

#3 Risk Factor: Thermal Dispatch & Tariff Adjustment (Scenario A)

Source: JPMorgan estimates. BRAZIL

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Source: JP Morgan estimates.

How much is the 2014 power crisis is going to cost to Brazil? R$66bn

Estimated Cost with Thermoelectric Generation in 2014 and 2015

Estimated Impact of the Power Crisis on Brazilian Power Rates in 2014

JPMorgan’s Forecast: Brazilian Reservoirs

Source: JPMorgan estimates.


10

#3 Risk Factor: Thermal Dispatch & Tariff Adjustment (Scenario B)


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11

#3 Risk Factor: Thermal Dispatch & Tariff Adjustment (Scenario C)


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12

#4 Risk Factor: DisCos Regulatory Framework


BRAZIL

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Regulatory WACC proposed by Aneel is 7.34% and not 7.16%. Tariff Flags scheduled for Jan-15

DisCos Regulatory WACC: Historical vs. Preliminary Proposal

Tariff Flags Structure

ANEEL will launch next year a monthly pass-thru mechanism

to provide extra cash to disCos under poor hydrological

conditions.

Tested since June 2013 but becoming effective in January 2015,

ANEEL will allow DisCos to slightly increase consumer tariffs on a

monthly basis to raise extra cash to pay for thermo costs when

poor hydrological conditions prevail.

Our simulations indicate that tariff flags should cover most of the

thermo generation costs, translating into higher earnings

visibility/stability going forward.

Summary of Tariff Reset Cycles

13

Risk Perception within the Electric Sector

Progressive change in the energy matrix

Increased risk of negative GSF (generation deficits) and exposure to the spot market at volatile prices

Permanent dispatch of thermo capacity, with elevated marginal cost of operation

Distribution

Risk of Activity

Generation

Transmission

Until September 2012

Generation

Risk of Activity

Distribution

Transmission

After September 2012

Target of Government

intervention (Spot price

methodology, GSF, concession

renewal)

“Too big to fail”

Solid regulatory framework

Determining factors for a shift in risk perception

14

Investment Returns

15

Growth Challenges

Unbalanced risk-reward profile in GTD. The electric sector should require ~R$160bn capex from 2015-18

Generation Distribution Transmission Water Toll Roads Airports Ports Railroads

Conceding

Power

Federal

Government

Federal

Government

Federal

Government

State/Municipal

Government

Federal/State

Government

Federal

Government

Federal

Government

Federal

Government

Regulatory

Agency ANEEL ANEEL ANEEL

ARSESP (SP),

ARSAE (MG),

others

ANTT (Federal),

ARTESP (SP),

others

ANAC ANTAQ ANTT

Regulatory

Stability Medium Medium High Low High High Medium Medium

Political

Interference Medium Medium Low Medium Low Low Low Medium

Concession

period 20-30 years 30 years 30 years Usually 30 years 25-30 years 25-30 years 25 years 30 years

Returns for new

projects*

Real equity IRR,

levered

• 4-6% for

conventional

• 9-10% for

renewables

WACC

7.5% regulatory

WACC (2011-15

cycle)

Real equity IRR,

levered

4-7%

WACC

8.15% (Sabesp’s

1st cycle)

Real equity IRR,

levered

15% (regulated) -

18% (actual)

Real equity IRR,

levered

~12-14%

Real equity IRR,

levered

~16-17%

Real equity IRR,

levered

~18%

Growth

Prospects

• 6GW new

capacity p.a.

• Consolidation in

renewables

• Organic

• Consolidation

• New lines and

substations

• Reinforcement

• Consolidation

• Organic

• Expansion of

coverage

• Sewage

• New rounds of

concessions

• New rounds of

concessions

• New rounds of

concessions

• New rounds of

concessions

Risks associated • Hydrology (GSF)

• Execution

• Environment

• Tariff reset (3-5

years)

• Execution

• Environment

• Hydrology

• Tariff reset &

regulatory model

• Demand

• Execution

•Demand

• Execution

•Demand

• Execution

•Demand

• Execution

Risk-reward Unfavorable Unfavorable Unfavorable Fair Favorable Favorable Favorable Favorable

Comparison Among Regulated Businesses

16

The steep competition for infrastructure projects, in addition to growing environmental and

execution risks, have driven the returns of Greenfield projects to unappealing levels – not

only in transmission, but also in hydro generation projects.

The lack of bidders for some of the transmission projects tendered in 2012 and 2013

confirms our cautious view on the environment in Brazil, and indicates to us that the

government may have underestimated investors’ threshold for a “fair” return for each type

of infrastructure project, given the uncertainty and risks associated with the sector

We believe that this model needs a more attractive risk-reward to remain viable.

BRAZIL

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Source: ANEEL, Company data, regulatory filings and J.P. Morgan estimates based on the inputs.

Source: ANEEL and J.P. Morgan estimates based on the inputs. 34 % income tax break.

Growth Challenges

Comparative Analysis for Real Equity IRR (GTD)

Transmission Line Auctions: Growing Absence of Bids

Hypothetical Real Equity IRR per Concession Period (30-years vs. 60-years)

Diagnosis

Source: ANEEL, Company data, regulatory filings and J.P. Morgan estimates based on the inputs.

Contracted Capacity

Breakdown per Status and Project Type (Total: 39,555 MW)

Projects IRRs norrowed sharply over the past four years. Limited infrastructure requires IRR improvements

Source: ANEEL

Source: ANEEL

17

Greenfield Returns – Hydroelectric Projects BRAZIL

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Source: ANEEL, Companies, regulatory filings and J.P. Morgan estimates based on the inputs.


Wind Farm Projects Tendered Since 2009: Electricity Price (R$/MWh) vs. Real Equity IRR

Lack of fuel supply continuous to be the main problem for the development of thermal plants

1st Phase: 2009-10

Hydropower Projects Tendered Since 2005: Electricity Price (R$/MWh) vs. Real Equity IRR

2nd Phase: 2011 3rd Phase: 2012 4th Phase: 2013

18

LT Power Prices: Clear Upward Trend


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Source: Compass and JPMorgan estimates.

Structural changes are driving up power prices: R$150/MWh the new bottom

Power Price Curve for Conventional Energy (R$/MWh)

Estimated Marginal Cost of Expansion by Energy Source

Cost of the Power Crisis

Source: Compass and JPMorgan estimates.

Power Price Curve for Renewable Energy (R$/MWh)

Higher Marginal Cost of Operation (MCO): This upward trend for

power prices is partially explained by the growing need for

thermoelectric dispatch to offset the historical lack of investments in

new water dams (the real reason for the recent hike in hydrology risk)

and the high marginal cost of operation, which unfortunately is

currently based on fuel oil and diesel, as demonstrated by the ongoing

spot prices.

Increasing Marginal Cost of Expansion (MCE): The rebalancing of

IRRs to provide realistic risk-reward ratios will depend on the elevation

of ceiling prices for new genCo projects. This puts further pressure on

power prices in the short-to-mid term. Whoever the new president, we

believe their main focus will be to foster investments in new power

generation facilities to enlarge electricity supply and restore economic

growth.

Long-term power prices hovering around R$150/MWh. All

companies that we have spoken to recently have, without exception,

indicated that long-term power prices are stabilizing above

R$150/MWh in 2017-18 and onwards. This poses substantial upside

risk to our models and valuations, as we assume R$135/MWh.

JPMorgan’s Marginal Cost of Expansion in Brazil

Fair Value Sensitivity to

+R$10/MWh in Long-Term

Power Prices

19

Greenfield Returns – Hydroelectric Projects BRAZIL

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Hydropower Projects: Project Valuation & Key Assumptions

(1) All electricity prices as of December 2013.


20

Greenfield Returns – Wind Projects BRAZIL

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Wind Power Projects: Project Valuation & Key Assumptions


21

Greenfield Returns – Transmission Projects BRAZIL

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Real Equity IRR for Transmission Line Projects Tendered Since 2010

Transmission Projects: RAP vs. Real Equity IRR

22

Greenfield Returns – Transmission Projects BRAZIL

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Transmission Line Projects: Project Valuation & Key Assumptions

Source: Source: ANEEL, Companies, regulatory filings and J.P. Morgan estimates based on the inputs.

23

Opportunities in the Electric Sector

24

How Do We See the Electric Sector: Growth Segment

Electricity Consumption by Class and per Region

+ Brazil is still an emerging economy

= Growth Segment

+ Income Growth + Credit + Light for All + Family Grant (Bolsa Família) = Continued Growth in Residential Consumption

+ Expansion of electric infrastructure is paramount to support long term economic growth and unlock Brazil’s potential GDP

-15.0%

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0% Ja

n-09

F

eb-0

9 M

ar-0

9 A

pr-0

9 M

ay-0

9 Ju

n-09

Ju

l-09

Aug

-09

Sep

-09

Oct

-09

Nov

-09

Dec

-09

Jan-

10

Feb

-10

Mar

-10

Apr

-10

May

-10

Jun-

10

Jul-1

0 A

ug-1

0 S

ep-1

0 O

ct-1

0 N

ov-1

0 D

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0 Ja

n-11

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1 M

ar-1

1 A

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1 M

ay-1

1 Ju

n-11

Ju

l-11

Aug

-11

Sep

-11

Oct

-11

Nov

-11

Dec

-11

Jan-

12

Feb

-12

Mar

-12

Apr

-12

May

-12

Jun-

12

Jul-1

2 A

ug-1

2 S

ep-1

2 O

ct-1

2 N

ov-1

2 D

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2 Ja

n-13

F

eb-1

3 M

ar-1

3 A

pr-1

3 M

ay-1

3 Ju

n-13

Ju

l-13

Aug

-13

Sep

-13

Oct

-13

Nov

-13

Dec

-13

Jan-

14

Feb

-14

Mar

-14

Apr

-14

May

-14

Jun-

14

Residential Industrial Commercial Others

Source: Energy Research Company (EPE).

2.0%

8.5%

11.8

%

8.4%

7.2%

6.0%

4.4%

7.1%

6.0%

9.8%

5.3%

0.8%

0.6%

-1.8

%

2.5%

6.2%

10.6

%

9.4%

8.0%

3.9%

10.2

%

13.6

%

7.6%

5.6%

0.4%

-0.4

%

3.1%

0.9%

6.4%

6.3%

2.8%

3.4%

7.0%

5.8%

5.6%

5.8%

2.1%

-1.0

%

3.0%

9.0%

7.2%

6.9%

3.8%

6.9%

5.6%

7.1%

6.3%

5.5%

4.3%

3.3%

6.2%

0.9%

3.4%

5.3%

4.6%

11.1

%

3.3%

3.2%

6.8%

6.3%

5.4%

4.3%

3.8%

5.4%

8.5%

10.8

%

11.5

%

8.9%

7.4%

8.4%

6.8%

6.2%

7.5%

7.1%

5.5%

6.6%

-4.5%

0.5%

5.5%

10.5%

15.5%

4Q09 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14

North Northeast South MidWest

25

Greenfield Opportunities

The Brazilian electric sector should require ~R$160bn capex in the next four years, as per the Decenal Plan

Renewables Conventional Transmission

Planned capacity to

contract • Wind: 6,700 MW

• Biomass: 4,100 MW

• Small hydro plants: 1,400 MW

• Total: 12,200 MW

• Thermo: 1,500 MW (Coal & LNG)

• Hydro: 19,400 MW

• Total: 20,900 MW

• 13,300km of new lines and 39 new substations

• Tapajós transmission lines & connections

Planned capex to contract • R$ 50 billion • Thermo: R$ 4 billion

• Hydro: R$ 91 billion

• Total: R$ 95 billion

• Transmission lines: R$ 10 billion

• Substations: R$ 8 billion

• Total: R$ 18 billion

Opportunities • Free market: spot market volatility can foster

clients to sign long-term bilateral contracts

• Possibility of auctions per regions / source

• São Luiz do Tapajós HPP: 8.0 GW (R$30bn)

• Jatobá HPP: 2.3 GW (R$10bn)

• Possibility of auctions per regions / source

• Self production shared with free market

• Auctions for basic grid capacity

• Auctions for ICGs (connection of wind farms)

• Belo Monte transmission project (second dipole)

Comments • Wind is the most competitive renewable source

• Increased requirements for suppliers: mandatory

production of towers, machines and blades in Brazil

• BNDES requirements for manufacturers and

potential incentives to other sources could harm

competitiveness

• Gas-fired generation highly dependent on supply

from Petrobras

• Hydro expansion into sensitive regions

environmental wise

• Low attractiveness: returns and profitability did not

keep up with increasing construction costs

• Introduction of new technology: Belo Monte

transmission line in 800 kV

Summary of the Greenfield Projects (Generation & Transmission)

26

Greenfield Opportunities in Renewables

Biomass Small hydro Wind Solar

Strengths • Up to 2018, 4,100 MW of new biomass

capacity should be contracted

• Beyond sugar cane bagasse, projects

fueled by woodchips are economically

viable

• Increased flexibility and visibility in the

agricultural phase are important to raise

profitability in the free market

• Up to 2018, 1,400 MW of new small

hydro capacity should be contracted

• BNDES extended loan amortization

period to 20 years, facilitating new

projects

• Up to 2018, 6,700 MW of new small

hydro capacity should be contracted

• The confirmation of higher load

factors, associated to scale gains,

turned wind the most competitive source

among all renewables

• Big potential in Brazil

• First solar power auction in Brazil took

place in 2013

• Low installation and maintenance

complexity facilitates access to remote

areas

• In the future, distribution generation

can be exploited

Challenges • Mostly concentrated in sugar cane

bagasse, the main challenge is securing

fuel supply on a consistent basis,

aligning the interests between

generators and the sugar industry

• Achieve isonomy of funding conditions

and access tax benefits available in the

regulated market, such as the REIDE




• Seek ICMS exemption for the

construction supply chain, as granted

today to wind

• Accelerate ANEEL’s approval

procedures

• Low prices has restricted the

expansion. Higher cap price

(~R$160/MWh) would unlock growth.




• Guarantee connection to the basic grid

through new transmission auctions

• Volatile electricity generation due to

weather changes and nighttime, need to

storage

• Storing solar power isn’t efficient today

• Fierce competition with wind power

due to its high production costs

• Low load factors (~25%)

Comparison Among Renewable Businesses (Biomass, Small Hydro, Wind and Solar)

Renewables tend to dominate the expansion in the near future

27

Greenfield Opportunities in Conventional Generation

Hydro Gas Coal/Oil

Strengths • Up to 2018, 19,400 MW of new hydro capacity

should be contracted

• Regulated market is priority

• Up to 2018, 1,500 MW of new gas-fired capacity

should be contracted

• More competitive, less pollutant and enjoys better

funding conditions compared to coal or oil

• Not included in the Decenal Plan, but there are a

few coal projects under study

Challenges • Hydro expansion into sensitive regions

environmental wise

• Post Provisional Measure 579, investment appetite

from big players was reduced

•Fierce competition from Chinese players should

squeeze returns

• A great part of capex is imported, hence cannot

enjoy BNDES funding

• Highly dependent on supply from Petrobras

• Petrobras still present in the transportation or

pipeline O&M

• Only the most expensive technologies (less

pollutant) are eligible for BNDES funding

• A great part of capex is imported, hence cannot

enjoy BNDES funding

• More expensive credit line within BNDES, with

reduced leverage and shorter amortization period

(14 years)

Comparison Among Renewable Businesses (Biomass, Small Hydro, Wind and Solar)

A more restrict environmental agenda would restrict the development of conventional sources

28

Greenfield Opportunities in Hydro Generation

Expected Auction Project River Capacity

(MW)

State Feasibility Studies

A-5 2014 Ribeiro Gonçalves Parnaíba 113 PI/MA Chesf/CNEC/Queiroz Galvão/Energimp

A-5 2014 Cachoeira Parnaíba 63 MA Chesf/CNEC/Queiroz Galvão/Energimp

A-5 2014 Itaocara I Paraíba do Sul 145 RJ Light

A-5 2015 São Luiz do Tapajós Tapajós 8,133 PA

A-5 2015 Davinópolis Parnaíba 74 MG/GO Cemig/Neoenergia

A-5 2015 Foz Piquiri Piquiri 96 PR

A-5 2015 Paranhos Chopim 63 PR Foz do Chopim

A-5 2015 Ercilândia Piquiri 97 PR BE/Desenvix/Copel

A-5 2016 Água Limpa Das Mortes 380 MT PCE/Enercamp/Tech/Furnas/Alstom/AG/Enorte

A-5 2016 Jatobá Tapajós 2,336 PA

A-5 2016 Comissário Piquiri 140 PR BE/Desenvix/Copel

A-5 2016 Telêmaco Borba Tibagi 109 PR Promon

A-5 2016 Apertados Piquiri 139 PR BE/Desenvix/Copel

A-5 2016 Tabajara Jiparaná 350 RO

A-5 2017 Castanheira Arinos 192 MT

A-5 2017 Bem Querer Branco 709 RR

A-5 2017 Itapiranga Uruguai 721 SC/RS

A-5 2018 Salto Augusto Baixo Juruena 1,461 MT

A-5 2018 São Simão Alto Juruena 3,509 MT/AM

A-5 2018 Marabá Tocantins 2,160 PA/MA Eletronorte/Camargo

A-5 2018 Torixéu Araguaia 408 MT/GO

Other

Project Location (MW)

Project Size (MW)

Hydro Power Projects Currently Under Study

29

Ongoing Issues for New Greenfield Thermo Generation

Diesel Fuel Oil Coal Natural Gas

Fuel Supply • Petrobras (BR Distribuidora) is the main supplier

• Due to severe penalties for non delivery, long-term supply agreements are

inexistent

• Trading is an alternative (Tramp oil – WFS)

• International market

• Self production

• Petrobras controls supply and

prices

• Self production (i.e. Parnaíba)

• International market, subject to

presence of LNG conversion

terminals

Location • Project must have access to supply infrastructure and logistics

Contract model of main

suppliers

• EPS Turn Key Lump Sum or EP+C Turn Key Lump Sum with Owners Engineering

• Track record and set of guarantees

Environmental Issues • Adherence to standard rates of emission of greenhouse gases (Nox, Sox e CO2), in line with Ibama and IFC best practices

• Clean Coal Technology required for coal-fired thermo projects

FX risks • Hedge is a necessity given that ~50% of capex is imported

Lack of fuel supply continuous to be the main problem for the development of thermal plants

Fuel Supply for Thermoelectric Plants

30

Placement of Thermo Capacity in the Regulated Auctions

Evolution of the placement of projects by source (MW average)

Evolution of the placement of new thermo projects (MW average) Thermo generation by source

Thermo Hydro SHP Wind

Biomass Diesel Process Gas Natural Gas Fuel Oil

31

Challenges

32

Energy Balance: Electricity Supply

Expansion Model Favors Low Cost Sources

Source: ONS and J.P. Morgan

Contracted Expansion (AVG. MW of Assured Energy)

Source: Energy Research Entity (EPE) and J.P. Morgan Source: ONS and J.P. Morgan

Supply & Demand Estimates (Avg. MW)

Source: J.P. Morgan and EPE

The Brazilian energy matrix has changed considerably over the past 10 years,

though continue to be predominantly hydro (76% of total assured energy).

The current expansion model clearly favors low cost power sources like wind farms.

As a result wind farms will respond for 6% of Brazil’s assured energy in 2018.

The decision to build only run-of-the-river hydro power plants and wind farms will

certainly culminate in a higher thermoelectric dispatch throughout the upcoming

years, boosting system’s marginal cost of operation.

Energy Matrix: Evolution Energy Matrix : Existent + Contracted Expansion

33

Project Delays are Threats

4,969

7,267

4,926 4,014

5,087

611 -

262

3,777

1,710

784

2,002

50

30

4,057

5,231

6,636

4,798

7,088

661

10

4,087

2014 2015 2016 2017 2018 2019 2020 2021

No Impediments Some Restrictions Severe Restrictions

11,044

26,884

8,615

4,057

No Impediments

Some Restrictions

Severe Restrictions

1,794 1,693 198 303

2,110

-

2,976

1,531

4,640

581 140

107

30

106

1,906

4,711

5,857

4,355

4,872

631 -

1,005

5,231

6,636

4,798

7,088

661

10

4,087

2014 2015 2016 2017 2018 2019 2020 2021

Thermal Wind Hydro

11,044

4,041 3,237

19,605

2,067 3,821

2,727

2,976 76

1,005

Thermal Wind Hydro

No Impediments Some Restrictions Severe Restrictions

Angra 3: 1,350 MW

Belo Monte: 11,233 MW

Sinop: 400 MW

Installed Contracted Capacity per Year

Installed Capacity per Project Type (TOTAL: 39,555 MW) Breakdown per Status and Project Type (TOTAL: 39,555 MW)

Installed Capacity per Status (TOTAL: 39,555 MW)

34

Shortage Risk in 2014 = LOW

Higher rationing risks in 2014, 2015 and 2018: Early this year, Brazilian water

reservoirs reached their worst levels since the 2001 rationing, pushing the

Government to dispatch nearly all the 14GW avg. of available thermo capacity in

order to avoid the decree of another rationing. We think Brazil’s thermo capacity

should operate at peak so as to guarantee energy supply in next year’s large-scale

events, implying higher energy costs to end-users.

The regularization capacity of our reservoirs is decreasing: FIRJAN Association

estimates that the regularization capacity of Brazilian water reservoirs will drop from

4.91 months today to 3.35 months in 2021, as demand grows at 4.1% p.a.

Given strict environmental requirements from IBAMA (environmental agency) all

HPPs tendered since 2005 located in the Amazon region are run-of-the-river type,

without reservoirs and, hence, with no regularization capacity.

Rationing Risks

Risk of Energy Deficit in %

Source: Decenal Plan 2022 (Energy Research Entity).

Water Storage Capacity

Water Storage Capacity vs. Demand Growth Water Regularization Capacity (in months)

Source: FIRJAN (Rio de Janeiro Industry Federation)

Source: Decenal Plan 2022 (Energy Research Entity).

35

Energy Balance: Supply & Demand

A Comfortable Situation for EPE

A Critical Situation for EPE

A Challenging Situation for EPE

Source: Energy Research Entity (EPE) and J.P. Morgan


Avg. GW


Avg. GW

Avg. GW

This scenario encompass a recurrent GDP growth rate of 2.6% YoY.

ONS (System Operator) would likely keep thermal dispatch ranging between 8-to-10

Avg. GW throughout the upcoming 3-years in order to avoid electricity shortage

risk. This would cost ~BRL 10 billion per year.

EPE would contract ~3 Avg. GW and ~4 Avg. GW of assured energy in 2014 and

2015 A-5 auctions.

Construction delays (Belo Monte, Angra III, etc) would raise considerably the

electricity shortage risk in 2018.


ONS (System Operator) would turn off all costly thermal plants. Thermal dispatch

would be restrict to the inflexibility (level ~5.1 avg. GW), starting in 2015. This would

represent a cost cut of ~BRL 7 billion per year.

No need to contract new capacity in 2014 and 2015 A-5 auctions.

Construction delays (Belo Monte, Angra III, etc) would not have a material impact in

the electricity shortage risk.


ONS (System Operator) would have to dispatch all thermal power plants available,

including the costly one (fuel-oil and diesel power plants). Thermal dispatch would

range between 14-to-16 Avg. GW in a recurrent basis up to 2018. This would cost

~BRL 25 billion per year.

EPE would have contract ~6 Avg. GW of assured energy in 2014-15. auctions.

Construction delays (Belo Monte, Angra III, etc) would raise considerably the

electricity shortage risk in 2016.

Bull Case Scenario: CAGR +5.5% (2013-22)

Bear Case Scenario: CAGR +2.5% (2013-22)

Base Case Scenario: CAGR +4.1% (2013-22)

36

Long Term Power Prices

Electricity Price Formation: Key Variables for Long-Term Power Prices

0

75

150

225

300

375

450

525

600

675

750

825

900

975

1,050

1,125

1,200

0

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

Fu

el C

ost

(BR

L / M

Wh)

Inst

alle

d C

apac

ity

-MW

Residues Nuclear Natural-Gas LNG Coal Fuel Oil Diesel Biomass Marg.Cost of Operation

10.0 Avg. G

W

15.0 Avg. G

W

Inflex. ~6.4 A

vg. G

W (12m

Fw

d)

0.0% 5.0% 10.0% 15.0% 20.0% 25.0% 30.0% 35.0% 40.0% 45.0% 50.0% 55.0% 60.0% 65.0% 70.0% 75.0% 80.0% 85.0% 90.0% 95.0% 100.0%

Thermo-powered generation park's implicit Load Factor

Thermal Plants: Marginal Cost of Operation (R$/MWh)

Average Thermal Generation Cost (R$/MWh) Historical Thermoelectric Generation in Brazil’s National Grid (Avg. GW)

0

2

4

6

8

10

12

14

16

18


2008 2009 2010 2011 2012 2013 2014 9-Year avg

Source: CCEE and ONS Source: CCEE

37

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