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Brazil's gas prospects fade as import dependence continues

Facing an increasingly costly import dependence its time the country re-thinks its strategy

When Petrobras discovered billions of barrels of oil and gas in pre-salt fields off Brazil's coast last decade, it promised to deliver the country energy independence. Brazil was, it seemed, on a path to become not only a major oil player, but also a significant natural gas exporter, reversing years of import dependence. In 2009, Petrobras was confident enough about its gas prospects that it commissioned a study to build the world's first floating liquefied natural gas (FLNG) export terminal. 

But those hopes have long since faded, and Brazil's costly natural gas import dependence is likely to last for at least another decade, argues Ieda Gomes in a new Oxford Institute for Energy Studies report. Gomes, who spent years working in the Brazilian gas sector, expects the country to continue require gas imports of around 15 billion cubic metres a year (cm/y) through at least 2025 to meet demand, with supplies coming from the international liquefied natural gas (LNG) market and via pipeline from Bolivia.  

The outlook is more pessimistic than earlier predictions. In its latest World Energy Outlook, the International Energy Agency forecast Brazil narrowing its gas deficit to just 1bn cm/y by 2025. Since then, though, Petrobras has slashed its gas production forecast as its oil projects continue to suck in a greater share of its investment.

The import dependence is not for a lack of potential gas supply. Gas discovered alongside the major pre-salt oil discoveries have seen the country's proven reserves nearly double over the past decade, from 241bn cubic metres (cm) in 2003 to 451bn cm. That is enough to meet around 12 years of demand at current consumption rates. 

Brazil is also thought to have some of the largest shale gas deposits in South America, behind just Argentina. The US Energy Information Administration says the country could hold around 7 trillion cm of recoverable shale resources, placing it 10th in the world. The government's own studies have indicated the total could be twice as large when all of the country's gas basins are taken into account.

Developing the country's gas reserves, though, has not been a priority for Petrobras, which has found its hands more than full with the task of bringing the pre-salt oil discoveries on stream. Gas and downstream energy investment accounts for just 5% of the company's $220bn 2014-2018 business plan.

Brazil's gas business, Gomes points out, should be an attractive one to other domestic and foreign companies looking to fill the gas left by Petrobras. Brazilians pay some of the highest natural gas prices in the world. Major industrial customers typically pay at least $16 per million British thermal units (Btu) while residential consumers pay as much as $50/m Btu. Prices at the wellhead rang from $8/m Btu to $12/m Btu. But the government has not made the reforms needed to pave the way for others to step into the market. Petrobras dominates domestic supply, operates nearly all of the country's gas-fired power plants and holds a quasi-monopoly over the gas transport infrastructure. Petrobras has protected this privileged position, leaving smaller gas producers with few options other than selling to Petrobras at the wellhead. 

A project launched late last year by OGX, now know as OGPar, in the state of Maranho is the only integrated gas-to-power project in Brazil that does not involve Petrobras.

The nature of Brazil's gas demand also makes it difficult for smaller producers to crack the market. In the power sector gas demand can be erratic and unpredictable because it is typically used to plug the gap when hydropower drops off in the dry season, making it difficult for producers to secure long-term contracts.   

In many other ways, Gomes writes, Brazil's gas sector remains underdeveloped, even though natural gas has been sold in the country as far back as 1851. Less than 4% of Brazilian households are hooked up to the national gas grid. Natural gas-fuelled vehicles are on the rise, but still account for just a fraction of the country's vehicle fleet. Policymakers instead have looked to ethanol to green the transport sector. And Brazil has just 25,000 km of gas pipelines. The US, by contrast, has nearly 500,000 km of pipeline stretching across the country. 

There have been recent moves by Petrobras and the government to open the sector. An onshore-focused licensing round last year saw a number of companies snap up gas-prospective acreage. Still, interest was muted because of the barriers to entering the business and Petrobras dominated the round. 

More recently, Petrobras has signed a preliminary deal with Brazilian independent HRT and Russia's Rosneft to try to develop a gasfield in the Amazon. Petrobras also recently sold its stake in a regional gas distributor, indicating it may be stepping back from its downstream gas operations. 

Still, Petrobras will dominate the industry for years to come and will have to develop a long-term strategy for securing supplies from abroad if it isn't going to be able to increase domestic production fast enough. That, Gomes writes, will mean continuing pipeline imports from Brazil's neighbour Bolivia and continuing to increase LNG purchases.

That is very good news for Bolivia. Brazil and Argentina are Bolivia's sole gas customers, and if it lost one of them it would hit the country's fragile economy hard. Brazil imports around 11bn cm/y from Bolivia under a long-term supply deal, with much of the gas coming from fields Petrobras has helped develop in southern Bolivia. 

As Gomes notes, the countries' gas contracts expire in 2019 and all signs indicate Petrobras will have to sign on for a new deal, for which negotiations will likely have to start soon. Bolivia will be keen to lock Brazil into a deal for as long as possible, though there is considerable doubt as to whether Bolivia will be able to find sufficient reserves to underpin another long-term contract. Gomes reckons Bolivia will have to prove up another 140bn cm of gas reserves to meet its commitments to both Argentina and Brazil. 

Bolivia's national oil company YPFB has announced a major new exploration programme earlier this year to help bolster its reserves. Petrobras and Brazilian policymakers will be keeping a close eye on developments.

Petrobras may also have to re-think its LNG buying strategy. Because of the unpredictable nature of Brazil's gas demand, and hopes of imminent self-sufficiency, Petrobras has been reluctant to sign any long-term LNG supply deals. Instead it has relied on the spot market for LNG cargoes. But that strategy has come at a cost. Brazil competes on the spot market with northeast Asian buyers Japan and South Korea, and as result pays some of the highest LNG prices in the world. Petrobras paid an average of around $17/m Btu for LNG imports last year.

Three straight exceptionally dry seasons, as well as surging power demand associated with hosting the World Cup this summer has added to the burden as Petrobras has been forced to ramp up costly spot LNG purchases. Petrobras has turned primarily to Trinidad and Tobago for its LNG needs, a timely relief for the Caribbean island nation still looking for new markets now that US demand has dried up. Brazil has also gotten supplies from West Africa and Norway. 

Gomes reckons Petrobras should look to sign a long-term supply deal with one of the LNG export projects being built on the US Gulf Coast. Those projects are offering Henry Hub-linked gas prices that would be far cheaper for Petrobras at prevailing prices. By Gomes' sums, opting for a US supply deal over spot LNG purchases would save Petrobras as much as $38bn over the course of a 20-year deal if prices remain at their current levels, with the Henry Hub benchmark at around $5.00/m Btu.

A better deal still would be for the government to put policies in place to encourage the development of Brazil' own resources.

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