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The journey of US light tight oil production towards a financially sustainable business

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The financing model underpinning the US shale oil industry is fundamentally different from that of large companies producing predominantly in conventional oil. Small and medium-size independent producers, which dominate the US shale industry, generally have much higher leverage with high levels of debt and hedging.  Since its inception, the industry has been characterised by negative free cash flow as expectations of rising production and cost improvements led to continuous overspending in the sector. Over the last few months, the industry as a whole has seen a notable improvement in financial conditions, though the picture varies markedly by company, and the overall health of the industry remains fragile.

In order to try to assess as precisely as possible the developments of shale industry throughout the decade, we identified four distinct phases that have characterised the shale industry since 2010 up to now.

2010-14: The start-up phase

In the 2010-14 period, technology developments and high and stable oil prices triggered a massive investment wave in the US shale sector. Investment more than quadrupled, leading to an eightfold increase in shale oil production, from 0.44 million barrels per day (mb/d) to over 3.6 mb/d – the fastest growth in oil production in a single country since the development of Saudi Arabia’s super-giant oilfields in the 1960s.

However, the growth came with a huge bill. The sector as a whole generated cumulative negative free cash flow of over USD 200 billion over those five years. Throughout this phase, companies were forced to rely extensively on external sources of financing, predominantly debt and receipts from the sale of non-core assets, in order to finance their operations. In addition to issuing bonds, companies benefited from the reserve base lending structure – a bank-syndicated revolving credit facility secured by the companies’ oil and gas reserves as collateral. This structure was used heavily by small and medium-sized companies with non-investment credit rating that did not have as easy access to the corporate bond market.

2015‑16: The survival phase

The collapse of prices in the second half of 2014 and throughout 2015 and early 2016 had a major impact on the way the shale industry operates. Companies switched to survival mode, focusing on improving efficiency and cutting costs. The number of firms declaring bankruptcy and filling for Chapter 11 protection, a form of bankruptcy involving reorganisation, skyrocketed to almost 100 in 2015-16.

The fall in prices also changed the way the shale industry was financed. Debt finance dried up as banks were unwilling to lend during a period of market turmoil, with bond yield spreads widening to over 1 000 basis points and the credit rating of the majority of companies being downgraded. Asset sales also dropped by 70% in 2015 as owners were unwilling to part with assets at the much lower prices on offer. While the main buyers of the assets were US independent companies, the market turmoil discouraged bank lending, opening up opportunities for financial firms such as private equity firms, which typically have a higher risk profile. Those firms accounted for around 30% of reported asset deals over 2015-16. Available funding from the reserve base lending structure also declined as the value of proved reserves for collateral shrank with lower oil prices. The net result was that companies were obliged to raise equity to finance their operations – a more expensive option.

Despite the slump in revenues throughout this period, the shale industry actually saw an improvement in free cash flow as a result of huge cuts in capital spending and costs. Between 2014 and 2016, investment fell by 70% and costs by around half. Cost reductions helped to offset the impact of less investment, such that shale oil production declined only modestly in 2016.

2017: The consolidation phase

The recovery of oil prices since mid-2016 following the collective decision by the Organization of the Petroleum Exporting Countries (OPEC) and some non-OPEC producers to cut output led to a revival in confidence in the US shale sector. Further advances in technology, huge efficiency gains and cost reductions, and an upward revision of the shale resource base triggered an increase of 60% in investment in 2017. In the meantime, the shale industry proved that its upstream cost structure had been rebased as it was able to offset inflationary pressures coming from overheating of the supply chain, further reducing the overall costs per barrel produced.

Despite the improvements achieved, however, the shale sector continued to slightly over-spend the cash flow generated from its operations, with 2017 cumulative free cash flow remaining overall negative. Asset sales once again became the main source of financing operations, with most transactions occurring between US independent companies. Asset sales involved mainly acreage rather than whole companies, as companies sought to do relatively small deals as a way of making gains in operational efficiency. The confidence in the shale sector, traditionally dominated by private investors and small and medium-sized companies, received a boost from announcements by large US oil companies of their intention to make substantial investments.

2018: Profitability at last?

Current trends suggest that the shale industry as a whole may finally turn a profit in 2018, although downside risks remain. Thanks to a 60% increase in investment in 2017 and, based on company plans, an estimated 20% increase in 2018, production is projected to grow by a record 1.3 mb/d to over 5.7 mb/d this year. Several companies expect positive free cash flow based on an assumed oil price well below the levels seen so far in 2018 and there are clear indications that bond markets and banks are taking a more positive attitude to the sector, following encouraging financial results for the first quarter. On this basis, this we estimate that the shale sector as a whole is on track to achieve, for the first time in its history, positive free cash flow in 2018. This result is all the more impressive given the context of rising investment.

Structural changes also augur well for the sector. Recent consolidation, such as the recent USD 9.5 billion Concho-RSP Permian merger, and the increased participation of the majors and other international companies could bring significant economies of scale and accelerate technology developments, including through digitalization. Larger companies generally have a more robust financial structure and rely less on external sources of financing, so their shale investment will be less vulnerable to future downswings in oil prices and financial conditions.

The potential risks for shale independent from rising interest rates are currently attracting a lot of attention. The impact of rising interest rates on independent oil and gas companies in the US shale industry may also be small. Most companies are highly leveraged, benefiting from the ample availability of low-cost bond finance. However, given the high depletion rate, the time horizon of shale projects is so low that the discount rate has only a minor impact on the net present value of a given project. Rising interest rates often coincide with tighter lending conditions, which may make it harder for companies to service their debts and refinance their operations. But this risk can be managed through asset sales to less-capital-constrained companies, such as the majors, and increased reliance on equity raising through IPOs and private equity.

A lot of attention has been focused on interest expenses – the cost of repaying debt. The development of shale production has been accompanied by constantly rising interest expenses, which has impeded companies from generating profits sustainably. For the first time, the overall amount of interest expenses paid by shale companies declined in 2017. While US shale companies remain far more leveraged (measured by the net debt/equity ratio) than traditional operators, leverage is falling from its peak in 2015 and the average interest rate paid by shale companies – currently around 6% – has been broadly stable in recent years despite rising interest rates generally since the end of 2015, though they still pay more than conventional oil producers. Improving financial conditions mean that shale companies are able to borrow more cheaply than before.

The US shale industry seems to have reached a turning point with the recent significant improvement in its financial sustainability. But major uncertainties and important downside risks to the future of the shale industry remain:

Above-ground constraints: With production rising very rapidly in certain basins, such as the Permian, timely investment in takeaway capacity and pipeline infrastructure will be vital to the further expansion of the industry. At present, several producers in the Permian Basin are forced to discount their crude oil by more than USD 15 per barrel compared with the price on the Gulf Coast due to a lack of pipeline capacity. No significant pipeline capacity expansion is expected before 2019. The importance of infrastructure applies not only to oil but also to associated gas production, wastewater and other products. In the absence of new pipeline capacity, companies might be forced to curb drilling or ship their production using trucks or rail, which are usually much more expensive.

Further productivity gains: The continued ability of the companies to offset inflationary pressures with improved productivity stemming from technology or improved project execution remains very uncertain. In most active basins, especially the Permian, there are clear signs of overheating and bottlenecks in skilled labour, materials and equipment. In addition to the potential for further technological advances, there may be scope for more efficiency gains, for instance by expanding operations in continuous acreages, improved understanding of the resource base and more accurate spacing of wells.

Grabbing the fruits of the “digital revolution”: Companies are putting more effort into developing and adopting innovative digital technologies and big-data analytics in order to reduce costs, by optimising operations, improving reservoir modelling and enhancing processes.

Competition from other sources of oil: The US shale sector has not been alone in reducing its costs and will need to continue to do so to remain competitive in international markets. Most onshore resources, especially in OPEC countries, cost less to produce than shale oil, while the bulk of new deepwater projects are competitive with the cheapest shale basins. Consequently, the US shale industry is required to keep improving.

This analysis was written by IEA Senior Programme Officer Alessandro Blasi and IEA Energy Investment Analyst Yoko Nobuoka, and was adapted from World Energy Investment 2018. Source: IEA

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Italy’s and EU’s natural gas imports from the United States

Giancarlo Elia Valori

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Currently natural gas is one of the most important US assets in its relations with the European Union.

In fact, President Trump and President Jean Claude Juncker spoke at length about it during their last meeting at the White House at the end of July 2018.

Obviously the issue of the US natural gas sales is linked to a broader strategic theme for President Trump.

He wants to redesign – especially with the EU – the system of tariffs and rebalance world trade.

He also wants to recreate a commercial and economic hegemony between the United States and the EU – a hegemony that had tarnished over the last decade.

With the EU, the United States has already achieved a zero-tariff regime for most of the goods traded, also removing non-tariff barriers and all the subsidies to non-automotive goods.

Moreover, since late July last, both sides have decided to increase inter-Atlantic trade in services, chemicals, pharmaceuticals, medical products and – as a central issue in their relations with China – soybeans.

What China no longer buys – since it has been burdened with tariffs and duties – is resold to the European Union.

In fact, soy was bought massively by European consumers, as Jean Claude Juncker later added.

The demand for natural gas, however, is on the rise all over the world.

Currently Europe is in difficulty for this specific energy sector, considering that the large gas extraction field in Groningen, Netherlands, suffered an earthquake at the beginning of January 2018.

The Dutch extraction area, however, is managed jointly by both Royal Dutch Shell and Exxon-Mobil.

The North American analysts think that, for the whole EU, the other natural gas sources are at their peak of exploitation.

Gas sources such as Russia, Turkey, Central Asia and the Maghreb region are supposed to be soon saturated as a result of the growth in EU gas consumption and, therefore, the United States is thinking to sell much of its LNG to Europe as well.

With an obvious strategic and geopolitical pendant.

This holds particularly true – at least for the time being – for the Algerian gas, while the United States is currently pressing for a diversification from the Russian pipelines, offering its liquefied natural gas (LNG) for ships to   Northern Europe’s terminals and, recently, also to the Italian ones.

Across the European Union, the natural gas terminals are 28, including Turkey.

There are also eight other small natural gas terminals in Finland, Sweden, Germany, Norway and Gibraltar.

Said terminals are 23 in the EU and 4 in Turkey; 23 are land-based and 4 are at sea for storage and regasification, and the Malta terminal includes both a ground base and a maritime unit.

Italy, one of the largest LNG consumers in Europe, produces a good share of natural gas internally, but it still imports 90% of the gas it consumes, while 60% of Italy’s LNG consumption is divided almost equally between two suppliers, Algeria and the Russian Federation.

By way of comparison, France extracts domestically only 1% of the natural gas it consumes every year.

Also Germany, like Italy, imports much gas from Russia – about 50% of its yearly consumption.

From where, however, does Italy import its natural gas? From Russia, as already seen, as well as from Algeria, Libya, Holland and Norway.

Then there is the Trans Austria Gas (TAG), a network which, again from Russia, brings gas to the Slovakian-Austrian border (precisely to Baumgarten an der March up to Arnoldstein in Southern Austria) with a maximum capacity of 107 million cubic meters per day.

There is also Transitgas, crossing Wallbach, Switzerland, up to Passo Gries, where it intersects with the SNAM network.

It is also connected to Gaz de France and has a maximum capacity of 59 million cubic meters per day.

A significant role is also played by the Trans Tunisian Pipeline Company (TTPC), a network with a capacity of 108 million cubic meters per day, stretching from Oued al Saf, between Tunisia and Algeria, to Cape Bon, where it connects with the Trans-Mediterranean Pipeline Company (TMPC). The network reaches Mazara del Vallo, where it enters the SNAM system.

The security of this line was a factor considered in the decision taken by the Italian intelligence services to participate actively in the struggle for succession in Tunisia, after Habib Bourghiba’s political end.

The Greenstream pipeline connects Libya to Italy, with a maximum capacity of 46.7 million cubic meters per day, with regasifiers located in Panigaglia and off Leghorn’s coast (OLT), as well as off Rovigo’s coast.

It should be recalled that, in July 2018, ENI opened production in the offshore plant of Bar Essalam, a site 120 kilometres off Tripoli’s coast, which could contain 260 billion cubic meters of gas, while the French company Total paid 450 million dollars to buy – from the United States -16% of the oil concession in Waha, Libya.

As is well known, the TAP is under construction.

With a maximum capacity of 24.6 million cubic meters per day, it stretches from Greece to Italy through Albania.

There is also the IGI Poseidon, again between Greece and Italy, as well as the regasification terminal of Porto Empedocle, and the other terminals of Gioia Tauro and Falconara Marittima.

Shortly the pipelines from Algeria to Sardinia could be operational, with a terminal in Piombino, as well as the one in Zaule, and the regasification plant in Monfalcone.

Hence if all these networks are already operational or will be so in the near future, Italy alone could shift the axis of the natural gas transport from the North (namely Great Britain and Holland) to the South (namely Italy and Greece).

If this operation is successful, Italy could become the future natural gas energy hub, thus making it turn from a mere consumer to an exporter of natural gas.

In 2020, SNAM plans to bring 4.5 billion cubic meters of gas from the Trans-Adriatic Pipeline, which transports Azerbaijan’s LNG, jointly with BP.

This is a further phase of reduction of the EU dependence on Russian gas.

But also the purchase of LNG from the United States could undermine the Italian plan of becoming the European natural gas hub, as against the Dutch-British system.

Obviously the liquefied natural gas is sold by the United States mainly as an operation against Russia.

Currently, the American LNG has prices that are approximately 50% lower than the Russian gas prices.

As pointed out by one of the major Italian energy experts, Davide tabarelli, the price is 8 euros per megawatt / hour as against 22 euros of the LNG coming from Russia.

For the time being, however, China is the world’s top LNG buyer, with a 40% increase in its consumption.

Nevertheless, while China’s gas consumption is booming, the ships carrying natural gas from the United States tend to go right to Asia, where, inter alia, a much higher price than the European average can be charged.

In the EU, however, the Russian gas can be bought at 3.5-4 dollars per Mega British Thermal Unit (MBtu) while the break-even price of the US gas, which is much more expensive to produce, is around 6-7.5 MBtu, including transport.

Competition, however, is still fierce, given that the EU regasifiers are used at 27% of their potential, and considering Qatar’s harsh competition with the United States. It is worth recalling that Qatar is a large producer of natural gas with the South Pars II field, in connection with Iran.

In the near future, the small Emirate plans to sell at least 100 million tons of LNG per year, opposed only by Saudi Arabia’s reaction. According to the usual rating agencies, at banking level Qatar is also expected to suffer the pressure of Saudi Arabia and its allies, including the United States.

Nevertheless, if the cost of the trans-Atlantic transport and the cost of regasification in our terminals are added to the 8 euros about which Tabarelli speaks, we can see that the US gas and the Russian LNG prices tend to become the same.

Russia has also much lower gas production costs than the United States, considering that most of the North American LNG is extracted with shale or fracking technologies, which are much more expensive than the Russian ones.

It should be recalled that in 2017 the Russian Federation was the world’s top natural gas exporter, with a record peak of 190 billion cubic meters, accounting for 40% of all EU consumption.

Moreover, thanks to fracking technologies, the United States has become the world’s largest crude oil producer, but also the largest consumer globally. Hence no additional room for its exports of non-gas hydrocarbons can be easily envisaged.

Certainly buying American gas would mean avoiding the US import tariffs for European cars in the future, which would lead many EU governments to willingly accept President Trump’s offer.

Furthermore, ENI is finding much oil and much natural gas in Egypt, which could lead to the building of a pipeline from the Egyptian coast to which also the Israeli natural gas could join.

This implies a significant weakening of both the Egyptian domestic crisis and the tensions between the “moderate” Arab world and the Jewish State.

In fact, in the concession of Obayed East, Egypt, ENI has found a natural gas reserve of 25 million cubic meters per day which, together with the recent discoveries of the Zohr, Norus and Atol deposits, is expected to make Egypt achieve energy autonomy and independence before early winter 2018-2019.

This, too, could be one of President Trump’s geo-energy goal, along with Israel’s expansion on this market. In all likelihood, however, Russia will remain one of the largest or still the largest LNG seller to the whole EU.

However, let us better analyse the situation: with the South Pars II field it shares with Qatar, also Iran could provide the EU with a large part of its yearly natural gas requirements.

Iran is a Russian ally although, in this case, strategic friendships are always less sound than economic interests.

Furthermore, the war in Syria resulted – and probably this is also one of its underlying causes – in a block of future Iranian pipelines to the Mediterranean.

Moreover, China has bought the shareholdings held by the French Total on the Iranian territory.

For the time being, however, the United States sells much of its LNG to Asia and Latin America, where currently prices are still higher than in Europe.

Hence, like all consumer countries, the EU is interested in diversifying its energy suppliers. Nevertheless, the war in Syria has blocked Iran and the war in Libya has made the Greenstream pipeline, which is essential for Italy, unusable.

It should be recalled that Greenstream is the 520-kilometre pipeline connecting Libya to Italy directly.

Almost all the Libyan gas, however, is currently consumed inside the country.

Moreover, at this stage, President Trump would like Germany to stop even the doubling of Nord Stream 2 from the Russian coast to the German Baltic Sea.

The Ukrainian leadership is also urging the EU to avoid doubling this project, considering the forthcoming expiry of the Ukrainian contracts for the Russian natural gas.

If this happens, as from 2022 Poland will buy a large share of its natural gas from the United States, thus avoiding the Russian LNG.

Nevertheless, the United States will also favour the Southern Gas Corridor in Azerbaijan and Turkey, with a view to transferring the Caspian natural gas to the EU through Apulia.

Hence Italy would be disadvantaged: instead of using its lines and routes with Libya and Algeria, or Russia, it should buy the Caucasian gas, which will be fully managed by US companies – and this holds true also for the US natural gas direct sales, which have recently started in some Italian ports.

A dangerous political calculation, as well as a risky commercial evaluation.

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Oil Market Report: Twin Peaks

MD Staff

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Both global oil demand and supply are now close to new, historically significant peaks at 100 mb/d, and neither show signs of ceasing to grow any time soon. Fifteen years ago, forecasts of peak supply were all the rage, with production from non-OPEC countries supposed to have started declining by now. In fact, production has surged, led by the US shale revolution, and supported by big increases in Brazil, Canada and elsewhere. In future, a lot of potential supply could come to the market from places like Iran, Iraq, Libya, Nigeria and Venezuela, if their various challenges can be overcome. There is no peak in sight for demand either. The drivers of demand remain very powerful, with petrochemicals being a major factor. In a new IEA study “The Future of Petrochemicals”, the Agency points out that rising living standards, particularly in developing countries, are already underpinning strong demand growth for plastics and this will continue for many years to come.

As the oil market reaches the landmark 100 mb/d level, prices are rising steadily. Brent crude oil is now established above $80/bbl, with infrastructure constraints causing North American prices to lag somewhat. Nonetheless, our position is that expensive energy is back, with oil, gas and coal trading at multi-year highs, and it poses a threat to economic growth. For many developing countries, higher international prices coincide with currencies depreciating against the US dollar, so the threat of economic damage is more acute. The global economy is also at risk from trade disputes. In this Report, our revised demand outlook reflects these concerns: growth in both 2018 and 2019 will be 110 kb/d lower than our earlier forecast. As explained in the demand section of this Report, there is also an impact from methodological changes to Chinese estimates.

Today’s elevated oil prices partly reflect very high crude runs 100 during recent months and also supply fears as sanctions against Iran draw near. In fact, since May, when the US announced its withdrawal from the JCPOA and its decision to impose sanctions, the Vienna Agreement parties, plus Libya and Nigeria but excluding Iran, Mexico and Venezuela, have increased total oil production by a combined 1.6 mb/d. At the same time, total US supply has increased by 390 kb/d. Even China has seen the first year-on-year production growth in nearly three years in response to higher prices. Official statements from Saudi Arabia suggest that October exports are back to the high levels seen in June and that more oil is available for those who wish to buy it. Meanwhile, output in Iran, Mexico, and Venezuela has fallen by 575 kb/d. New data for OECD stocks show that in August they increased by a more- than-normal 16 mb and have been relatively stable for several months after falling significantly following the implementation of the original Vienna Agreement.

The increase in net production from key suppliers since May of approximately 1.4 mb/d, led by Saudi Arabia, and the fact that oil stocks built by 0.5 mb/d in 2Q18 and look likely to have done the same in 3Q18, lends weight to the argument that the oil market is adequately supplied for now. The IEA welcomes this boost to supply; however, with Iran’s exports likely to fall by significantly more than the 800 kb/d seen so far, and the ever-present threat of supply disruptions in Libya and a collapse in Venezuela, we cannot be complacent and the market is clearly signalling its concerns that more supply might be needed.

It is an extraordinary achievement for the global oil industry to meet the needs of a 100 mb/d market, but today, in 4Q18, we have reached new twin peaks for demand and supply by straining parts of the system to the limit. Recent production increases come at the expense of spare capacity, which is already down to only 2% of global demand, with further reductions likely to come. This strain could be with us for some time and it will likely be accompanied by higher prices, however much we regret them and their potential negative impact on the global economy.

IEA

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The Force of the Sun: Madagascar Embarks on Renewable Energy Production

MD Staff

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“JIRAMA: until when?”  “JIRAMA: it’s been 2 hours!” “JIRAMA: you’re destroying our equipment!” It is 11 a.m. Numerous complaints against the national water and electricity company, JIRAMA, are posted on social media by Internet users. The electricity supply has been cut in several neighborhoods in Antananarivo. Cue the familiar sounds of power generators in offices and a number of stores. The scene is nothing new. Over the past decade, JIRAMA’s customers, both household and industrial alike, have experienced repeated power outages.

A Crucial Resource for Economic and Social Development

In Madagascar, only 15% of the population has access to electricity. In 2017, the country had just 570 MW of mainly thermal (60%) and hydroelectric (40%) installed production capacity. Furthermore, only 60% of this energy is truly available owing to poor maintenance of power plants. Apart from the fact that these challenges in the energy sector undermine the quality of citizens’ daily lives, they also represent one of the major obstacles to the country’s development and to private sector expansion. In the World Bank Group’s Doing Business 2018 report that assesses the business climate, Madagascar ranks 184 out of 190 countries for access to electricity.

Keenly aware of this challenge, in 2014, the Government of Madagascar decided to embark on intensive reforms to transform the sector. In March 2016, the country was granted $65 million in financial support from the World Bank through the  Electricity Sector Operations and Governance Improvement Project (ESOGIP) and in June 2018, $40 million in additional financing. The objective: increase production capacity and reduce energy loss, while helping the Government improve governance of the sector and JIRAMA’s operational performance. The ESOGIP also aims to expedite progress on renewable energies in order to provide a reliable, more affordable alternative to expensive and environmentally unfriendly diesel generators.

Betting on Solar Energy

With all regions of Madagascar enjoying over 2,800 hours of sunlight per year, the Grande Île is the perfect location for development of solar power, with a potential capacity of 2,000 kWh/m²/year. The Government is counting on this potential to fulfill its objective of providing energy access to 70% of Malagasy households by 2030.

“Our energy policy for 2015-2030 addresses several pressing economic, social, and environmental challenges. It supports the transition to the energy mix for electricity and lighting, which will include 80% of renewable resources. To achieve our goal of providing electricity to 70% of the population, we will have to produce 7,900 GWh by 2030, as opposed to the 1,500 GWh currently produced,” explains Lantoniaina Rasoloelison, Minister of Energy and Hydrocarbons.

An ambitious project, particularly if it is entirely dependent on public financing.

An Innovative Financing Mechanism to Support the State

To supplement public funds in order to finance large-scale construction of solar plants by promoting private investment, the International Finance Corporation (IFC), the private sector arm of the World Bank Group, is helping the Government set up a public-private partnership (PPP).

Through the Scaling Solar initiative, in March 2016, IFC signed an agreement with the Malagasy Government to construct a plant of approximately 25 MW, connected to the Antananarivo network, through a transparent international competitive bidding process.

Madagascar is currently the fifth country in Africa in which a Scaling Solar tender process was launched, after two tender processes in Zambia, one in Senegal, and another in Ethiopia. It is also the first Scaling Solar project to include solar energy storage requirements by pairing solar with batteries.

The process began with feasibility studies conducted by IFC experts to determine the solar capacity that could be added to the existing network and to select a suitable location.

In October 2017, the Government of Madagascar invited private investors to participate in a prequalification process, based on strict eligibility criteria, to select potential candidates with the necessary experience, expertise, and financial resources to complete the project as expeditiously as possible.

Expertise of the Various World Bank Group Institutions

Over 100 companies from 28 countries expressed their interest. In February 2018, six companies and groups were selected to participate in the tender process and will be able to make use of the feasibility studies provided by IFC to prepare their technical bids and identify financial partners.  This last step will also be facilitated by the investment guarantees and credit enhancement tools provided by the World Bank and the Multilateral Investment Guarantee Agency (MIGA), which offers a number of protections, particularly against non-commercial risks (political, expropriation disputes, etc.).

“Scaling Solar Madagascar aims to propose an integrated solution that includes financing and the implementation of technical solutions in which the operating company chosen will benefit from coverage against political and financial risks, offered by the World Bank,” explains Satyam Ramnauth, IFC Country Manager for Madagascar. “This project will also set the operating standards that will serve as a reference for legitimate operators, as well as for the Government with respect to the implementation of its energy policy.”

World Bank

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