June 2014

Brazil:Country of the future or has its time come for natural gas?

Ieda Gomes

OIES PAPER: NG 88

OIES Senior Visiting Research Fellow

Copyright © 2014
Oxford Institute for Energy Studies(Registered Charity, No. 286084)

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permission from the copyright holder, provided acknowledgment of the source is made. No use of thispublication may be made for resale or for any other commercial purpose whatsoever without priorpermission in writing from the Oxford Institute for Energy Studies.

ISBN 978-1-78467-004-7

i

Acknowledgements
The author would like to thank all those who provided valuable insights and information during the
preparation of this paper, particularly my colleagues at the Infrastructure Department of the Sao PauloFederation of Industries, ABEGAS Executive President Augusto Salomon, Maria D’Assuncao Costaof the Brazilian Institute of Energy Law and Luiz Minitti Amoroso of Eletricidade do Brasil. The author
also would like to thank members of the Oxford Institute for Energy Studies, especially Howard
Rogers for reviewing and contributing to this paper and Kate Teasdale and Jan Cleave for the final
formatting and editing.

iiAbout the Author
Ieda Gomes is Senior Visiting Research Fellow at the Oxford Institute for Energy Studies. Her areasof expertise include natural gas and LNG market fundamentals as well as energy pricing, policy andregulation particularly in developing countries in South Asia, the Middle East, Africa and Latin
America. Ieda’s career in the gas and energy industry spans more than 30 years. She worked fornearly 14 years at BP plc as Vice President for new ventures and market development on several
international assignments and for 19 years at the largest gas distribution company in Brazil, Comgas.
She has been a key participant and shaper of events in Brazil’s gas industry – from the introduction ofnatural gas supplies in Sao Paulo to the negotiating and signing of the domestic and Bolivian gas
supply agreements, the privatization of Comgas and the establishment of the Brazilian Association of
Gas Distribution Companies (ABEGAS). Ieda is based in the UK and sits on the board and advisory
council of various companies and associations. She writes a bimonthly column for Brazil Energia.
Ieda holds a BSc in chemical engineering and an MSc in energy and environmental engineering.

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Preface
I suspect I am amongst a significant majority of people who were not aware, prior to reading thispaper that Brazil’s natural gas industry dates back as far as 1851. In the past few years Brazil, hasreceived much attention in macro-economic circles as one of the high growth BRICS countries. Its
performance has waned of late, apparently due to lack of internal reforms and infrastructure
bottlenecks, and as this paper demonstrates, these factors certainly ‘read across’ to Brazil’s natural
gas sector.
Initial excitement in the wake of Brazil’s offshore pre-salt hydrocarbon discoveries in 2007 and 2008
raised the prospect of the country becoming an LNG exporter. Following further appraisal and market
developments this prospect has receded and managing the country’s gas balance has been further
complicated by low rainfall (and hence hydro availability) in recent years. For these reasons Brazil
has had to import LNG at Asian-equivalent spot prices to meet requirements which are difficult toforecast.
In short Brazil is a market which any observer of the natural gas world is required to develop aworking understanding of: in view of its scale, its potential for growth and its impact on the global LNG
market. However, its circumstances and specificities make such an understanding extremely difficult
without expert assistance.
In this regard who better to author this paper than Ieda Gomes, who spent 19 years of her career inBrazil’s largest gas distribution company and who was a key participant and instigator of sector
development and modernisation? I am extremely grateful to Ieda for her comprehensive, lucid andperceptive assessment of the evolution, status and future challenges of Brazil’s gas sector. The OIESNatural Gas Programme is particularly committed to undertaking research which advances
understanding of the important growth markets which impact tomorrow’s gas world, and I am
delighted that her paper admirably fulfils this aim.

Howard Rogers
OxfordJune 2014

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Contents
Acknowledgements ................................................................................................................................. i
About the Author ....................................................................................................................................iii
Preface ................................................................................................................................................. iv
Tables ................................................................................................................................................... vi
Figures .................................................................................................................................................. vi
1. Introduction ...................................................................................................................................... 1
2. Brazil in Context .............................................................................................................................. 2
2.1 Brazil’s energy matrix is becoming less green .......................................................................... 4
2.2 The Brazilian gas industry: Genesis and evolution ................................................................... 7
3. Key Industry Players and Regulation .............................................................................................. 9
3.1 Brazil’s E&P fiscal regime ......................................................................................................... 9
3.2 Natural gas regulation ............................................................................................................. 11
4. Brazil’s Gas Reserves: Significant Growth .................................................................................... 14
4.1 Domestic gas production ......................................................................................................... 16
4.1.1 Brazil’s pre-salt hopes ..................................................................................................... 18
4.2 Natural gas balance ................................................................................................................ 20
4.3 Gas demand by sector ............................................................................................................ 20
4.4 Brazil’s power sector ............................................................................................................... 24
4.5 Stored energy vs LNG imports ................................................................................................ 28
4.6 Gas Demand – LDCs franchise areas .................................................................................... 29
4.6.1 Residential demand ........................................................................................................ 30
4.6.2 NGVs ............................................................................................................................... 30
4.6.3 Industrial demand............................................................................................................ 31
4.7 Natural gas infrastructure: The challenges of a continental country ....................................... 33
4.7.1 The Bolivia-Brazil pipeline: Game changer ..................................................................... 34
4.7.2 LNG infrastructure: Another game changer? .................................................................. 35
4.8 Natural gas prices ................................................................................................................... 36
5. Gas Production Outlook for the Period 2020–30 .......................................................................... 42
5.1 Natural gas supply-demand outlook ........................................................................................ 44
5.2 Spot LNG: Expensive alternative for power generation .......................................................... 48
6. Brazil and South America: Markets and Connectivity ................................................................... 51
7. Can Unconventional Gas Play a Role in Brazil? ........................................................................... 56
8. Conclusions and Insights .............................................................................................................. 58
Glossary ............................................................................................................................................... 62
Bibliography ......................................................................................................................................... 64
Company and News Websites ............................................................................................................. 66v

Tables
Table 1: Blocks granted to Petrobras via transfer of rights ................................................................... 10
Table 2: Key players in Brazil's gas value chain ................................................................................... 13
Table 3: Gas production in Brazil by producer, 2013 ............................................................................ 18
Table 4: Stored Energy in Brazil's hydropower reservoirs*................................................................... 26
Table 5: Natural gas regional transportation and LNG infrastructure in Brazil (January 2014) ............ 33
Table 6: Petrobras’ LNG import capacity .............................................................................................. 36
Table 7: Gas-fired power plants owned by Petrobras as of December 2013 ....................................... 38
Table 8: Natural gas and fuel prices to end-users ................................................................................ 40
Table 9: Brazil’s LNG imports and re-exports ....................................................................................... 49
Table 10 : Gas sourcing options: Costs and savings (LNG imports vs domestic gas) ......................... 50
Table 11: LNG import capacity of the Southern Cone, 2016 ................................................................ 55
Table 12: Technically recoverable shale gas resources ....................................................................... 56
Table 13: Breakdown of Brazil’s potential shale gas resources by basin ............................................. 57

FiguresFigure 1: Brazil’s GDP growth, 1998–2013............................................................................................. 3
Figure 2: Composition of Brazil's GDP, 2013 ........................................................................................ 4
Figure 3: Brazil’s primary energy mix, 2012 ............................................................................................ 4
Figure 4: Comparative energy and economic indicators, 2011–12 ........................................................ 6
Figure 5: Brazil's power generation capacity, 2012 ................................................................................ 6
Figure 6: Planned investment in Brazil by sector, 2013–16.................................................................... 7
Figure 7: Evolution of Brazil’s oil & gas legislation ............................................................................... 11
Figure 8: Geographical location of LDCs in Brazil ................................................................................ 13
Figure 9: Evolution of gas reserves in South & Central America ......................................................... 15
Figure 10: Gas reserves of Brazil compared with other selected gas producers, 2012 ....................... 15
Figure 11: Brazil's E&P sedimentary basins ......................................................................................... 16
Figure 12: Breakdown of Brazil's gas production, 2013 ........................................................................ 17
Figure 13: Brazil’s domestic natural gas production vs available supply .............................................. 17
Figure 14: Breakdown of Brazilian gas production by company (MMm 3/d) .......................................... 18
Figure 15: Pre-salt clusters in southeast Brazil..................................................................................... 19
Figure 16: Natural gas balance in Brazil, 2013 ..................................................................................... 20
Figure 17: Brazilian gas consumption by segment, 2011 ..................................................................... 21
Figure 18: Brazilian gas consumption by segment, 2013 ..................................................................... 21
Figure 19: Evolution of Brazilian gas consumption by sector ............................................................... 22
Figure 20: Natural gas consumption in Brazil’s power and industrial sectors ...................................... 22
Figure 21: Supply profile of Brazil’s gas-fired power plants, 2009–2013 .............................................. 23
Figure 22: Brazil’s regional power transmission system ....................................................................... 24
Figure 23: Brazil’s hydropower reservoirs - Historical patterns ............................................................ 25
Figure 24: Storage capacity of Brazil’s hydropower reservoirs by region ............................................. 25
Figure 25: Share of hydro-power in Brazil’s total power generation ..................................................... 26
Figure 26: Brazil’s thermal power generation (gas, oil and coal), 2013 vs 2012 .................................. 27
Figure 27: Outlook for Brazil’s gas-fired power plants .......................................................................... 27
Figure 28: Breakdown of Brazil’s LNG imports by source* ................................................................... 29
Figure 29: LDC gas sales, 2013 vs 2009 .............................................................................................. 29
Figure 30: Breakdown of residential consumers by region ................................................................... 30
Figure 31: Historical growth of NGVs in Brazil ...................................................................................... 31
Figure 32: Breakdown of industrial energy consumption, 2012 ............................................................ 32
Figure 33: Natural gas demand in industry – actual and forecast ....................................................... 32
Figure 34: Evolution of Brazil's gas transportation and distribution infrastructure ................................ 33
Figure 35: Commercial structure of the Bolivia-Brazil pipeline project ................................................. 35vi

Figure 36: Natural gas pricing structure and competencies in Brazil ................................................... 37
Figure 37: Wholesale gas prices in Brazil compared with international prices ..................................... 39
Figure 38: Natural gas prices in Brazil: Wholesale vs end-user (December 2013) .............................. 39
Figure 39: Increasing gap between power and gas (domestic and imported) prices ........................... 40
Figure 40: Breakdown of fuel consumption by Brazilian industrial segment, 2012 vs 2003 ................. 41
Figure 41: Comparison of natural gas end-user prices, Q1/2012 ......................................................... 42
Figure 42: Petrobras investment plan for 2011–15 ($ bn) .................................................................... 42
Figure 43: Petrobras production forecasts, 2014 vs 2011 plan ............................................................ 44
Figure 44: Evolution of domestic and imported gas supply in Brazil .................................................... 45
Figure 45: Sources of natural gas supply in Brazil, 2013 vs 2011 ........................................................ 45
Figure 46: GDP vs gas demand growth in Brazil, 2001–13 .................................................................. 46
Figure 47: Petrobras scenarios for natural gas supply and demand .................................................... 46
Figure 48: Natural gas supply-demand outlook in Brazil, 2013–25 ...................................................... 48
Figure 49: Average DES prices of LNG as of November 2013 ............................................................ 49
Figure 50: Brazil’s LNG import volumes and LNG FOB prices ............................................................ 50
Figure 51: Gas infrastructure and interconnectivity in the Southern Cone ........................................... 52
Figure 52: The Bolivia–Brazil Pipeline .................................................................................................. 53
Figure 53: Bolivia’s gas balance, 2013 ................................................................................................. 53
Figure 54: Argentina’s gas balance, 2013 ............................................................................................ 54
Figure 55: Evolution of natural gas production in Argentina, Brazil and Bolivia ................................... 54
Figure 56: Natural gas imports and exports in the Southern Cone (Bcma), 2013 ................................ 56
Figure 57: Overview of onshore unconventional gas blocks in Brazil‘s November 2013 tender .......... 58
Figure 58: Evolution of Brazil and Argentina’s natural gas imports ...................................................... 59vii

1. Introduction
Natural gas plays a relatively modest role in Brazil’s energy mix, accounting for less than 12% of thedomestic energy supply and 7.2% of the country’s final energy consumption 1 . This is due to thepredominant role of hydroelectricity in Brazil’s power generation, the country’s relatively undeveloped
gas infrastructure, government subsidies for LPG and the monopoly of Petrobras, which contributes tobalancing the supply of competing fuels – natural gas and low-value fuel oil.
In 2013 final gas sales totalled 32.7 Bcma, including 4.6 Bcma consumed by Petrobras refineries and
12 Bcma used in E&P operations and flaring. Brazil is a net gas importer: 12 Bcma was imported from
Bolivia in 2013 and 5.3 Bcma of LNG. The country has three floating LNG import terminals – oneeach in the states of Ceara (2.5 Bcma), Rio de Janeiro (7.7 Bcma) and Bahia (5.1 Bcma), all owned
and operated by Petrobras. The dry season in 2012 and 2013 prompted Petrobras to source LNG tomeet the needs of its gas-fired power plants. Petrobras is also currently building its credentials as an
LNG trader; in 2013 it bought nearly 100 cargoes of LNG, around 4.4 mtpa, of which nearly 80
cargoes were imported into Brazil, several traded externally and one half of one cargo re-exported toArgentina in a gas swap with a Brazilian power plant on the Argentine border. The continuation of thedry season combined with the need to ‘keep the lights on’ during the World Cup in June/July 2014
and major elections in October will mean that similar amounts of LNG will be imported in 2014.
After nearly 40 years of state monopoly, the government began to gradually liberalise the oil and gas
sector. In 1999 the National Petroleum Agency (ANP) launched the first E&P tenders which received
bids from local and international players. As of 2013, there were more than 70 private companies
active in the upstream sector, either operating alone or partnering with Petrobras; of these, 29 are
already producing small volumes of natural gas, most of which is sold to Petrobras owning to lack ofaccess to the market. A growing number of private producers are positioning to market theirproduction independently in the medium term if they are given access to the pipeline infrastructure.
The oil and gas fiscal regime in Brazil is based on 30-year tax-royalty concessions for E&P. However,in 2008 the government decided that the huge deepwater pre-salt2 resources in the offshore Santos
and Campos basins should be developed under PSCs with Petrobras as the operator with a minimum
participation of 30%. In order to allow the discussion and approval of a separate law for pre-salt
blocks, the government suspended the annual upstream exploration auctions in 2008; these wereresumed only in May 2013. Currently Brazil operates under three separate exploration regimes:
concession contracts for all areas except pre-salt, PSCs for pre-salt blocks and hybrid contracts for asmall number of pre-salt blocks granted exclusively to Petrobras under a rights transfer agreementwith the Brazilian government.
Petrobras’ previous forecasts indicated that the company would be producing 6 million bbl/d of oil and
80 Bcma of domestic gas by 2020, most of which would be associated gas from pre-salt discoveries.
In this scenario Brazil would become a net gas exporter. This prompted Petrobras and its partners to

1(EPE , 2013).
Pre-salt refers to the geological strata beneath salt layers. Some petroleum that was formed in the pre-salt layer has not
migrated upwards to the post-salt layers. This is especially common off the coast of West Africa and Southeast Brazil.
2

1

commission a FEED study in 2009 for a 2.7 mtpa FLNG to be built offshore Rio de Janeiro. Petrobras
originally planned to start LNG exports in 2016.
Delays in several upstream projects, uncertainty over gas reinjection volumes and the quality of presalt gas (which is thought to have a high CO2 content), and the increasing demand for gas in power
generation led to major changes in the supply and demand forecasts for natural gas. The FLNG
project was suspended in 2010 and Petrobras increased its LNG import capacity, with three FSRUs
commissioned between 2009 and 2014. Only recently, the industry agreed a forecast for domesticgas production, which is expected to grow to approximately 50 Bcma by 2020, of which 31.4 Bcma
will be available for sale3. Thus in the long term Brazil will continue to depend on imported gas tomeet domestic demand. If the seasonal scarce rainfall persists in coming years and if there is no
policy change promoting base-load gas generation, Brazil will continue to be a significant player in the
LNG spot market.
In 2013 the Brazilian government resumed E&P leasing auctions. In May of that year, 142 onshore
and offshore blocks were awarded at a concession auction to 39 companies that together paid
signature bonuses in excess of $1.3 bn. In October Brazil completed the first pre-salt bid under the
new PSC regime; only one consortium – formed by Petrobras, Shell, Total and CNPC – took part. In
November the ANP offered another 240 onshore blocks for auction, but the response was limited.
This paper provides an overview of the natural gas market fundamentals in Brazil – supply, demandand pricing – as well as a supply and demand forecast to 2025. It reviews the outlook forunconventional and pre-salt gas in Brazil and the current status of and prospects for gas trading(imports and exports) with Bolivia and Argentina. In addition, it discusses key issues impacting on thepenetration of natural gas in the industrial, power and NGV sectors: price competitiveness, access to
infrastructure and the challenges in increasing the share of gas-fired power generation in the hydrodominated power mix, including matching LNG contractual terms with the unpredictable dispatch ofgas-fired power plants.

2. Brazil in Context
Brazil is the fifth-largest country in the world in terms of surface area (8.5 million km 2), larger thaneither the continental US or Western Europe. Its population of approximately 201 million4 lives mainly
in coastal areas – vast swaths of the country remain covered by the Amazonian forest. Brazil is afederation of 27 states, each of which has its own constitution and elected local parliament (State
Assembly). The federal government system is a presidential one in which the elected head of state
has a four-year mandate. The parliament is made up of a lower chamber (Congresso Federal) and an
upper chamber (Senado), which represents the federal states.
Brazil’s economy is the seventh-largest in the world: in 2013 GDP amounted to $2.2 trillion5. Owing toseveral setbacks, the economy is predicted to grow by only 1.67% in 2014, significantly below therecord 7.5% growth in 2010.

3

The balance is to be used for oil field reinjection and production facility fuel gas.
http://g1.globo.com/brasil/noticia/2013/08/populacao-brasileira-ultrapassa-marca-de-200-milhoes-diz-ibge.html
5
IMF:
http://www.imf.org/external/pubs/ft/weo/2014/01/weodata/weorept.aspx?pr.x=55&pr.y=14&sy=2012&ey=2019&scsm=1&ssd=1&sort=country&ds=.&br=1&c=223&s=NGDP_R%2CNGDPD&grp=0&a=4

2

Brazil’s economy is quite diversified: the services sector accounts for 59% of GDP, followed byindustry (21%) and agriculture (15%). Similarly the industrial sector is very diverse, catering for thedomestic and export markets and encompassing segments ranging from aerospace to automakers,
consumer goods, ship-building, chemicals, aluminium, ceramics, glass and textiles. However,Brazilian industry has been struggling to compete with cheaper Chinese manufactured products whileat the same time being faced with a strong domestic currency (Brazilian Real) and high energy prices
and taxes.
Brazil is an important exporter of agricultural products, in particular soya beans, sugar cane, maize
and wheat. It is also one of the world’s leading producers of iron ore, manganese, bauxite, nickel andlimestone.
Figure 1: Brazil’s GDP growth, 1998–2013

Source: http://g1.globo.com/economia/noticia/2014/02/economia-brasileira-avancou-23-em-2013-diz-ibge.html

The city of Sao Paulo is the largest financial market in South America and one of the largest in theworld. However, there are 15 other cities in Brazil with more than 1 million inhabitants 6.
Following are other important factoids about Brazil:
 It is the world’s fourth-largest market for bulk and passengers transportation vehicles and thethird-largest for computers.
 It has the largest private helicopter fleet and the second-largest executive jet fleet in the world.
 In 2010 Brazilian consumers purchased 12 million TV sets.
 In 2011 there were 215 million mobile phones in operation in Brazil, making it the fourthlargest mobile phone market in the world.
 Brazil is the 11th-largest oil producer in the world and the second-largest producer ofhydroelectricity.

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http://exame.abril.com.br/brasil/noticias/as-300-cidades-mais-populosas-do-brasil-em-20133

Figure 2: Composition of Brazil's GDP, 2013

Source: http://g1.globo.com/economia/noticia/2014/02/economia-brasileira-avancou-23-em-2013-diz-ibge.html

Brazil is a member of the Mercosur free trade area, which comprises Argentina, Uruguay, Chile,
Paraguay and Venezuela as well as Bolivia as an acceding member. The purpose of Mercosur is topromote free trade and the free movement of goods, people and currencies.

2.1 Brazil’s energy matrix is becoming less green
Brazil’s energy policymakers are very proud of the country’s ‘green’ energy credentials: renewableenergy plays a large role if the share of hydropower and biomass7 is taken into account. Wind power
is not yet significant, despite an increase in wind projects being built in the northeast region over the
past 10 years. However, the share of renewable energy in the overall energy mix decreased from
44% in 2011 to 42.4% in 2012 owing to the decrease in the consumption of ethanol and the increasein the consumption of petrol, diesel and natural gas 8. The share of renewable energy, particularlyhydropower and ethanol, is expected to decrease further but still be significantly larger than the world
average of 13.2%9. In 2012 the primary energy offer was 283 MTOE.
Figure 3: Brazil’s primary energy mix, 2012

Source: (EPE , 2013)

7

Figures include sugarcane ethanol.
(EPE , 2013).
9
http://www.iea.org/aboutus/faqs/renewableenergy/
84Natural gas accounts for 12% of Brazil’s primary energy consumption, while oil accounts for 39%. Oil
products are used primarily in the transportation and residential sectors. Despite the significant role ofanhydrous ethanol, which is used in a 22% mixture with petrol and as a popular standalone fuel inflexi cars10, the Brazilian fleet is highly dependent on diesel and petrol, while bottled LPG is the main
fuel used for cooking.
In order to shield the country from the 2008–09 world economic crisis, the Brazilian government
embarked on a policy of fuelling domestic demand by facilitating credit to families, increasing the
distribution of cash grants to the poor and reducing taxes and customs duties for consumer-oriented
industries such as automakers and white-good manufacturers.
From 2001 to 2012 Brazil’s vehicle fleet jumped from 34.9 million to 76.1 million – an increase of
138%, compared with population growth of 11.8% in the same period 11. At the same time, there was a
sharp increase in the purchase of home appliances and equipment such as computers, mobile
phones, refrigerators, TVs and air-conditioning sets.
To rein in demand-driven inflation, the government froze Petrobras’ ex-refinery petrol and diesel
prices and ended a compensation mechanism (CIDE) previously used to neutralising currency andprice fluctuations. The freeze on petrol prices impacted negatively on the ethanol industry because
ethanol prices are pegged to petrol prices and producers could no longer compete with the price of
petrol ex pump. As regards the power sector, the Ministry of the Environment established new rules
for permitting power projects that virtually prevent hydroelectric power plants with reservoirs frombeing built. Previously, such plants were built with firm energy equivalent to 55% of their total
capacity. Nowadays hydro power plants are only built as “run-of-the-river”. The new environmental
rules contribute to reducing the availability of hydropower during the dry season.
Overall, the consumption of energy increased 3.4% in 2011–12, while losses in transformation rose
8% owing to the increase in thermal power generation.
Despite very modest GDP growth of 0.9% in the period 2011–12, the government policy of fuellingdomestic demand resulted in disproportionately high growth in the consumption of electricity andliquid fuels, as Figure 4 below shows. The consumption of petrol alone increased 17% in 2011–12.

A ‘flexi-car’ can burn any mixture of hydrated ethanol and petrol. This development has slowed down the conversion of cars
to natural gas in Brazil.
11(Instituto Nacional de Ciencia e Tecnologia, 2013)10

5

Figure 4: Comparative energy and economic indicators, 2011–12

Source: (EPE , 2013)

Brazil’s total installed capacity in 2012 was close to 121 GW, compared with 89 GW in the UK12.
Hydropower plants account for approximately 84 GW (70%) and thermal plants (gas, oil and coal) for
32.5 GW. The share of hydro in the power generation mix decreased from 464.2 TWh in 2011 to455.6 TWh in 2012 owing to the unusually long dry season and the reduction in storage capacity.
Figure 5: Brazil's power generation capacity, 2012

Source: (EPE , 2013)

The power sector in Brazil is reeling from the damaging impact of several developments: therecurrence of abnormally dry seasons, which has resulted in the reduced availability of cheaperhydropower; losses of profitability for power generation and distribution companies owing to higher
generation costs and the government’s mandatory reduction in electricity tariffs in the period before
the 2012 municipal elections; and mismatch between demand and contracted power, causing a ‘hole’

12

https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/279546/DUKES_2013_Chapter_5.pdf

6

of 3000 MW that was covered by distribution companies through purchases on the spot market.
According to power sector specialists, in 2015 Brazilian consumers will have to pay an additional$18–23 bn in order to contain the haemorrhage in the sector13.
Petrobras – the main E&P investor in Brazil – is also the largest gas-to-power generator. Be that as it
may, the oil and gas sector is expected to play a big role in Brazil’s economy in the short and longterm. Planned investment in oil and gas for the period 2013–16 will total approximately $200 bn,
exceeding combined investment in the other industrial sectors. The Ministry of Energy’s 10-year Plan
for 2012–22 estimates that $550 bn will be needed to increase the availability of electricity, oil and gas
and biofuels. According to the plan, the power sector will require investment totalling $124 million toincrease capacity from almost 121 GW currently to 183 GW in 202214.
Figure 6: Planned investment in Brazil by sector, 2013–16

Source: (EPE , 2013)

2.2 The Brazilian gas industry: Genesis and evolution
The Brazilian gas industry was founded in 1851, when the Baron of Maua, a Brazilian entrepreneur,signed a contract to provide street lighting in the city of Rio de Janeiro15. In 1854 the Rio de Janeiro
Gas Company – later known as CEG (Companhia Estadual de Gas) – was incorporated. This wasfollowed by the incorporation of the Sao Paulo Gas Company (Comgas) in 1872 and several city gas
distribution companies in other Brazilian cities. Medium calorific gas was produced through thedistillation of coal in retorts. The advent of electricity in the early 1900s contributed to the collapse of
all city gas companies except for Comgas and CEG, both of which continued to produce medium
calorific gas from coal for cooking purposes until the 1960s, when they switched to naphtha. Until thelate 1980s, city gas in Brazil was a mix of methane, hydrogen and carbon dioxide distributed to asmall number of households and industrial consumers. CEG and Comgas were state-owned
companies that had very limited market reach owing to the lack of gas supplies and funding.
In 1953 the nationalist government of President Getulio Vargas established a state-owned oilcompany, Petróleo Brasileiro S.A. (Petrobras), following a country-wide campaign under the motto ‘O13

http://noticias.r7.com/economia/conta-criada-no-setor-de-energia-pode-ir-a-r-52-bilhoes-10042014-1(EPE, 2013).
15
https://www.gasnaturalfenosa.com.br/br/conheca-nos/quem+somos/historia/1297092019569/historia+rio.html
147

petróleo é nosso’16. The monopoly of Petrobras in the oil and gas sector, except in gas distribution
and importation, was subsequently enshrined in the Brazilian Constitution. Petrobras started toprospect for and find oil in onshore locations in northeast and southeast Brazil and to market
associated natural gas to industrial consumers near its oil fields.
From 1960 to 1984 two gas distribution regimes existed in Brazil: city gas17 distribution in the cities of
Sao Paulo and Rio de Janeiro and natural gas industrial distribution by Petrobras in eight states in thenorth-eastern part of the country and in the interior of the state of Rio de Janeiro. Following thediscovery of large offshore oil fields in the Campos Basin (Rio de Janeiro), which provided large
volumes of associated gas, Comgas and CEG entered into negotiations with Petrobras and signed
gas supply and purchase agreements allowing them to expand the distribution network. The
governments of several states particularly those served by Petrobras’ gas distribution system,
established their own city gas distribution companies (LDCs) in a bid to exert more control over the
expansion of the natural gas grid. At the same time, the federal government wanted to provide
incentives for private investment in oil and gas E&P because of Petrobras’ limited investment
capability and Brazil’s continued dependence on imported crude.
Initially, Petrobras was very reluctant to supply gas to the LDCs as it competed with low-value fuel oil
produced at Petrobras’ 11 refineries. In 1995, following a campaign by the LDCs to be allowed toimport gas from Bolivia, a constitutional amendment ended Petrobras’ monopoly by allowing privateand state-controlled companies to explore for, produce, transport, and import and distribute petroleum
and natural gas. The Petroleum Law (9478) of August 6, 1997 created a regulatory body, the ANP,
and established a regulatory framework for the petroleum sector, which was later expanded tobiofuels. Meanwhile, the distribution of natural gas remained within the competence of the federal
states.
Even after the formal end of its monopoly, Petrobras continued to play a huge role in controlling
Brazil’s gas industry and infrastructure and to dictate both the pace of infrastructure expansion andgas pricing. This prompted another campaign to reduce Petrobras’ grip on the gas sector, which
resulted in the enactment of the Gas Law (11909) of March 4, 2009, which is yet to be fully
implemented.
During the period 1997–99 the states of Sao Paulo and Rio de Janeiro privatised their gas distribution
companies, while other states decided in favour of a tripartite ownership model in which the state
government, Petrobras and private investors were shareholders. All states granted a 30–50 year
exclusive geographical franchise to gas distribution concessionaires. The states of Sao Paulo,
Espirito Santo and Rio de Janeiro regulation allow large consumers to become so-called freeconsumers after the 11th anniversary of the concession contract, but even free consumers are
obliged to pay a distribution fee regulated by the state’s regulatory agency. Since Petrobras remains
the only supplier of gas and since the same distribution fee must be paid by free and captive
consumers, there is no incentive to become a free consumer.
Despite all the setbacks and the lack of a clear government policy to provide incentives for the
production and utilisation of natural gas, the Brazilian gas industry has witnessed some progress,
particularly between 1999 and 2005 following the commissioning of the Bolivia-Brazil gas pipeline.

16
17‘The petroleum belongs to us’.
Medium calorific value city gas was manufactured from naphtha.

8Gas consumption increased from 1 Bcma in 1980 to approximately 33 Bcma in 2013 while thenumber of consumers rose from under 500,000 in 1999 to 2.4 million in early 201418.

3. Key Industry Players and Regulation
Following the enactment of the 1997 Petroleum Law and the creation of the ANP, Brazil initiallygranted a transition period for the exploration blocks held by Petrobras and then developed the rules
for holding E&P auctions on a yearly basis. The first pre-salt blocks were auctioned in the second
exploration bidding round, which took place in 2000, when there was still little knowledge of thecountry’s resource potential. The auctions attracted a significant number of domestic and internationaloil companies. Currently, 77 companies – both domestic and international – hold 329 exploration
concessions.
The sedimentary basins in Brazil cover an area of 7.5 million km 2. Little is known about the resource
potential of several offshore and onshore basins, particularly in the north of the country. Out of Brazil’s
27 federal states, only 10 are gas-producing, with 66% of overall production concentrated in threebasins – Campos, Urucu (Amazonas state) and Espirito Santo.

3.1 Brazil’s E&P fiscal regime
The E&P fiscal regime in Brazil follows three models:Royalty-tax concessions, for all exploration contracts signed before 2012 and new
exploration blocks that are not part of the pre-salt.

Hybrid (Transfer of rights), under which the federal government granted exclusive rights toPetrobras to explore a number of pre-salt blocks.

In 2010 the federal government granted Petrobras exclusive rights to produce up to 5 bn BOEover 40 years in seven pre-salt areas and prospects, in six definitive blocks and in one
contingent block]19. Petrobras paid BRL74.8 bn ($42.5 bn) to the federal government for thetransfer of rights, implying an average price of $8.51/BOE.
Petrobras and the ANP hired, respectively, DeGolyer and MacNaughton and Gaffney, Cline &Associates to certify 2C contingent (best estimate) 20 and prospective resources in theassigned discoveries/prospects and to conduct a discounted cash flow analysis of the netpresent value of hydrocarbons in situ. Gaffney, Cline estimated 2C contingent resources andbest-estimate prospective resources of 7.05 bn BOE, with an NPV ranging from $6.39/BOE to$11.76/BOE at a 10% discount rate 21 . After negotiations with the government, Petrobras
agreed to pay $42.5 bn for the rights. Petrobras then issued shares to pay for the rights andto finance part of its ambitious investment programme; a 2010 share issue raised $71.6 bn –the largest-ever sum to be raised by this means. In practical terms, the share issue increased

18(ABEGAS, 2014) (BP , 2013).
Tupi Sul, Florim, Tupi Nordeste, Peroba, Guará and Franco e Iara are the definitive blocks and Peroba the contingent block.
20‘Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by
application of development projects, but which are not currently considered to be commercially recoverable due to one or more
contingencies.’ (Gaffney, Cline & Associates, 2010).
21(Gaffney, Cline & Associates, 2010).
19

9

the Union’s shareholding in Petrobras from 39.8% to 48.3%, diluted minority shareholdings
and contributed to creating a surplus on the 2010 primary account.
Production Sharing Contracts (PSC), for all pre-salt blocks granted after 2010 and for new‘strategic areas’.
According to the new legislation approved by the Congress in 2010 Petrobras is the soleoperator with a minimum 30% interest in all PSC blocks. The first pre-salt block (Libra) in the
new PSC regimen was auctioned in October 2013, although there was only one bidder – theconsortium formed by Petrobras, Shell, Total and CNPC. The signature bonus was $6.8 bn
and the bidder offered the minimum profit oil percentage of 41.65%. The ANP expects the
Libra block to contain 8–12 bn BOE.

Table 1: Blocks granted to Petrobras via transfer of rights
Block

Volume (MMBOE)

Price ($/BOE)

FlorimFrancoSouth Guara
Entorno de Yara
South Tupi
Northeast Tupi
Peroba
Total

467
3058
319
600
128
428
tbd
5000

9.01
9.04
7.94
5.82
7.82
8.54
8.53
8.51

Source: (Rocha, 2011)

In Brazil the exploration bidding round consists of a pre-qualification stage, in which investors may
qualify as operator type A (any area, including deepwater), B (shallow water and onshore), C(onshore) or non-operator, and the depositing of a bank or parent company guarantee. On the day of
bidding, which is a public event, bidders are asked to make bids for the following: Bidding bonus (which should be equal to or exceed a pre-determined value); Percentage of local content (percentage for the exploration stage differs from that for thedevelopment stage).
The winner is immediately awarded the block(s) and must sign a concession contract within one
month of the bidding date. There is no restriction on the number of bids per bidder and companies areallowed to form consortia, provided they meet the pre-qualification criteria. As regards bids for pre-salt
blocks, the government fixes the bidding bonus and the percentages of local content and cost oil. The
bidder is asked to make a bid for the percentage of profit oil to be transferred to the federal
government.
In 2008, following the pre-salt discoveries, the government suspended the annual auctions and sent abill to the Congress providing for a new fiscal regime for pre-salt and strategic blocks. At that time, it
was estimated that the pre-salt blocks could hold reserves of 30–50 bn BOE and that the exploration
risk was very low, which justified increased control and a larger government take. Law No 12.351 ofDecember 22, 2010 introduced the pre-salt regime, created a new state company to manage thegovernment’s interests in PSCs – Pre-Sal Brasil S. A. – and granted additional rights to Petrobras.
Also, a new law on royalties was enacted in 2012 under which all Brazilian states receive royalty
revenues – the previous relevant legislation had benefited only the producing states – and pre-salt
royalties can be used for education and health. In 2013 the government launched new bidding
rounds. Hence, all in all, the review of legislation on pre-salt and strategic blocks resulted in a fiveyear hiatus that has unpredictable consequences for future supplies of oil and gas in Brazil.
10

To summarise, the main changes introduced by the new petroleum legislation are:
 Pre-salt and strategic blocks are to be allocated under a production-sharing regime. All otherblocks are to be allocated through concession licences. Pre-salt blocks allocated before theenactment of the new legislation will continue to be explored under concession licences.
 The government has created a new state-owned company – Pre-Sal Brasil S.A. – torepresent the government’s interests in pre-salt contracts. This company will have majority
and veto rights in all pre-salt joint operating agreements
 Petrobras will be the sole operator of all pre-salt blocks with a minimum stake of 30%.
 The Congress has approved the creation of a special fund to invest pre-salt revenues inhealth and education.
 Producing and non-producing states will share equally the royalty proceedings which in thepast were allocate only to producing states. Although there is no fixed percentage of local
content established by law, the ANP has maintained a high threshold for bids, despite theconclusions of a study from ONIP 22 showing that local providers usually supply goods at
higher cost than international suppliers. .
Figure 7: Evolution of Brazil’s oil & gas legislation

Source: Author

3.2 Natural gas regulation
In Brazil there are two distinct jurisdictions for the regulation of the natural gas industry. The federal
government sets all policy and regulation on the upstream and midstream, while the state
governments supervise distribution activities and approve end-user prices.

22(Oportunidades, desafios e competitividade para a rede de fornecedores de O&G no Brasil, 2013).

11

Federal level The Ministry of Mines and Energy (MME) sets sector policies, executes high-level planning,authorises the import and export of natural gas; the MME is also in charge of putting in placea 10-year plan for the expansion of the gas transportation system; The National Council of Energy Policy (CNPE) approves the exploration blocks to be
auctioned by the ANP (see immediately below) and sets guidelines for the development ofBrazil’s energy resources; The National Petroleum Agency (ANP) organises E&P auctions and gas transportation bids,
monitors the execution of E&P activities, authorizes the construction of LNG import terminals
and mediates conflicts involving producers, transporters, distributers and users;
 The Energy Planning Company (EPE) is responsible for forecasting long term energy demand
as well and organise auctions for three and five year power capacity and availability,
respectively A-3 and A-5 auctions.
States level The regulatory agencies of the states approve distribution margins and tariffs and monitor
LDC concession contracts.
Apart from the restrictions governing the participation on the pre-salt blocks, any company establishedunder Brazilian law can participate in any activity in the gas value chain. E&P concessionaires areallowed to dispose freely of their share of natural gas and oil.
According to the 2009 Gas Law, two regimes exist for the construction and operation of gas pipelines:
international pipelines are authorised by the MME, whereas domestic pipelines fall under a regime
whereby concessions are granted to the bidder offering the lowest tariffs. The owner of pipelines built
or authorised before 2009 are granted 10-years’ exclusivity. There is no open access to LNG
terminals.
Gas distribution concessions are granted by individual states. Most states have established energy
regulatory agencies to ensure quality of service and approve the margins and tariffs ofconcessionaires. The states are not obliged to follow a uniform federal framework, which causes
some discomfort for large industrial end-users that have premises in more than one state since they
have to abide by more than one set of rules and price levels.
In the downstream segment, there are 27 gas distribution companies (LDCs). Most states have just
one LDC, while Sao Paulo has three and Rio de Janeiro two. According to the Brazilian Constitution,
the states either operate gas distribution services directly or grant concessions to third parties. As
noted above, gas distribution concessions award exclusive geographical franchise rights for 30–50
years. End-user prices are either bundled or cost of service, depending on the legislation of therelevant state, and readjusted on a yearly basis.

12

Table 2: Key players in Brazil's gas value chain23

Source: Author’s research

Figure 8: Geographical location of LDCs in Brazil

Source: http://www.abegas.org.br/Site/?page_id=839

23

PEMAT: MME 10-year Plan for the expansion of natural gas pipelines.

13

4. Brazil’s Gas Reserves: Significant Growth
Brazil’s gas reserves, though dwarfed by Venezuela’s, have increased 25% over the last five years
thanks to Petrobras and private companies investing in oil and gas exploration and development. In
fact, Brazil, Peru, Venezuela and, to a certain extent, Colombia are the only countries in SouthAmerica to have seen growth in gas reserves, while traditional exporters such as Bolivia andArgentina are experiencing a dramatic change in fortunes. Bolivia’s takeover of foreign oil companies’
assets and the nationalisation of gas reserves in 2006 have resulted in a sharp reduction in E&P
investment. As a consequence, Bolivia’s gas reserves more than halved over the last five years –from 26.13 Tcf in 2007 to just 11.2 Tcf in 201224. According to the Oil & Gas Journal, its provenreserves are only 9.9 Tcf, whereas the US Energy Information Agency (EIA) 25 estimates that its
technically recoverable reserves are 48 Tcf. Argentina is suffering from the same problem: its gas
reserves fell from 15.5 Tcf in 2007 to 11.3 Tcf in 2012.
The Global Petroleum Survey 2013 of the Fraser Institute polled the views of 864 respondents
representing 762 companies in the oil and gas sector 26. The survey ranked Bolivia and Salta Province
in Argentina among the 10 least attractive regions for investment out of 147 global jurisdictions. The
ranking is based on five commercial environment index factors: fiscal terms, taxation in general, tradebarriers, quality of infrastructure, and labour availability and skills 27.
The state-owned Yacimientos Petroliferos Fiscales Bolivianos (YPFB) is trying to develop E&P
partnerships with foreign companies in a bid to double natural gas production by 2015. According to
the EIA, YPFB aims to negotiate and approve 18 exploration contracts and drill 14 wells by 2015.
Following the development of a new service contract model, a few deals were inked in 2013 withinternational companies, including the south-eastern Azero block (Gazprom/Total/Tecpetrol) and theCedro and Huacareta areas (Petrobras and BG Group respectively).

24(BP, 2008) (BP , 2013).
(US Energy Information Administration, 2012).
26(Fraser Institute, 2013).
27(Wilson, 2013).
25

14

Figure 9: Evolution of gas reserves in South & Central America

Sources: (BP , 2013) (BP, 2008)

At 16 Tcf, Brazil’s gas reserves are larger than those of Trinidad & Tobago, twice the size of the UK’sand half of Azerbaijan’s. Although the gas R/P in 2012 was 26 years, Brazil’s domestic gas production
is insufficient to meet its gas demand.
Figure 10: Gas reserves of Brazil compared with other selected gas producers, 2012

Source: (BP , 2013)15

4.1 Domestic gas production
As of January 2014, Brazil had 329 blocks in the exploration phase, 72 fields in the development
phase and 437 concessions in the production phase –– operated by 23 companies. There were 8,980
producing wells, of which 8213 were onshore and 767 offshore28.
Figure 11: Brazil's E&P sedimentary basins

Source: Petrobras (http://www.fool.com/investing/international/2014/05/17/will-petrobras-production-grow.aspx)

In 2013 Brazil produced on average 77 MMm3d of natural gas (27.8 Bcma). Approximately 67% isassociated gas, while 73% of is produced offshore. In January 2014 Brazil’s gas production reached80.4 MMm3/d (29.3 Bcma); the field with the largest production was the pre-salt oil field Lula, which
produced 2.4 Bcma, of which 0.4 Bcma was flared. According to Petrobras, in March 2014 Brazil’s
domestic production reached a record 100 MMm3/d (35 Bcma)29.

28
29

http://www.anp.gov.br/?pg=70027&m=&t1=&t2=&t3=&t4=&ar=&ps=&cachebust=1395447983965
Presentation by Petrobras at the CWC Rio Gas Forum, April 10, 2014.

16

Figure 12: Breakdown of Brazil's gas production, 2013

Source: (MME, 2014)

In 2013 only 57% of Brazil’s domestic gas production reached the market. Approximately 12 Bcma
are used by Petrobras in E&P operations and at its gas processing units or re-injected and flared.
Petrobras also uses a large share of the marketed production at its refineries and fertilizer plants (4.6
Bcma).
Figure 13: Brazil’s domestic natural gas production vs available supply

Sources: (ANP, 2008) (MME, 2014)

Gas production in Brazil is dominated by Petrobras, which accounts for 83.4% of the country’s total
output. There are currently nine private companies producing gas, most of which in partnership withPetrobras. Only one consortium sells gas independently; the others sell to Petrobras at the wellhead.

17

Figure 14: Breakdown of Brazilian gas production by company (MMm3/d)

Source: (MME, 2014)

Several major IOCs are currently active in Brazil, most of them in the exploration or development
phase: BG, BP, Shell, Exxon, Chevron, Total, GDF Suez, GALP, Repsol and Statoil.
Table 3 below shows the companies that are producing gas in Brazil alongside Petrobras, albeit insignificantly smaller volumes than the Brazilian NOC. Six of the smaller producers are independent
Brazilian companies.
Table 3: Gas production in Brazil by producer, 2013
Producer

Gas Producer (Mm3/d)

Type of company

Parnaiba Gas
Queiroz Galvao
BG Brasil
Petra Parnaiba
Brasoil Manati
Petrogal Brasil
Rio das Contas
EP Energy
Repsol Sinopec
Petrobras
Total

3.92
2.79
1.77
1.68
0.62
0.62
0.62
0.59
0.35
65.1
78.06

Brazilian independent
Brazilian independentIOC
Brazilian independent
Brazilian independentIOC
Brazilian independent
Brazilian independentIOC
Brazilian NOC
IOC

Source: (MME, 2014)

4.1.1 Brazil’s pre-salt hopes
Brazil’s pre-salt blocks consist of several clusters on the continental shelves offshore the Campos andSantos basins, in south-eastern Brazil. The hydrocarbon formations are buried under a 2000m layerof salt at a water depth of 2000–3000m. It is estimated that pre-salt covers an area of 122,000km 2, of
which 41,000km2 have already been allocated for exploration/development. Brazil’s pre-salt oil is ofgood quality (28–310 API) and has a gas-to-oil ratio of 250–300m3 of gas/m3 oil and CO2 content of 8–
15%30. The Santos Basin Pre-Salt Cluster comprises six blocks operated by Petrobras with various

30(Pre-salt Production development in Brazil, 2011).

18

partners: GALP (Caramba and Jupiter), Shell and GALP (Bem-Te-Vi), BG and Repsol (Carioca andGuará), BG and Partex (Parati), BG and GALP (Lula, Cernambi and Iara. Six other blocks have been
allocated to Petrobras under the transfer of rights regime, while another block (Libra) was auctioned
under the PSC regime in 2013. More than 30 pre-salt blocks have yet to be auctioned. The Lula andCernambi fields contain estimated recoverable reserves totalling 8.3 bn BOE, while Brazil’s entire presalt may yield more than 50 bn BOE.
Assuming that by 2020 the pre-salt blocks are producing 2 MM bbl/d the gross production of
associated gas is estimated at 79–95 MMm3 /d. After subtracting volumes used by Petrobras
internally and taking into account the removal of CO2, the total volume available for sales would befrom 35-42 MMm3/d.
In 2009 Petrobras and its partners (BG, GALP and Repsol) awarded FEED contracts to three
consortia:
Saipem (Italy), SBM (Switzerland)/Chiyoda (Japan) and Technip (France)/JGC(Japan)/Modec (Japan) 31 to develop a floating LNG unit that would process 5.1 Bcma of pre-salt
associated gas to produce 2.4–2.8 mtpa of LNG and LPG. Petrobras aimed to execute an EPC
contract by mid-2011 with the objective of starting to produce LNG by the end of 2015. At that time
Petrobras, very encouraged by the outlook for pre-salt, announced it would be commissioning the first
FLNG in the world, ahead of Shell’s Prelude. However, in 2011, it issued a statement saying that itwas not proceeding with the FLNG project and would instead build three pipelines delivering the presalt gas to processing facilities in Sao Paulo and Rio de Janeiro. Among the reasons cited for thatdecision was the need to supply ethane to a Petrobras-led petrochemical project in Rio anduncertainties over CO2 removal and gas needs for reinjection.
As of March 2014, Petrobras was producing nearly 400,000 bbl/d of oil at pre-salt fields and 2.3 Bcmaof associated gas, of which 17% was being flared.
Figure 15: Pre-salt clusters in southeast Brazil

Source: (Fraga, 2012)31

http://www.rigzone.com/news/oil_gas/a/84447/Petrobras_Awards_FEED_Contract_for_Floating_LNG_Unit19

4.2 Natural gas balance
Despite the size of Brazil’s economy and its large population, domestic consumption of natural gas isrelatively modest when compared with that of the country’s smaller neighbour, Argentina, or otheremerging markets, such as Turkey and India. A relatively mild climate (which means no need forspace heating), insufficient investment in infrastructure and lack of interest in the exploration anddevelopment of non-associated gas are among the reasons for the modest role of natural gas in
Brazil.
LDCs control most of the downstream market and accounted for 73.3% of natural gas consumption in
2013; the remainder is used by Petrobras at its refineries, fertiliser and power plants.
Figure 16: Natural gas balance in Brazil, 2013

Source: (MME, 2014)

Brazil began importing natural gas in 1999, initially from Bolivia and from 2000 onwards from
Argentina as well; LNG imports started in 2009. After deducting volumes used internally byPetrobras, the supply of domestic gas is now slightly less than that of imported gas.

4.3 Gas demand by sector
The consumption of natural gas has been growing steadily in Brazil since the commissioning in 1999
of the Bolivia-Brazil pipeline. The compound average growth rate was 10.8% for the period 2000 –2013. The gas consumption pattern in Brazil differs from that in other emerging countries in the sensethat the industrial sector accounts for the bulk of demand while power sector demand is extremely
variable and highly dependent on rainfall and the availability of hydropower.
For example, in 2011 the industrial sector accounted for 66% of total gas marketed in Brazil and thepower sector just 17% (see Figure 17 immediately below).

20

Figure 17: Brazilian gas consumption by segment, 2011

Source: (MME, 2014)

In 2013, however, the power sector accounted for 43% and industry for 46% of consumption (seeFigure 18 below). The share of other market segments dropped in terms of percentage but was
virtually unchanged in absolute terms.
Figure 18: Brazilian gas consumption by segment, 2013

Source: (MME, 2014)

In 2013 the LDCs were responsible for the sales of approximately 74% of natural gas supply in Brazil.
The country’s 27 LDCs supplied gas to 2.44 million consumers32, the majority of which are located in
the states of Sao Paulo and Rio de Janeiro.
Several of Petrobras’ power plants and refineries are classified as self-consumers and receive gas
directly from Petrobras. The first independent gas production and supply project in Brasil wascommissioned in 2013 in the northern state of Maranhao. It integrates gas production from theonshore Parnaiba block with an 845 MW power generation complex, which consumes 2 Bcma anddispatches mostly on base load.

32(ABEGAS, 2014).

21

Figure 19: Evolution of Brazilian gas consumption by sector

Source: (MME, 2014)

The 19.5% growth in consumption in 2013 compared with 2012 can be explained by the decision of
the National System Operator (ONS) to increase the dispatch of gas-fired power plants to mitigate theimpact of the prolonged dry period, which severely depleted the reservoirs in the southern and southeastern regions.
By contrast with the stable and nearly stagnant consumption levels of the industrial sector, powersector demand follows no predictable pattern: it jumped from 11.73 MMm3/d in February 2012 to25.86 MMm3/d in April 2012 and sank back to 12.09 MMm 3/d in June 2012. The average
consumption of the power sector in 2013 was 38.91 MMm 3/d.
Figure 20: Natural gas consumption in Brazil’s power and industrial sectors

Source: (MME, 2014)

The irregular consumption pattern of the power sector makes it extremely difficult for private powersector developers to secure long-term gas supplies because if they embed the costs of gas ‘take orpay’ (ToP) commitments in the fixed costs of the power plant they may not be able to win the longterm power auctions (A-5) 33as their prices will not be competitive against those of smaller wind andbiomass power plants.

33

A-5: power auctions designed to add new capacity within five years.

22At the same time, unpredictable consumption levels in the power sector make it difficult for privately
owned power plants to commit to ToP gas agreements – particularly those involving LNG, which
requires 100% ToP. In 2013 average gas consumption in the power sector was 38.91 MMm 3/d; in2012 the same plants consumed on average 23.03 MMm 3/d, which is 59% of 2013 consumption. The
lowest level of consumption was registered in January 2012 – 8.15 Mm3/d – which was just 21% of
average 2013 consumption. Moreover, power plants cannot re-sell gas already paid for but notconsumed in the secondary market.
It is for this reason that Petrobras, which owns most of Brazil’s gas-fired power plants, is the only
company that has a large portfolio of domestic and imported gas supplies with which the relatively low
power price ceiling and conditions imposed by the MME can be met. Those conditions include theobligation to present 25-year gas supply agreements and to demonstrate that the gas supplierpossesses reserves that will meet the 25-year supply obligation; the latter doesn’t fit well with LNG
portfolio suppliers which source LNG from various projects. The auction price is also too low toaccommodate for LNG import prices. Once a power price is bid there is little flexibility to readjust thevariable components. Most existing gas-fired plants were built in 2003/2004–, at a time when Brazil
was still in the wake of the 2001 rationing of electricity and before such restrictive conditions were inplace. As a result of current auction policies, only four gas-fired power plants are being built in Brazil,
three of which belong to Petrobras and one by government-owned Eletrobras. Despite the increased
need for thermal power, the government forecast is for just 1,450 MW of new gas-fired power plant
capacity to be built by 2020, out of a total of 35,000 MW of new capacity added in the same period.34
Figure 21: Supply profile of Brazil’s gas-fired power plants, 2009–2013

Source: (IBP, 2013)

34(EPE, 2013).

23

4.4 Brazil’s power sector
Brazil’s National Integrated System (SIN) comprises four sub-systems: Southeast/Midwest, South,
Northeast and North; the two last-named have limited connectivity with the industrialized southern andsouth-eastern regions. Most of Brazil’s electricity demand is from the southeast of the country.
Figure 22: Brazil’s regional power transmission system

Source: http://www.ons.org.br/conheca_sistema/mapas_sin.aspx

Brazil’s generation system is 28.8% nuclear/thermal and 71.2% hydro/wind. Previously, the country’shydropower plants were built with large reservoirs with firm energy of 50–60% of total built capacity,which means they could stock lots of water that could be converted to power in the dry periods. In thelast decade the government succumbed to environmental and social pressure by thus severely
limiting the construction of power plants with reservoirs.
According to Brazil’s electricity regulator (ANEEL), 42 power plants with a combined capacity of
28,835 MW were granted concession licences in the period 2000–12. Only 10 of those plants wereauthorised to build reservoirs (total capacity of 1,940 MW). The other 32 plants, (26,894 MW) werebuilt without any storage capacity (‘run of the river’) 35.
After the rainy season, it is usual for Brazil’s hydropower reservoirs to bounce back to 80–100% of
their water storage level. But for the last three years, Brazil has suffered from low rainfall, which has
resulted in the faster depletion of the reservoirs with very limited recovery. By mid-2013 the reservoirs
in the south-eastern part of the country had recovered to only 64% of their water storage level.

35(Tancredi, 2013).

24

Figure 23: Brazil’s hydropower reservoirs - Historical patterns

Source: (MME, 2014)

The maximum storage capacity in Brazil is 287,716 MW, of which 201,717 MW is in the southeast.
Under Brazil’s 10-year energy plan, very little storage capacity will be added to the SIN between 2013
and 2022 – just 7 GW, which is a mere 2.4% increase, compared with estimated demand growth of
51% during the same period.
Figure 24: Storage capacity of Brazil’s hydropower reservoirs by region

Source: (EPE, 2013)

As of March 13, 2014, the energy stored in the Southeast/Midwest subsystem reached the very low
level of 35.84% – equivalent to approximately 72 GW. In February 2014 the SIN registered record
peak demand of 81,129 MW, which triggered the shutdown of 5,000 MW in several cities in thesoutheast for several hours.

25Table 4: Stored Energy in Brazil's hydropower reservoirs*
Subsystem

Stored energy (% of total capacity)

Southeast-Midwest
South
Northeast
North

35.84
39.44
42.13
83.2

* As of March 13, 2014.
Source: http://www.ons.org.br/home/

By the end of 2014 the installed capacity of gas-fired power plants in Brazil which are integrated with
the SIN is expected to reach 11,483 MW. This is roughly 34% of Brazil’s installed thermal capacityand 9.3% of its total installed power capacity. Gas-fired power plants operate in tandem with theavailability of hydropower. In 2012 hydropower plants accounted for 77% of the total power generated
in Brazil, compared with 82% in 2011.
Figure 25: Share of hydro-power in Brazil’s total power generation

Source: (EPE, 2013)

The hydrology situation in 2014, combined with the imperative that the government avoid blackouts
during the World Cup and presidential elections, points to the need for increased dispatch of thermal
power into the SIN. This will be accentuated in the winter months (June-August) since they are
traditionally drier in the south and southeast than the summer months and owing to the lack of rain in
the summer of 2013.

26

Figure 26: Brazil’s thermal power generation (gas, oil and coal), 2013 vs 2012

Source: ( ONS, 2014)

The MME projections for gas-fired capacity are very modest; in the short term, this is reflected in thelatest power auctions, in which no gas-fired power plants were included. In the medium to long term,
the MME expects less than 2,000 MW of new capacity at of gas-fired power plants during the period
up to 2022.
Figure 27: Outlook for Brazil’s gas-fired power plants

Sources: (EPE, 2013), (MME, 2014)27

4.5 Stored energy vs LNG imports
As of December 2013, there were 36 gas-fired power plants operating in Brazil, with a total capacityof 10,366 MW, and another three under construction (1,117 MW). Those plants range from combined
cycle gas turbines to stationary engines. At least 840 MW cannot be dispatched owing to lack of gas
or disputes under contractual arrangements.
In January 2013 the gas-fired plants generated an average of 7,486 MW, which implies a load factorof 79%. Based on that month’s average power consumption of 41.98 MMm 3/d, the unit average
consumption was 5.6m3/MW.
Also in January 2013, Brazil imported an average of 15.57 MMm3/d of LNG, all of which wasconsumed by the power sector. Petrobras appears to be supplying approximately 23–26 Mm3/d ofdomestic and Bolivian gas to the power sector, which allows 4,700–4,900 MW to be generated at alower price with the balance of 2,600–2,800 MW covered by LNG imports.
As of April 15, 2014, the water storage situation in the southeast of the country had not significantly
improved compared with the situation on March 13, 2014: reservoirs were filled to 36.91% ofcapacity36. Based on previous years, the south-eastern reservoirs should have been at 60–80% of
capacity by that time. With the dry season now approaching, it seems unlikely that the levels canrecover in 2014.
The lack of water storage implies the need to continue importing LNG. In 2014 Petrobras will have toimport seven to eight cargoes per month; some sources suggest 15 will be needed in the peakmonths37. According to Platts, Petrobras had already imported 1.2 mtpa in the period from December
2013 to March 2014 – in which month LNG imports reached a new record of 0.69 mtpa 38. Meanwhile,
the MME reports that imports in January 2014 totalled 0.26 mtpa, with Petrobras paying on average$14.53/MMBtu FOB (Figure 28).

36

http://www.ons.org.br/home/
http://www.hellenicshippingnews.com/News.aspx?ElementId=35dfc488-f6cf-4c04-a9e6-05ecbbaf6485
38
http://www.platts.com/latest-news/natural-gas/houston/brazil-lng-imports-hit-new-record-high-amid-drought-21430191
37

28

Figure 28: Breakdown of Brazil’s LNG imports by source*

Source: (Young, 2014)

Despite the volatility in gas-fired power demand, there are currently no underground storage projects
in Brazil. A study from San Paulo state research institute, IPT, suggested using 10 potential storagesites in an area in the state of San Paulo that is close to the Bolivia-Brazil pipeline39. In addition,
several nearly depleted gas/oil fields in in the Campos basin and onshore blocks in northeast Brazil
could be potentially used as gas storage; however, the high costs involved and the lack of aregulatory framework are impeding the development of gas storage projects in Brazil.

4.6 Gas Demand – LDCs franchise areas
The consumption of natural gas in the franchise areas of the LDCs nearly doubled from 2009 to2013 40 , increasing overall by approximately 11.8 Bcma and recording annual average growth of
15.84%. Most of the growth can be attributed to three or four LDCs – the others being too small tomake a significant difference. The largest gas distribution company, Comgas, holds an exclusive
franchise for the metropolitan area of Sao Paulo and neighbouring municipalities.
Figure 29: LDC gas sales, 2013 vs 2009

Source: (ABEGAS, 2014)

39
40

Iyomasa, 2004.
Figures do not include power generation.

29

4.6.1 Residential demand
Brazil has a population of 201 million and approximately 62.8 million households. The number ofhouseholds served with natural gas is just 2.44 million or 3.8% of the total. As of January 2014, there
were 28,227 consumers of natural gas in the commercial segment. The low penetration of natural gas
in the residential and commercial segments can be attributed to several factors: Brazil’s mild climate,
the lack of urban and household infrastructure, subsidies for LPG (which is main competitor of natural
gas in these two segments), high gas prices and the lack of funding from the smaller gas LDCs. The
general public knows little about natural gas and its intrinsic advantages – namely, that it is clean,secure and flexible.
Figure 30: Breakdown of residential consumers by region

Source: (ABEGAS, 2014)

4.6.2 NGVs
As of January 2014, Brazil had 1,162 NGV stations supplying natural gas to nearly 1.8 million
vehicles. While Brazil’s NGV fleet ranks among the five largest in the world, it remains rather
incipient, accounting for just 2.2% of the country’s 81 million vehicles. In 2013 alone, some 4.74
million new vehicles were licensed in Brazil41.

41(DENATRAN, 2014).

30

Figure 31: Historical growth of NGVs in Brazil

Source: (IBP, 2014)

In 2013 NGVs accounted for 6% (2 Bcma) of Brazil’s total gas consumption. The price of natural gas
at the pump is usually set at 60–70% of the price of petrol on an m 3/litre basis: in December 2013
natural gas at the pump cost R$1.792/m3 compared with BRL 2.841/litre of petrol and BRL1.932/litreof ethanol42.
Natural gas competes with ethanol in Brazil for the mantle of ‘greener’ transportation fuel. The adventof the flexi-car, which can burn any mixture of hydrated ethanol and petrol, gave a big boost to
ethanol and slowed down the conversion of cars to natural gas. In addition, after the Bolivia
nationalisation crisis in 2006 and amid renewed power-sector demand for gas from 2008 onwards,
information about the availability of gas for vehicles was contradictory, which scared off consumers
and reduced the momentum for car conversions.
Other factors contributing to the relatively low penetration of NGVs in Brazil’s fleet are:
 Lack of country-wide infrastructure with adequate network pressure (>10 bar) to deliver gas
efficiently to compressors at NGV stations; Continued reluctance among car manufacturers in Brazil, unlike in countries such as Italy andthe US, to fit the NGV kits before the car leaves the factory so (consumers are penalised bylosing their warranty once the car is converted to NGV; High-pressure cylinders occupying a large part of the car boot and still weighing quite a lot(‘the extra passenger’); Widespread concern in Brazil about the continuity of the NGV programme owing to
uncertainty about gas supplies; Most Brazilian buses are diesel-cycle, meaning that natural gas cannot be used as
standalone fuel (after two to five years, fleet owners resell buses to companies located in theinterior of Brazil, where many locations do not have NGV fuelling stations).

4.6.3 Industrial demand
As of January 2014, there were 2,815 industrial gas consumers in Brazil, of which 1,349 were locatedin the state of San Paulo 43 . Demand is highly diversified, with consumers across all industrial
segments: ceramics, glass, petrochemicals, steel, textiles, automakers and food and beverages, toname but a few.

42
43

(IBP, 2014).
(ABEGAS, 2014).

31

Figure 32: Breakdown of industrial energy consumption, 2012

Source: (EPE , 2013)

The industrial sector consumed 15 Bcma in 2013 44 but industrial demand for gas has stagnated since2011 owing to gas-price competitiveness and the plight of Brazilian industry, which has to endure highinterest rates, heavy taxation, competition from cheaper Chinese goods and the appreciation ofBrazil’s currency, the Real. At the same time, the lower gas price in the US has been detrimental forinvestment plans in Brazil: several energy-intensive industries have announced plans to build new
facilities on the US Gulf Coast. Looking forward, industrial gas demand in Brazil is forecast to grow to
up to 20 Bcma by 2025 at a CAGR of 2.3%.
Increased penetration in the industrial sector depends on the ability of natural gas to compete withwood and coal, both of which play a bigger role in the industrial energy mix – not least in regions
where gas infrastructure is under-developed.
Figure 33: Natural gas demand in industry – actual and forecast

Sources: (ABEGAS, 2014), (IBP , 2013), (EPE, 2013)

44

This figure does not include Petrobras’ refineries and fertiliser plants.

32

4.7 Natural gas infrastructure: The challenges of a continental country
As in the case of most emerging gas markets, Brazil lacks a comprehensive natural gas
infrastructure. At the midstream level, there are 9,240km of transportation pipelines and three LNG
terminals operated by Petrobras and 25,066km of distribution grids operated by gas distribution
companies and mostly concentrated in the states of Rio de Janeiro and San Paulo. By comparison,
Argentina has 15,437 km of transportation pipelines, 127,000km of distribution grids and two LNG
import terminals45,46 as well as 8.2 million consumers.
Table 5: Natural gas regional transportation and LNG infrastructure in Brazil (January 2014)
North
Northeast
SoutheastSouth
Mid-West
Total Brazil
Gas transportation pipelines
LNG import capacity (3 terminals)

48km
2835km19556km2424km
204km
25066km
9244km15.3 Bcma

Sources: (ABEGAS, 2014), (MME, 2014)

The Bolivia-Brazil pipeline, commissioned in 1999, runs 3,000km from Santa Cruz de la Sierra in
Bolivia to Porto Alegre in Rio Grande do Sul in southern Brazil, crossing five Brazilian states. It was
designed to carry 11 Bcma. In addition, a 362km and 1.0 Bcma pipeline links Bolivia to a power plantin the mid-western region of Brazil, while a 450km pipeline connects Argentina to a power plant built
by AES in southern Brazil. These two pipelines are currently idle owing to either lack of supply or
issues related to power plants.
Figure 34: Evolution of Brazil's gas transportation and distribution infrastructure

Source: (ABEGAS, 2014) (MME, 2014)

45
46

ENARGAS: http://www.enargas.gov.ar/Publicaciones/Informes/Anual/2012/Index.php
ADIGAS: http://www.adigas.com.ar/industria_datos.php

33

Brazil’s gas import capacity – both pipeline and LNG – is nearly 28 Bcma. There were trilateral
discussions to build an intercontinental pipeline linking Venezuela to Brazil and Argentina; but owing
to poor project economics and the lack of a strong project leader those plans came to naught.
So far, no new pipeline has been built in Brazil under the 2009 Gas Law. In fact, since mid-2010 only
150km of transportation pipeline have been added to the system.

4.7.1 The Bolivia-Brazil pipeline: Game changer
Bolivia and Brazil began discussing natural gas imports in the 1930s but the absence of key market
fundamentals and the lack of a strong backer postponed the project for decades. In 1987, promptedby Comgas, which wanted to secure natural gas supplies, the former Governor of San Paulo sent a
letter to the Minister of Energy requesting that negotiations on gas imports from Bolivia be restarted.
That request was opposed by Petrobras, whose policy was to drip feed natural gas supplies into
Brazil to avoid losing market share for its fuel oil – with its high sulphur content (up to 5%) and low
market value, HFSO was sold to industrial consumers, most of which were concentrated in Sao
Paulo47.
A Brazilian ministerial mission to Bolivia in 1988 ended in stalemate: Brazil promised only to help
Bolivia build gas monetization facilities – an iron ore plant and a petrochemical plant – on the Bolivian
side of the border. The impending end of Petrobras’ monopoly, combined with Comgas’ plans toimport LNG from Algeria, motivated Petrobras to re-launch negotiations with Bolivia in order to ensurethat it had full control over Brazil’s gas imports.
In 2003 Petrobras and Bolivia’s YPFB signed a gas supply agreement (GSA) for an initial volume of 5
Bcma. The following year Petrobras selected the equity partners for the pipeline company known as
TBG: the consortium BTB (comprising BG, BHP Billington and Tenneco/El Paso), in which Petrobras
had a 51% share. For the Bolivian pipeline company, the Gas Transboliviano S.A. consortium wasformed by Enron, Shell, and Bolivian pension funds. YPFB retained the role of gas aggregator with
Bolivian producers while Petrobras assumed the role of shipper and marketer of the gas in Brazil. In
1996–97 Petrobras signed gas supply agreements with five Brazilian LDCs. Construction began laterin 1997 and the first 2,000km to San Paulo were completed in 1999; the remaining 1,000km to thesouthern state of Rio Grande do Sul was commissioned in 2000.
The $2.1 bn project was financed by several multilateral agencies – the World Bank, the European
Investment Bank, Corporacion Andina de Fomento and the Inter-American Development Bank
contributed 40% – while Petrobras arranged another 40% with bilateral agencies and the equity
sponsors contributed 20%48. Its main features are:
 Total length: 3,150km, of which 2,593km in Brazil and 557km in Bolivia
 Contractual arrangements:o Transportation contract quantity (TCQ): initial contractual volume of 5.8 Bcmao Transportation capacity option (TCO): 2.19 Bcma of pipeline capacity in addition to
TCQ
o Additional transportation capacity: 2.19 Bcma of pipeline capacity in addition to TCQ
and TCO Gas off-takers: LDCs of the states of San Paulo (Comgas), Parana (Compagas), Santa
Catarina (SC-Gas), Rio Grande do Sul (Sulgas) and Mato Grosso do Sul (MS-Gas)
 Pipeline capacity: 11 Bcma

47
48

(Gomes, 1996).
(Law, 1998).

34





Diameter: 32 inches up to Sao Paulo, thereafter telescopic ending (20 inches in Rio Grande
do Sul)ToP of 80% for gas and 95% for pipeline capacity
Postal transportation tariff for all off-takers regardless of distance

Figure 35: Commercial structure of the Bolivia-Brazil pipeline project

Source: Adapted from (Law, 1998)

The project proved a game changer for the Brazilian gas industry. Facing a rapid increase in gas
supplies and hefty ToP obligations, the LDCs developed a substantial gas marketing campaign while
Petrobras came up with its own marketing initiative to help promote the use of natural gas in Brazil.
As a result, the share of natural gas in Brazil’s final energy consumption rose from 2.2% in 1998 to
7.2% in 2012.
The pipeline, however, remains closed to third-party access. In 2001 the ANP tried to allow open
access to the pipeline. BG, which owned the largest gas off-taker, Comgas, obtained a short-term
interruptible capacity contract under which it paid monthly charges of $5 million; however, it did not
succeed in securing capacity on the Bolivian side of the pipeline. More recently, buoyed by thepossibility of open access provided for by the 2009 Gas Law, Brazilian gas trading companies made abid to secure some capacity in the pipeline but were informed that Petrobras had just signed an
additional GSA of 2.24 m3/d with YPFB up to August 2014, which meant there was no spare capacity
or supply volumes49.
Post-2006 nationalisation, the Bolivian government strengthened YPFB’s role as the sole export
aggregator. As a result, Brazilian gas buyers cannot negotiate GSAs directly with private producers.

4.7.2 LNG infrastructure: Another game changer?
Brazil first toyed with the idea of importing LNG in the 1970s. Faced with the prospect of no domesticgas supply possibilities and the high costs of producing city gas from naphtha, Comgas started
discussions on building an onshore import terminal. The company acquired a plot of land in themunicipality of San Sebastiao (now a public beach) close to a major Petrobras oil terminal andlaunched talks with Algeria on LNG imports. Those talks stalled and were not revived until 1985 –before Comgas secured a 1.1 Bcma domestic gas supply contract with Petrobras. In 1999 BP and
Shell began carrying out separate studies on LNG-cum-power projects in Northeast Brazil. The
projects failed to materialize because it proved impossible to conclude the necessary GSAs to go
ahead with the construction.

49

Comment made during the CWC Rio Gas Forum on April 10, 2014 in Rio de Janeiro.

35

After Bolivia had nationalised its gas industry (in 2006), Brazil imported 50% of its gas supplies fromthe neighbouring country. Later Petrobras decided to follow a two-pronged strategy to diversify its
supply sources: increasing the share of non-associated domestic gas and developing LNG import
capacity.
There are currently three LNG import terminals in Brazil: the first was commissioned in 2009 in thestate of Ceara (northeast Brazil), the second in in Rio de Janeiro and the third in 2014 also in thenorth-eastern state of Bahia. Talks on a fourth terminal are under way. In April 2014 Petrobras and
Mitsui Group signed a MOU to carry out a study on building an LNG terminal in the country's
southernmost state, Rio Grande do Sul. The study is to be completed within 12 months. Besides it
trading capabilities, Mitsui is shareholder in seven gas LDCs in Brazil – in each case, in partnershipwith either a state government and Petrobras.
Table 7 immediately below shows Petrobras’ current LNG import capacity.
Table 6: Petrobras’ LNG import capacity
Terminal
Pecém-Ceara
Guanabara-Rio
JaneiroBahia-Bahia
Total

de

Capacity (Bcma)

FSRU supplier

Storage
(m3)

2.6
7.3

Golar Spirit
Excelerate
Excellence
Golar Winter

129,000
173,400

5.1
15.0

capacity

138,000

Source: Author’s research.

According to GASTECH News50, Petrobras’ lease of the Golar Spirit will end in 2018 and the Golar
Winter in 2024. The 15-year lease for Excelerate ends in 2029.
In 2012 Petrobras announced the lease of two Excelerate LNG carriers – Excelsior and Excalibur,
each of which has a capacity of 138,000m 3. This allows the company to import LNG on an FOB basis.

4.8 Natural gas prices
Brazil has a hybrid gas-pricing regime: producers, importers and transporters come under thejurisdiction of the ANP, while the gas LDCs are regulated by the regulatory agencies of the individualstates. Producers and importers are able to freely negotiate gas supply prices with gas LDCs andpotential free consumers. Imported gas prices are determined by the price formulae of the various
GSAs, while Petrobras and other producers can freely negotiate the price of domestic gas.
Before the enactment of the 2009 Gas Law, gas transportation companies (aka Petrobras) were free
to negotiate transportation tariffs. The Gas Law stipulates that new pipelines are subject to tender andthe winning bid is the one offering the lowest tariff. The ANP can intervene to mediate conflicts
between suppliers and buyers.

50

http://www.gastechnews.com/lng/petrobras-starts-up-brazils-third-fsru-import-facility/36End-user gas prices in Brazil are high compared with those in other South American andeven European markets: large industrial consumers pay in excess of $16/MMBtu, whereas
residential consumers pay $30-$50/MMBtu. Domestic gas prices at the wellhead and city gate are notregulated and range between $8/MMBtu and $12/MMBtu. Although these prices seem very attractive
for gas producers and importers, it is uncertain whether other suppliers will be able to access themarket place owing to the continued de facto monopoly in the pipeline infrastructure.
Domestic gas pricing is non-transparent: prices are bundled at the city gate and do not discriminate
between the commodity and transportation components. Despite 70% of Brazil’s gas being
associated with oil and produced up to 300km from the consuming regions, domestic gas is more
expensive than gas imported from Bolivia and has to be transported up to 3,000km to reach endusers. Following a campaign led by consumer associations and gas LDCs, Petrobras has begun
granting a provisional discount on domestic gas.
Figure 36: Natural gas pricing structure and competencies in Brazil

Source: Author’s research

The Bolivian gas price is formed of two components 51:
P city gate = Pg (Gas commodity price at Rio Grande, Bolivia) + T t (Transportation tariff, postal)
The commodity price is readjusted 50% quarterly and 50% every six months and is indexed to abasket of fuel oils (50% HSFO and 50% LSFO). The transportation tariff, which has a capacity
component and a throughput component, is readjusted annually in accordance with the US
purchasing price index (PPI).
Petrobras is currently the sole importer of LNG in Brazil and pays market prices. It imports only LNG
to supply power plants. Following an acute power shortage and electricity rationing in 2001, thefederal government established an emergency power programme (PPT) whereby power plants

51(Gomes, 1996).

37

commissioned by December 31, 2004 were to benefit from lower gas prices for 20 years. The priceformula for PPT plants was set as following:
Price in Brazilian Real = 2.581 $/MMBtu * exchange rate (R$2.3436/$)52
The price is readjusted annually as follows: 80% in accordance with US PPI and 20% Brazil’s
wholesale price index IGPM-FGV. A compensation account is used to take into account variations in
the exchange rate over 365-day periods.
Nineteen gas-fired power plants were built under the PPT regime, of which most now belong toPetrobras. The average contract price for PPT plants in 2013 was $4.56/MMBtu. It is unclear whether
Petrobras is selling LNG to all its PPT plants at the lower and possibly subsidised prices. A
newspaper article hinted that Petrobras had claimed that its supply commitment to PPT plants wasjust 12 MMm3/d, of which 60% was delivered to its own power plants53. Table 8 immediately below
lists the gas-fired power plants owned by Petrobras.
Table 7: Gas-fired power plants owned by Petrobras as of December 2013
Power plant

Capacity(MW)

PPT
commitment(MW)

Variable
cost(R$/MWh)

Unit
consumption(m3/d)

A. Chaves
Barbosa L
E. Rocha
F. Gasparian
L. Brizola
L. Prestes
M. LagoS. Tiaraju
R. Almeida
C. Furtado
TermoCeara
Total

226
379
250
565
1058
385
923
161
138
186
242
4513

212
349
206
357
998
241
885
147
125
150
217
3887

102.84
92.2
98.96
70.16
147.74188.54719.99N.A.
58.89
258.85
37.8

4.36
5.86
5.28
5.02
4.89
7.46
5.86
4.37
6.24
7.40
6.56

Gas
consumption at
80% load factor(MMm3/d)
0.79
1.78
1.06
2.27
4.11
2.30
4.33
0.56
0.69
1.10
1.27
20.26

Source: (MME, 2014)

Figure 37 compares Brazil’s wholesale gas prices with international gas prices as of December 2013.
It is worth noting that gas prices in Brazil are similar to and, in some cases, even higher thanwholesale prices in Europe54. LNG prices ex-regas approach oil parity, while domestic gas prices
without discount are 20% higher than NBP prices. The average cost of supply in Brazil is$10.29/MMBtu (excluding tax as of December 2013) based on a mix of Bolivian gas, regasified LNG
and domestic gas with discount. The price of the mix increases to $12.21/MMBtu if Petrobras decides
to withhold the discount for domestic gas.

52

(ANP, 2010).
http://www.eletrosul.gov.br/gdi/gdi/index.php?pg=cl_abre&cd=gnlgeh8:%7DVehe54
Prices are excluding tax.
53

38

Figure 37: Wholesale gas prices in Brazil compared with international prices

Sources: Author’s research and (MME, 2014)

Regulation at the state level allows LDCs to pass through supply prices to end-users and charge a
distribution margin that takes into account the depreciation of the assets base, ongoing investments
as well as operational and financial costs. The margin is adjusted annually to take into accountinflation. Some regulatory agencies provide for a five-year margin review process and impose
efficiency conditions.
Figure 38: Natural gas prices in Brazil: Wholesale vs end-user (December 2013)

Sources: (MME, 2014) MME (2014) and author’s estimates

Natural gas prices to end-users are subject to federal taxes, including a 9.25% social contribution tax(PIS/COFINS) and VAT charged at 12–25% depending on the legislation of the individual state. For
example, in addition to the $12.53/MMBtu price, a large consumer will pay 27% in state and federal
taxes, some of which is not recoverable.
Figure 38 above compares wholesale and end-user gas prices as of December 2013. Except in thecase of PPT plants, end-user prices are not subsidised and all costs, margins and taxes can bepassed through.

39

There is no uniform gas distribution tariff in Brazil. Each state allows its LDCs to charge margins on a
cost-of-service basis. In general, prices for industrial consumers are set to compete with HFSO, while
NGV prices are offered at a discount to petrol prices. Smaller industries pay much more than HFSO
prices because they have few alternatives, are under pressure from environmental agencies to meet
air quality standards and are located in places where they cannot stock liquid fuels.
Table 8: Natural gas and fuel prices to end-users
Prices ex-tax ($/MMBtu) 55

Northeast

Southeast

Small industry (>2,000 m3/d)
Medium-sized industry (>20,000 m3/d)
Large industry (>50,000 m3/d)
NGVs
Residential
Power plant (PPT)Petrol pump prices
LPG
Fuel oil

11.19
11.14
10.41
15.93
22.13
4.56
25.99
23.80
11.14

17.20
13.09
12.53
14.79
37.99
24.99
25.99
11.07

Source: (MME, 2014)

Although the regulation in some states allows consumers above a certain threshold of gas usage tobe free to choose their suppliers, there is little incentive for a consumer to be ‘free’. This is because ,the only gas supplier is Petrobras and the ‘free consumer’ is obliged to pay a distribution margin,
which is usually the same as that paid by regulated consumers.
Figure 39: Increasing gap between power and gas (domestic and imported) prices

Source: (ANP, 2010)

The consumption of power plants is expected to increase as the economy slowly recovers. As long as
the dry period continues, the gap between electricity wholesale prices and regulated PPT prices is
expected to grow; and, with it, Petrobras’ losses. This may explain why domestic gas prices are as

55

End-user prices include taxes; w. Wholesale prices are excluding tax.

40

high as Continental European prices; indeed, it looks as if the price paid by PPT power plants is being
cross-subsidised by other consumer segments.
The marginal operation cost shot up from $105/MWh in early December to $202/MWh in the last
week of January 2014. Meanwhile, the spot power price in April 2014 reached $373/MWh.
While gas supply prices in Brazil are sufficiently high to attract private producers, the penetration ofnatural gas in the industrial sector is hampered by those high prices. There is not much room for gas
to compete with oil products because most of Brazil’s industries have already converted from fuel oil
to natural gas and other fuels. According to Brazil’s 2013 Energy Balance 56 the country’s total
consumption of fuel oil was equivalent to only 3 Bcma in 2012 – most consumers being located inregions without gas infrastructure.
Figure 40: Breakdown of fuel consumption by Brazilian industrial segment, 2012 vs 2003

Source: (EPE , 2013)

Natural gas prices for Brazilian industry seem to have reached saturation levels: growth in thissegment has been very limited since 2011. Owing to high gas prices, some energy providers are now
offering pulverized biomass-to-boiler and wood-furnace solutions to compete with natural gas. The
end-user price of natural gas is much higher in Brazil than in the US, Argentina and even the UK (butis lower than in Chile, which is a net energy-importing country).

56(EPE , 2013).

41

Figure 41: Comparison of natural gas end-user prices, Q1/2012

Sources: (Kozujl, 2012) and author’s research

5. Gas Production Outlook for the Period 2020–30
Petrobras is the main player in Brazil’s oil and gas industry. The state-owned company dictates thepace and quantum of the production of both types of fuel. It should be noted that most foreign oil
companies are partners of Petrobras in prospective key areas such as the equatorial margin and presalt.
On July 26, 2011 the former President of Petrobras, Jose Sergio Gabrielli, announced a very bullish
outlook for Petrobras and Brazil’s oil and gas production, which was included in the Petrobras 2020
Strategic Plan.
Figure 42: Petrobras investment plan for 2011–15 ($ bn)

Source: Petrobras 2020 Strategic Plan

42

According to Gabrielli’s 2011 presentation, Petrobras planned to invest $224.7 bn during the period
2011–15 – more than half of which in the E&P segment. This equates to nearly $45 bn annually,
compared with Shell’s $25–27 bn per year in its 2011–14 investment plan57.
Petrobras’ ambitious plan included investment totalling $13.2 bn in the Gas and Power segment,
including pipelines, gas distribution, fertilizer plants, another two LNG import terminals and hydro- andthermal power plants. This demonstrates Petrobras’ increased appetite to become a major integrated
oil & gas company. To achieve that end, it planned to use third-party resources (debt) to fund 36% of
its four-year investment needs.
The 2011–15 plan also envisaged $127.5 bn in E&P, of which $64.3 bn was allocated to pre-salt – ajump of nearly 100% compared with the 2010–14 business plan (which earmarked $33 bn for pre-salt
expenditure). At the same time, it foresaw hydrocarbon production increasing to 6.42 MBOE/d in 2020
from 2.77 MMBOE/d in 2011. Domestic oil production is forecast to increase to 4.91 MMbbl/d by2020 and domestic gas production to 1.12 MMBOE/d (68 Bcma) from 435 MBOE/d over the same
period. In 2012 the plan was revised down with projected oil production in 2020 at 4.2 MMbbl/d.
Petrobras’ 2030 Strategic Plan, approved by the board of directors and announced in February 2014,
offered a much more conservative scenario, with average Petrobras production of 2.9 MMbbl/d in the
period 2013–20 and 3.7 MMbbl/d in the period 2020–30 – a significant reduction compared with the
2011–15 plan. For the first time, Petrobras provided an overview of third-party production in Brazil,
forecasting total oil production of 5.2 MMbbl/d in the period 2013–20. Petrobras’ target for its own
production level by 2018 is 3.2 MMbbl/d58.
The 2030 Strategic Plan foresees investment totalling $220 bn for the period 2014–18, of which$153.9 bn is earmarked for E&P – $80 bn in pre-salt and $10.1 bn in Gas & Energy. Indeed, despite
reported financial problems, Petrobras is still planning to spend a staggering $45 bn/year, which it willcontinue to be hard pushed to achieve.

57

http://s05.static-shell.com/content/dam/shell/static/investor/downloads/news-and-library/2011-strategywebcastmediapresentation.pdf
58(Foster, 2014).

43

Figure 43: Petrobras production forecasts, 2014 vs 2011 plan

Sources: (Foster, 2014), (Gabrielli, 2011)

Although the various five-year plans provide a very high investment profile – more than $220 bn – theproduction targets for 2020 have slipped from 4.9 MMbbl/d to 3.7 MMbbl/d of oil & condensates. Thishighlights the increase in costs and project-management difficulties facing the company.

5.1 Natural gas supply-demand outlook
Brazil’s domestic gas production increased on average 7.3% annually from 2000 to 2012, while
average annual demand growth during the same period was 9.9%59. As mentioned above, Brazil
started to import pipeline gas from Bolivia in 1999; there followed imports from Argentina from 2000
onwards and LNG imports from 2009.
In 2009 Argentina stopped supplying gas to Brazil owing to dwindling domestic gas supplies, whichcaused the shutdown of the AES 640 MW Uruguaiana power plant, located near the Brazil-Argentina
border. The same year Brazil started to import LNG to complement the volumes imported from
Bolivia and to increase the diversity and security of supply.
In 2013 the volume of gas imported into Brazil exceeded the volume of domestic supply by 7.5%. Will
this trend continue? As a matter of fact, gas imports exceeding domestic supply is the norm rather
than the exception – only in 2011 and 2012 was the volume of domestic supply larger than that ofimports. And according to the Ministry of National Integration, the dry period will continue until 2015,
requiring additional (‘flexible’) LNG imports.

59(BP , 2013).

44

Figure 44: Evolution of domestic and imported gas supply in Brazil

Source: (MME, 2014) (ANP, 2008)

In 2013 domestic supply accounted for only 48% of the total consumption of natural gas in Brazil,
compared with 54% in 2011. LNG’s contribution to the energy mix rose from 3% in 2011 to 16% in
2013. LNG is sourced primarily to meet part of the flexible power generation demand which has no
firm gas supply agreement – according to the MME this flexible power demand is 3500-4000 MW.
Figure 45: Sources of natural gas supply in Brazil, 2013 vs 2011

Source: (MME, 2014)

Until 2009 natural gas consumption in Brazil was loosely correlated with GDP owing to the
preponderant contribution of the industrial sector. However, since 2010 this correlation has decoupledbecause of growing demand from the power sector, where the dispatch of gas-fired power plants
depends on the seasonal factor and not necessarily on economic fundamentals. For example, in2009 Brazil’s GDP shrank only 0.3% as the country was reasonably protected from the world
economic crisis. However, gas consumption dropped 24% because the exporting industrial sector
was negatively affected by waning demand in foreign importing markets. In 2010 both Brazil GDP andgas consumption rebounded strongly, but the following year growth in consumption was hit by a45

shrinking domestic economy and the lack of competitive domestic gas supplies. The growth inconsumption in 2012 and 2013 can be attributed to the increased dispatch of gas-fired power plants
met through LNG imports.
Figure 46: GDP vs gas demand growth in Brazil, 2001–13

Source: (ANP, 2008) (MME, 2014)

Following the 2014 changes in its investment plan and the announced delays in reaching ambitious oil
production targets, Petrobras issued a revised supply and demand forecast for natural gas. Gas
demand was revised downwards from 73 Bcma to 52 Bcma in 2020 owing to the substantial reductionin Petrobras’ planned investment in power generation, fertiliser plants and other downstream projects.
Domestic gas supply, meanwhile, is projected to drop from 37.2 Bcma to 31.2 Bcma in 2020.
In both of the above scenarios, domestic supply will be insufficient to meet demand and Brazil will
have to continue to import LNG and gas from Bolivia. This will be the case through 2020-25.
Figure 47: Petrobras scenarios for natural gas supply and demand

Source: (Foster, 2014)

According to Petrobras’ and other industry projections, the supply of domestic natural gas is expected
to reach 31 Bcma in 2020, after deducting the volume required for Petrobras’ internal use and46

reinjection. The Bolivia-Brasil GSA will expire in 2019, and it is expected that Petrobras will soon startnegotiations on renewing the contract. Petrobras’ supply projections suggest Bolivian imports willremain at the same level as today – around 11 Bcma – although it is questionable whether Bolivia’s
reserves will meet those requirements. Meanwhile, Petrobras has announced its intention to invest in
new gas exploration areas in Bolivia in an attempt to reverse the decline in its neighbour’s gas
reserves.
In addition to its 11 Bcma contract with Brazil, Bolivia’s YPFB has signed two supply agreements with
Argentina’s ENARSA: a firm supply contract with the obligation to deliver 13.9 Bcma by April 2015
and an interruptible contract under which 1.2 Bcma was delivered in 2013. According to YPFB, thefirm contract with ENARSA expires in 2026 and provides for maximum annual supplies of 9.9 Bcma,
subject to Argentina’s expanding its transmission system in the northern part of the country toaccommodate additional volumes.
If Bolivia increases gas supplies to Argentina to 7.3 Bcma in 2019 and maintains the same contract
volume for Brazil as well as the same level of supplies to its domestic market and for E&P uses (4.3
Bcma), it would need to increase its reserves from the current 11 Tcf to 16 Tcf in order to commit to
20-year gas supply agreements.
The supply-demand forecast shown in Figure 48 below assumes the following scenarios for the
supply of gas from Bolivia and overall gas demand in Brazil:
 Supply Scenario 1: Bolivia’s GSA with Brazil is renewed for 20 years with the same contract
volumes as in the existing contract (11 Bcma)
 Supply Scenario 2: Bolivian annual supplies to Brazil drop to 5 Bcma
 Inflexible Demand Scenario: firm demand from industry, the residential sector and NGVs andinflexible power demand of 4 Bcma Flexible Demand Scenario: Additional volume of 13.8 Bcma for flexible power plants
Under Supply Scenario 1, Bolivian and domestic gas combined will be sufficient to meet all inflexible
power demand. LNG imports to meet flexible power demand could be as high as 7 Bcma in 2018,
dropping to 5 Bcma in 2020 as more domestic gas becomes available.
Under Supply Scenario 2, part of the firm demand will not be met by Bolivian and domestic gas, whichmeans additional imports of LNG – totalling 13 Bcma in 2018 and 11 Bcma in 2020 – will be required
to meet firm and flexible commitments. In 2025 the gap is expected to reach 12 Bcma. If Petrobras
revises its oil-production forecasts downwards once again, the likely outcome will be not only
increased LNG imports but also some demand destruction in the industrial sector owing to pricecompetitiveness issues.

47

Figure 48: Natural gas supply-demand outlook in Brazil, 2013–25

Sources: Author’s estimates, (Foster, 2014), (IBP , 2013) & (EPE, 2013)

5.2 Spot LNG: Expensive alternative for power generation
Owing to uncertainties over the dispatch of thermal power plants, Petrobras has been buying
increasing volumes of LNG in the spot market or under short-term contracts.
Petrobras imports LNG FOB mainly from Trinidad & Tobago, Nigeria and Norway and has received
several reloads from Europe. According to the MME, as of November 2013 Petrobras had spent $2.8
bn on importing 3.8 mtpa at an average FOB price of $14.19/MMBtu. If freight and regas fees areadded, the total bill for 2013 could be as high as $3.5 bn. In February 2014 the average FOB pricepaid by Brazil was $14.53/MMBtu.
According to GIIGNL60, Brazil imported 4.15 mtpa in 2013 – an increase of 1.7 mtpa over 2012. In
addition to supplying Brazil’s domestic market, Petrobras is buying cargoes for their international
trade operations that do not necessarily involve Brazil. Besides Petrobras, there are several niche
players in Brazil that have been trying to develop LNG import schemes to supply their own power
projects. However, they have been deterred by the high price of LNG and have yet to provide LNG
sellers with acceptable buyer credit guarantees.

60(GIIGNL, 2014).

48

Table 9: Brazil’s LNG imports and re-exports

LNG imports
2009
2010
2011
2012
2013
Jan 2014
LNG re-exports
2011
2012
2013

Volume (mtpa)

LNG average price FOB($/MMBtu)

0.33
2.2
0.56
2.32
3.78
0.26

5.44
6.94
12.69
12.56
14.19
14.53

0.04
0.23
0.03

15.40
11.53
16.61

Source: (MME, 2014)

Despite buying increasing volumes of LNG and still enjoying an investment-grade credit rating 61 ,Petrobras is paying ever higher prices for LNG, as shown in Figures 49 and 50 below. Indeed, both
Brazil and Argentina seem to be paying Asia-equivalent prices for LNG at a 40–50% premium over
NBP and even higher prices than North Asia, given that most cargoes to South America originate in
Trinidad & Tobago.
Figure 49: Average DES prices of LNG as of November 2013

Source: Adapted by author from (FERC, 2013)

61

BBB- (Standard & Poor’s).

49

Figure 50: Brazil’s LNG import volumes and LNG FOB prices

Source: (MME, 2014)

There are a few alternatives to reduce Brazil’s cost of LNG supply
1. Petrobras signs a long-term supply and purchase agreement for one of the brown-fieldliquefaction projects currently being developed in the Gulf Coast. This would enable
Petrobras to procure LNG under a cost-plus pricing scheme rather than a market-based one.
o Under the terms agreed with other buyers, the price of LNG FOB would be:
PFOB = 1.15 to1.25HH + $3.0
o At HH = $5/MMBtu, the FOB price would range from $8.75/MMBtu to $9.25/MMBtu.
2. Brazil introduces long-term policies encouraging the development of domestic production.
This would make it likely that gas supplies at the city gate would cost $7–8/MMBtu.
Table 1 shows the potential savings for each one of these approaches.
Table 10 : Gas sourcing options: Costs and savings (LNG imports vs domestic gas)
1. Business as usual
Spot LNG
5 Bcma, 3.8 mtpa
$14.5/MMBtu FOB$17.7/MMBtu regasified
Annual cost: $3.1 bn

2. US Gulf LNG SPA
20-year SPA
5 Bcma, 3.8 mtpa
$8.75–9.25/MMBtu FOB$12.25–12.75 regasified
Annual cost: $2.1–2.2 bn
Annual savings: $0.9–1.0 bn

3. Domestic gas
20-year SPA
5 Bcma$7–8/MMBtu city gate
Annual cost: $1.2–1.4 bn
Annual savings: $1.7–1.9 bn

Source: Author’s estimates

Over 20 years, the implementation of the supply-sourcing alternatives shown in Table 10 would allow
Brazil to save $18–38 bn, assuming Henry Hub remains at $5/MMBtu for the life of the LNG supply
agreement. These savings are equivalent to 9–19 years’ revenues from Brazil’s largest power plant –the 14,000 MW Itaipu – which is also the second-largest power plant in the world and is shared by
Brazil and Paraguay62.

62

http://memoria.ebc.com.br/agenciabrasil/noticia/2012-12-28/receitas-de-itaipu-ajudarao-garantir-reducao-media-de-20-natarifa-de-energia

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6. Brazil and South America: Markets and Connectivity
The countries in the Southern Cone of South America are relatively well interconnected by pipelines
and a growing number of LNG terminals. However, there is no such connectivity in the northern partof the continent.
A total of 13 international gas pipelines and six LNG import terminals are to be found in the SouthernCone, while one LNG terminal is under construction and another planned:
 7 pipelines connecting Argentina to Chile, designed to transportation a total of up to 17 Bcma
 1 pipeline connecting Bolivia to Argentina, capacity of 6 Bcma (increasing to 10 Bcma in2015)
 2 pipelines connecting Bolivia to Brazil, combined capacity of 13 Bcma
 2 pipelines connecting Argentina to Uruguay, with a combined capacity of 4.7 Bcma
 1 pipeline connecting Argentina to Brazil, capacity of 4 Bcma
 2 floating LNG import terminals in Argentina
 2 LNG import terminals in Chile, with another one planned
 3 floating LNG terminals in Brazil, with studies into a fourth under way
 1 LNG terminal being built in Uruguay
In addition, Peru LNG is the first LNG plant to have been built in South America, but its production has
been directed to Mexico and Asia. Peru and Chile have a number of unresolved political issues thathave so far prevented gas trade between the two countries. Meanwhile, Bolivia and Chile have adifficult relationship as the former claims a part of latter’s territory that would give it access to the sea.
In 2003 a consortium formed by BG, Pan American Energy and Repsol proposed a pipeline-cum-LNG
project linking Bolivia and Chile (Pacific LNG). The project was an attempt to monetise the large gas
resources found in Bolivia’s Caipipendi region located a long way from the Bolivia-Brazil pipeline,
which was controlled by Petrobras. Indeed, the possibility of exporting to Chile was the trigger for
intense social unrest in Bolivia and led to the resignation of two of the country’s presidents63.
In 2006 Venezuela and Brazil started discussions on building a Pan-American Pipeline or North-SouthGas Corridor. The proposed project entailed a 9,000km pipeline with a capacity of 55 Bcma
connecting Venezuela, Brazil and Argentina and at the same time incorporating Peru and Bolivia. The
project has never been implemented owing to the sheer volume of investment required, weakeconomic fundamentals, lack of leadership and the environmental challenge of crossing the
Amazonian rainforest.
Until 2004 Argentina exported gas to neighbouring countries on a regular (uninterrupted) basis. That
year the decision of the Argentine government to devalue the local currency and unpeg gas prices
from the US dollar resulted in those prices dropping 70%; consequently, an increase in domestic
demand could not be met by gas producers who were being paid very low Peso-denominated prices
at the wellhead. Facing a gas shortage in the domestic market, the Argentine government issued anadministrative ruling whereby gas could be exported only if domestic demand had been met. This wasfollowed by the introduction of very stiff export taxes that made it uncompetitive to import gas from
Argentina.

63

http://www.libertaddigital.com/mundo/informe-el-plan-para-exportar-gas-detonante-de-la-crisis-1276204322/

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Argentina went on to suspend exports to all three of its export markets (Chile, Uruguay and Brazil),
except for small volumes supplied to residential consumers in Chile and Uruguay. Chile, whichsuffered most owing to the lack of alternative supplies, immediately started soon to develop LNG
import projects. Uruguay followed Chile’s example, but its single LNG import project has beendeveloped at a slower pace.
The impact of the Argentine gas-export moratorium on Brazil was less severe because that country
had imported smaller volumes to supply a single customer – an AES power plant built on the BrazilArgentina border (Uruguaiana). However, the owner of the power plant made huge losses because it
was not competitive to dispatch power using diesel as a replacement fuel.
Figure 51: Gas infrastructure and interconnectivity in the Southern Cone

Source: Adapted by the author from (Rudnick, et al., 2007)

Meanwhile, the Bolivia-Brazil pipeline has been operating relatively smoothly since July 1999. The
pipeline, the largest in South America, is 3,150km long (of which 557km are in Bolivia) and supplies
gas to five states in south-eastern and southern Brazil. The first section of the pipeline (some 2,100km) was commissioned in less than two years.

52

Figure 52: The Bolivia–Brazil Pipeline

Source: http://www.tbg.com.br/ra2012/tbg.html

Despite the 2006 nationalisation of Bolivia’s natural gas industry, which caused a hike in the wellhead
price, there has been no interruption of supply in the 15 years in which it has been operating.
However, the slowdown in E&P investment together with the resulting drop in gas reserves raises thequestion of whether Bolivia will be able to maintain its current level of exports to Brazil and Argentina
when its contract with the former expires in 2019.
Figure 53: Bolivia’s gas balance, 2013

Source: (MME, 2014)

According to the CEO of YPFB, Carlos Villegas, speaking at the recent annual meeting of the Ministryof Hydrocarbons, Bolivia would be able to export up to 9.5 Bcma if Argentina were to invest in
developing the gas infrastructure on its side of the border. He revealed that the contractual volume
agreed by YPFB and ENARSA is 6.9 Bcma firm and 1.2 Bcma interruptible.
For its part, Argentina has been steadily increasing its imports of pipeline gas and LNG ever since it
has been unable to stop the decline in domestic gas production (a decrease of 12.3% since 2003,53

while domestic demand has increased 21% in the same period). In 2013 it imported 12.3 Bcma, of
which 4.9 mtpa was LNG. Owing to the issues of credit rating and currency availability, most of the
LNG is purchased via short-term tenders. On average, Argentina paid $17–20/MMBtu in 2013.
Figure 54: Argentina’s gas balance, 2013

Source: (MME, 2014)

There is currently little hope of increasing natural gas trading between the countries of the Southern
Cone of South America or even developing better interconnectivity. This is because the key regional
markets are all net importers and increasingly dependent on LNG.
Figure 55: Evolution of natural gas production in Argentina, Brazil and Bolivia

Source: (BP , 2013)

Although Brazil and Bolivia have ramped up production since 2009, volumes are still insufficient tomeet regional market demand without resorting to LNG imports.

54

Moreover, geopolitical factors are an obstacle to further natural gas integration in the region,
particularly the long-term border issues involving Chile, Bolivia and Peru. It would be both logical andcheaper for Chile to import gas from Bolivia or LNG from Peru, instead of Trinidad & Tobago or
Equatorial Guinea.
Combined, the Southern Cone countries aggregate to a sizeable gas import market that traded morethan 33 Bcma in 2013 – a volume that is nearly equivalent to that of the individual markets of
Malaysia, Spain or The Netherlands. All Southern Cone countries import gas at market or contract
prices; and despite the disruption caused initially by the nationalisation of gas assets in Bolivia andArgentina, there has been no interruption in supplies since Argentina suspended exports.
In the meantime, GDF Suez and Marubeni won a tender to install a 3.6 mtpa FSRU in Uruguay (GNLdel Plata). The terminal is due to be commissioned in 2015, with a bridging solution provided by GdF
Suez Neptune, while a 263,000 m 3 storage facility is expected to begin operating in 2016. Besides
supplying the Uruguayan market, the unit could export to Argentina via the Cruz del Sur pipeline,
which connects the two countries and was originally built to export gas from Argentina.
In 2012 Chile’s Gas Atacama awarded a contract to Golar for the Gas Atacama Mejillones FSRU,
which is to be located near the existing terminal of Mejillones in the north of Chile. The initial term of
the contract, in Gas Atacama's option, is for 15 years. The FSRU will have a storage capacity of
170,000 m3 and will deliver 5 MMm 3/d of regasified LNG64. As a result, the total regasification capacityof the Southern Cone will reach 34.5 Bcma in 2016 (see Table 12 immediately below).
Table 11: LNG import capacity of the Southern Cone, 2016
Country

LNG regasification capacity(Bcma)

BrazilArgentina
Chile
Uruguay
Total

15.0
9.9
6.0
3.6
34.5

Sources: Author’s research, companies’ websites

There is a strong push for LNG in the Southern Cone, but the main importing markets – Brazil andArgentina – are unwilling to enter into long-term supply agreements. In Argentina, the credit rating andlong-term payment capability of the sole buyer, ENARSA, seem to be deterrents to long-term
contracts. In Brazil, uncertainty about demand from the power sector mitigates against such contracts,
as does, possibly, the unwillingness of Petrobras to burden its balance sheet.

64

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html

55

Figure 56: Natural gas imports and exports in the Southern Cone (Bcma), 2013

Source: Adapted by the author from (BP , 2013), (MME, 2014) & (International Gas Union, 2013)

7. Can Unconventional Gas Play a Role in Brazil?
In 2013 the Energy Information Agency (EIA) of the US Department of Energy (DOE) commissioned a
study from Advanced Resources International (ARI) on the potential of shale gas and shale oil in 41
countries and 95 shale basins. The ‘World Shale Gas and Shale Oil Resource Assessment’concluded that Brazil has the 10th largest technically recoverable shale gas resources in the world –245 Tcf, which is 15 times more than its proven conventional gas reserves as of December 2012.
Table 12: Technically recoverable shale gas resourcesCountry

Tcf

US
China
Argentina
Algeria
CanadaMexicoAustralia
South Africa
RussiaBrazilOthers
Total

1161
1115
802
707
573
545
437
390
285
245
1535
7795

Source: (Kuskraas, 2013)

The ANP has also conducted a preliminary assessment of Brazil’s potential resources of shale gas,including observation ‘in loco’ of gas flaring and seepage on the surface in several regions. Although56the agency did not validate the EIA /ARI’s figure of 245 Tcf, it provided its own estimate of 288 Tcf inareas that ARI had not included in the study. Thus Brazil’s technically recoverable shale gas
resources could range from 245 Tcf to 533 Tcf. If just 10% of Brazil’s shale gas proved commercially
viable, Brazil’s proven gas reserves would double. And even at prices higher than those in the US, it
might still be competitive with offshore gas and imported LNG.
Table 13: Breakdown of Brazil’s potential shale gas resources by basin
Basin

Tcf

Parnaiba

64

Parecis124

Reconcavo

20

Sao Francisco

80

Parana (EIA/ARI)

245

Total

533

Source: (Chambriard, 2013)

Unfortunately, as Figure 57 below shows, most of the identified resources are located in regions thathave no gas transportation infrastructure and are located a very long way from energy demand
centres.
In November 2013 ANP auctioned 240 onshore gas blocks. The tender was scheduled to take placeover two days but lasted only one day owing to the sheer lack of interest. Only 72 blocks wereawarded, of which 49 went to Petrobras. Of the 21 companies that pre-qualified to bid, only 12
participated in the auction. And of those, only four were foreign companies: Alvopetro (Colombia),
GDF Suez (France), Geopark (Bermudas) and Trayectoria (Panama). The reasons for the lack ofinterest is due to the uncertainties surrounding onshore gas in Brazil:
 Most blocks were located in remote regions or in producing areas that are close to depletion; The ANP has not yet issued regulations allowing hydraulic fracturing (those rules were still
subject to public consultations at the time of bidding);
 Government studies suggested that several blocks overlap with environmental conservation
areas and hydroelectric reservoirs, meaning it will be difficult to obtain environmental permits;
 It is uncertain whether shale gas can be used for power generation – the price set by thegovernment at recent power auctions is too low to encourage gas producers;
 Independent companies, which were the engine for the success of the US shale programme,
are facing their own economic challenges in the US and seem no longer interested ininvesting abroad; Brazil’s unattractive fiscal regime, including very high local content, is an obstacle to importing
available drilling rigs and does not acknowledge the need to import components crucial forhydraulic fracturing.

57

Figure 57: Overview of onshore unconventional gas blocks in Brazil‘s November 2013 tender

Source: (Chambriard, 2013)

The main challenge to the development of shale gas in Brazil remains the lack of in-house knowledge
and equipment to develop those resources as well as insufficient transportation infrastructure to get
the product to markets. For its part, the Brazilian Institute of Petroleum, Natural Gas and Biofuels(IBP) believes that Brazil is at least 10 years away from developing its unconventional gas
resources65.
There is little hope that Brazil will hold exploration bids in 2014, given that the country is holding theWorld Cup in June/July and presidential elections in October. After three bidding rounds having takenplace in 2013, it seems that the virtuous circle of annual bidding rounds may have been broken once
again.
In summary, Brazil seems to have the resource base to develop shale gas. However, the sheer sizeof the country, insufficient knowledge about the gas in place, nascent infrastructure and the lack of
incentives provided by the government could mean that shale gas will not developed until beyond
2025.

8. Conclusions and Insights
The main conclusion of this paper is that Brazil will not become an LNG exporter in the foreseeable
future but rather will remain a lucrative market for LNG sellers. As long as LNG supply continues tobe tight, sellers will be able to carry on charging prices as high as those paid by north Asian buyers,65

http://uk.reuters.com/article/2013/11/28/uk-brazil-oilauction-idUKBRE9AR0P420131128

58

Together, Argentina and Brazil are an increasingly important market for natural gas imports – which
exceed 30 Bcma. In 2013 the combined import of LNG from these countries reached 9.1 mtpa andthe trend is likely to be repeated in 2014. Both markets are also seasonally counter-cyclical with thenorthern hemisphere, offering additional seasonal arbitration opportunities.
Figure 58: Evolution of Brazil and Argentina’s natural gas imports

Source: (MME, 2014)

There are no signs that Brazil will abandon its policy of ‘run of the river” power plants, which means
the need for thermal power back-up will increase. Dry seasons are now a constant feature of Brazilian
life, as is the government imperative of not letting the lights go out at any cost. This year the World
Cup and presidential elections take place; in 2016 it will be the Olympic Games followed by themunicipal elections. All these events encourage the adoption of short-term and expensive palliatives.
Petrobras is well positioned to provide short-term thermal power back-up because it has a large gas
portfolio, the physical and commercial import capability and a sizeable gas-fired power generation
capacity installed near the main demand centres. There is little incentive for other players to enter themarket; as a result, Petrobras will continue to dominate the market in the short term, except for an
independent and integrated domestic gas-cum-power project in the northern state of Maranhao66.
Next year, when electricity prices are to be adjusted, consumers will have to pay a hefty bill – one that
could be as high as $23 bn67.
A well thought-out gas policy encouraging long-term and lasting solutions and fostering competition in
the supply of natural gas could help the country save $1–2 bn annually. Such savings are to be madeprincipally by lowering LNG and gas supply costs. Alternative solutions will become available only infive to 10 years: neither long-term purchase from the US nor new domestic production will materialize
before 2020.

66
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Owned by a consortium formed by ENEVA and E.ON.
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In the meantime, Brazil’s natural gas market will be impacted by structural issues such as: Nearly stagnant industrial-sector consumption owing to price-competitiveness issues (mostfuel oil demand is already being met by natural gas, which is too expensive to replace otherfuels such as wood, coal and biomass);
 Slow demand growth in the automotive sector owing to consumer concerns about security ofsupply and the lack of factory-designed NGVs;
 No significant growth in the residential and commercial sectors owing to nascent distribution
infrastructure in most states and low levels of household consumption;
 Unreliable demand from the power sector, which varies enormously from year to year andeven from month to month; The lack of integrated government planning allowing for the development of infrastructure andthe sharing of regulatory best practices; The lack of competition on the supply side and the monopoly in pipeline infrastructure are
hurdles for the development of competitive supplies.
The implications are clear: Brazil will not become a gas exporter before 2025 as there will be no exportable surplus ofdomestic gas. Continued imports of LNG will be the norm.
 Despite a substantial increase in domestic gas supplies, which will nearly double by 2020,
Brazil will continue to depend on Bolivian gas to meet part of its inflexible gas demand:
industries, residential/commercial and inflexible power plants.
 From 2018 onwards the inflexible demand for natural gas could be met by an increase indomestic production and by importing just 50% of the volume currently being imported from
Bolivia.
 If Brazil doubles domestic supplies by 2020 and renews its contract with Bolivia under the
existing terms and conditions (11 Bcma, ToP 80%), the flexible market might be unable toabsorb all these volumes under strict ToP conditions.
 On the other hand, if Bolivian gas supplies are halved, the flexible power market will need 10
to 13 Bcma of LNG by 2018–20.
 There are serious doubts as to whether Bolivia can continue to meet its supply obligations toboth Brazil and Argentina as disinvestment in E&P and increasing export volumes are quickly
depleting the gas reserves of the two countries.
 If the Electricity System Operator is willing to remain highly flexible over the dispatch of gasfired power plants, Brazil will need to rely on flexible (spot) and more expensive imports of
LNG.
 The volatility of demand in the power sector indicates the need for Brazil to develop
underground storage projects. This will require an adequate regulatory framework, including
on the pass-through of costs to power tariffs.
 As the gatekeeper of all gas import projects, Petrobras will continue to play a key role in alllarge gas transactions as well as being the dominant player in the production of gas andthermal power.
 After 2020 some domestic producers may help in the diversification of domestic supply bydeveloping local projects aimed at supplying LDCs and large ‘free consumers’.
 At current LNG spot prices into Brazil – around $14.2/MMBtu FOB – Brazil’s total LNG bill willreach $3.1 bn by 2018 and $4.5 bn by 2020.
Both Petrobras and electricity and gas consumers would benefit enormously if the government
embarked on drawing up a serious and effective policy for natural gas.
It is important to note that for its part, Petrobras would pay a much lower price for LNG if it enteredinto long-term contracts to purchase such gas directly from brown-field liquefaction projects being
developed in the US. Take the example of GAIL of India, whose credit ratings are similar to those ofPetrobras: GAIL purchased 3.5 mtpa from Sabine Pass under a cost-plus formula that exposes the60buyer to HH price volatility but whose gains remain significant as long as HH does not exceed $8–
9/MMBtu. In order for Brazilian companies to be able to follow suit, the energy authorities in Brazil
need to change the power auction rules so that natural gas and LNG projects can compete effectively.
A second and no less important point is the need for Brazil to develop sound policies to promote thedevelopment of domestic gas – both conventional and unconventional – and to encourage existingproducers to sell their gas to the market. This would require a full package of initiatives, including:









Enhancing the terms of the fiscal regime by reducing taxes and duties as well as minimising
the working programme burden in the exploration licenses , scrapping the payment ofsignature bonuses and reducing local content requirements for gas blocks, particularly thoselocated in areas with no infrastructure;
Improving cooperation between the energy sector and the various environmental agencies inorder to speed up the permitting of gas blocks, power plants and pipelines;
Providing bonuses and other incentives for early gas production;
Mapping potential gas-bearing areas and assessing transportation infrastructure
requirements;
Simplifying the rules to allow the development of gas from wellhead to power and industrial
projects;
Promoting the transfer of technology for the exploration and development of unconventional
gas;
Creating real competition on the supply side (that is, encouraging gas producers to offer theirgas to the market through independent gas tenders, arrange the financing of enabling
infrastructure and the effective unbundling of marketing and transportation/distribution
activities).

61

Glossary
AES
ANEEL
ANP
Bcma
Bbl/d
BG
bn

AES CorporationAgência Nacional de Energia EletricaAgência Nacional de Petroleo, Gas Natural e Biocombustiveis
Billion cubic metres per annum
Barrels of liquid per day
BG Group
Billion

BOE
CAGR
CEG
CIDE
CNPC
CNPE
Cogen
Comgas
DES
DOE
EIA
E&P
EPC
EPE
FEED
FLNG
FOB
FSRU
GALP
GCA
GIIGNL
GSA
GW
GWh
HFSO
IBP
IGU
IOC

Barrel of oil equivalent
Compounded Average Growth Rate
Companhia de Gas do Rio de Janeiro
Contribuição de Intervenção no Dominio Econômico
China National Petroleum Corporation
Conselho Nacional de Politica Energetica
Cogeneration
Companhia de Gas de Sao Paulo
Delivered Ex-ship
US State Department of Energy
Energy Information Administration
Exploration and production
Engineering, procurement and construction
Empresa de Planejamento Energetico
Front end engineering
Floating liquefaction unit
Freight on board
Floating storage and regasification unit
GALP Energy Group
Gaffney, Cline & Associates
Group of Liquefied Natural Gas Importers
Gas supply agreement
Gigawatt
Gigawatt hour
High Sulphur Fuel Oil
Instituto Brasileiro de Petroleo, Gas Natural e Biocombustiveis
International Gas Union
International oil company

IPT
K
KW
KWh
LDC
LFSO
LNG

Instituto de Pesquisas Tecnologicas do Estado de Sao Paulothousand
Kilowatt
Kilowatt hours
Local distribution company
Low Sulphur Fuel Oil
Liquefied Natural Gas

62

LPG

Liquefied petroleum gas

m3 /d
MM
MMBtu
MME

Cubic metre per day
MillionMillion British thermal units
Ministry of Mines and Energy

Mtoe
MOU
mtpa
MW

Million tonnes of oil equivalent
Memorandum of Understanding
Million tonnes per annum
Megawatt

MWh
NBP
NGV
NOC
ONIP
ONS
PEMAT
Petrobras
PL
PSC

Megawatt hour
National Balancing Point (UK)Natural Gas Vehicles
National Oil Company
Organizacao Nacional da Industria do Petroleo
Operador Nacional do Sistema Eletrico
Plano Decenal de Expansão da Malha de Transporte
Dutoviário
Petróleo Brasileiro S.A.
Pipelines
Production-sharing contract

PPT
R/P
SPA
TBG
Tcf
ToP

Emergency Thermal Power Programme
Reserves/Production ratio
Supply and Purchase Agreement
Transportationadora Brasileira Gasoduto Bolivia-Brazil S.A.
Trillion cubic feet
Take or pay

T&T
TWh
YPFB

Trinidad and Tobago
Terawatt hour
Yacimientos Petroliferos Fiscales Bolivianos

63

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65

Company and News Websites
1.
2.
3.
4.
5.
6.
7.
8.
9.

Mejillones LNG: http://www.gnlm.cl/sitio/
Golar LNG: http://www.golarlng.com/
Platts: http://www.platts.com/videos/2014/march/lng-brazil-imports
Quintero LNG: http://www.gnlquintero.com/
ENEVA: http://www.eneva.com.br/en/who-we-are/Paginas/corporate-structure.aspx
ANP: http://www.anp.gov.br/
ABEGAS: http://www.abegas.org.br/Site/
ONS: http://www.ons.org.br/home/
Tribuna da Bahia: http://www.tribunadabahia.com.br/2014/01/27/petrobras-inicia-operacaona-bahia-de-terminal-de-regaseificacao-de-gnl
10. EXAME http://exame.abril.com.br/mercados/noticias/petrobras-explica-contrato-cessaoonerosa-593560
11. Petrobras: http://www.petrobras.com.br/pt/
12. Shell: http://www.shell.com/
13. GIIGNL: http://www.giignl.org/
14. EPE: http://www.epe.gov.br/
15. YPFB: http://www.ypfb.gob.bo/

66